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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended DECEMBER 31, 1996
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)
(281) 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 [__].
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 February 28, 1997), was approximately
$345,000,000.
As of February 28, 1997, there were 22,857,294 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to
be held May 6, 1997 are incorporated herein by reference in Items 10, 11, 12,
and 13 of Part III of this report.
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TABLE OF CONTENTS
PART I PAGE
ITEMS 1 AND 2 Business and Properties 2
ITEM 3 Legal Proceedings 15
ITEM 4 Submission of Matters to a Vote of Security Holders 16
Executive Officers of the Registrant 16
PART II
ITEM 5 Market for Registrant's Common Equity and Related
Stockholder Matters 16
ITEM 6 Selected Historical Financial Data 17
ITEM 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
ITEM 8 Financial Statements and Supplementary Data 27
ITEM 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 53
PART III
ITEM 10 Directors and Executive Officers of the Registrant 53
ITEM 11 Executive Compensation 53
ITEM 12 Security Ownership of Certain Beneficial Owners and
Management 53
ITEM 13 Certain Relationships and Related Transactions 53
PART IV
ITEM 14 Exhibits, Financial Statement Schedules and Reports
on Form 8-K 54
------------------------
The statements regarding future financial performance and results and the
other statements which are not historical facts contained in this report are
forward-looking statements. The words "expect," "project," "estimate,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and
marketing activity, future production and costs and other factors detailed
herein and in the Company's other Securities and Exchange Commission filings.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary materially
from those indicated.
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PART I
ITEM 1. BUSINESS
GENERAL
Cabot Oil & Gas Corporation (the "Company") explores for, develops,
produces, 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 and Pennsylvania in
the Western Region, including the Anadarko Basin of southwestern Kansas,
Oklahoma and the Texas Panhandle, the Green River Basin of Wyoming, and South
Texas. At December 31, 1996, the Company had approximately 946.6 Bcfe of total
proved reserves, 97% 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
begun 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. The Company has been publicly traded on the New York Stock
Exchange since its initial public offering.
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, 1996
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)
Total Appalachian Western
Company Region Region(2)
- ----------------------------------------------------------------------------
RESERVES/PRODUCTION:
Proved reserves
Developed (Bcfe) 796.2 436.6 359.6
Undeveloped (Bcfe) 150.4 92.3 58.1
--------- --------- -------
Total (Bcfe) 946.6 528.9 417.7
========= ========= =======
Daily production (Mmcfe) net 170.3 73.5 96.8
Gross productive wells 5,109 3,858 1,251
Net productive wells 4,258.0 3,578.8 679.1
Percent of wells operated 88.2% 97.0% 60.8%
ACREAGE:
Net acreage
Developed acreage 992,151 755,269 236,882
Undeveloped acreage 416,753 258,733 158,020
--------- --------- -------
Total 1,408,904 1,014,002 394,902
========= ========= =======
- ----------
(1) As of December 31, 1996. 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) Includes all properties outside the Appalachian Region, including
properties located in Anadarko, the Rocky Mountains and the Gulf Coast
areas.
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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 60 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 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, Ohio, West Virginia, and
Virginia. Operations are managed by a regional office in Pittsburgh. At
December 31, 1996, the Company had approximately 529 Bcfe of proved reserves
(substantially all natural gas) in the Appalachian Region, constituting 56% of
the Company's total proved reserves.
The Company has 3,858 productive wells (3,578.8 net), of which 3,744
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 1996 was 73.5
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 1996, the Company drilled 123 wells (105.7 net) in the Appalachian
Region, of which 98 were development wells (94.6 net). Capital and exploration
expenditures, including pipeline expenditures for the year were $33.5 million.
In the 1997 drilling program year, the Company has plans to drill 138 wells.
At December 31, 1996, the Company had 1,014,002 net acres in the region,
including 755,269 net developed acres. At year end, the Company had identified
271 proved undeveloped drilling locations.
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, high concentration of
wells, natural gas gathering and pipeline systems and storage capacity.
WESTERN REGION
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. Operations for the Western Region are managed from a regional office in
Denver. At December 31, 1996, the Company had approximately 417.7 Bcfe of
proved reserves (93.1% natural gas) in the Western Region, constituting 44% of
the Company's total proved reserves.
ANADARKO
The Company has 745 productive wells (486.7 net) in the Anadarko area of
which 546 wells are operated by the Company. Principal producing intervals in
Anadarko are in the Chase, Morrow and Chester formations at depths ranging from
1,500 to 11,000 feet. Average net daily production in 1996 was 48.6 Mmcfe.
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In 1996, the Company drilled 41 wells (26.0 net) in Anadarko (39
development wells, 25.3 net). Capital and exploration expenditures for the year
were $13.1 million. In the 1997 drilling program year, the Company has plans to
drill 56 wells.
At December 31, 1996, the Company had approximately 216,278 net acres,
including approximately 184,368 net developed acres. At year end, the Company
had identified 54 proved undeveloped drilling locations.
ROCKY MOUNTAIN
The Company has 318 productive wells (119.7 net) in the Rocky Mountain
area of which 161 wells are operated by the Company. Principal producing
intervals in Rocky Mountain are in the Frontier and Dakota formations at depths
ranging from 9,000 to 13,000 feet. Average net daily production in 1996 was
32.7 Mmcfe.
In 1996, the Company drilled 22 wells (17.1 net) in the Rocky Mountains
(21 development wells, 16.1 net). Capital and exploration expenditures for the
year were $13.9 million. In the 1997 drilling program year, the Company has
plans to drill 36 wells.
At December 31, 1996, the Company had approximately 154,947 net acres,
including approximately 37,990 net developed acres. At year end, the Company
had identified 46 proved undeveloped drilling locations.
GULF COAST
The Company has 188 productive wells (72.7 net) in the Gulf Coast area of
which 54 wells are operated by the Company. Principal producing intervals in
Gulf Coast are in the Frio, Wilcox and Vicksburg formations at depths ranging
from 6,000 to 14,000 feet. Average net daily production in 1996 was 15.5 Mmcfe.
In 1996, the Company drilled 10 wells (5.4 net) in the Gulf Coast (8
development wells, 4.8 net). Capital and exploration expenditures for the year
were $12.2 million. In the 1997 drilling program year, the Company has plans to
drill 26 wells.
At December 31, 1996, the Company had approximately 23,677 net acres,
including approximately 14,524 net developed acres. At year end, the Company
had identified 3 proved undeveloped drilling locations.
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 and transportation management, short and
long-term supply contracts, capacity brokering and risk management
alternatives.
The marketing of natural gas has changed significantly as a result of
FERC 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 while also providing the Company the opportunity to serve broader
markets. In 1994, 1995 and 1996, there was 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 the Company's natural gas production in the
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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 ("LDCs") 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 20% 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
eastern 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 3,400 miles of pipeline with interconnects to four
interstate pipeline systems and five 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, LDCs
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 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 40%
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, midwestern, and northeastern 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
cogenerators, 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 15 year cogeneration contract with 12 years
remaining that escalates in price by 5% per year (See Item 3. Legal
Proceedings). The Western Region properties are connected to the majority of
the midwestern, northwestern, and northeastern interstate pipelines, affording
the Company access to multiple markets.
The Company also produces and markets approximately 1,100 barrels a day
of crude oil/condensate in the Western Region at market responsive prices.
RISK MANAGEMENT
In 1996, the Company entered into certain transactions to manage price
risks associated with its production and purchase commitments. 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
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price swaps call for payments to (or to receive payments from) counterparties
based upon the differential between a fixed and a variable gas price. At
December 31, 1996, the open price swaps (744,000 Mmbtu in notional quantity)
covered the months of January and February 1997. The Company plans to continue
to evaluate on an ongoing basis the benefit of this strategy in the future. See
the Overview section of Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations for further discussion.
RESERVES
CURRENT RESERVES
The following table sets forth information regarding the Company's
estimates of its net proved reserves at December 31, 1996.
Natural Gas(Mmcf) Liquids(1)(MBbl) Total(2)(Mmcfe)
- ------------------------------------------------------------------------------------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
- ------------------------------------------------------------------------------------------------------------
Appalachian 434,558 92,301 526,859 334 0 334 436,560 92,301 528,861
Western(3) 333,540 55,218 388,758 4,351 481 4,832 359,646 58,103 417,749
------- ------- ------- ----- --- ----- ------- ------- -------
Total 768,098 147,519 915,617 4,685 481 5,166 796,206 150,404 946,610
======= ======= ======= ===== === ===== ======= ======= =======
- ---------
(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.
The proved reserve estimates presented herein were prepared by the
Company's petroleum engineering staff and reviewed 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 included in Item 8 hereof. A copy of the review letter by
Miller and Lents, Ltd., has been filed as an exhibit to this Form 10-K. The
Company's estimates of proved 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, 1996.
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 represents only
estimates. 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 judgement. 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.
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HISTORICAL RESERVES
The following table sets forth certain information regarding the
Company's estimated proved reserves for the periods indicated.
Oil, Condensate
Natural Gas(Mmcf) & NGLs(MBbl) Total(Mmcfe)
- ------------------------------------------------------------------------------------------------------------------------
APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL
- ------------------------------------------------------------------------------------------------------------------------
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 and
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) (6,049) (234) (6,283)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1994 560,494 392,589 953,083 167 7,869 8,036 561,496 439,803 1,001,299
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates 3,699 10,333 14,032 65 (713) (648) 4,086 6,061 10,147
Extensions, discoveries and
other additions 12,333 22,075 34,408 23 151 174 12,471 22,982 35,453
Production (27,530) (30,191) (57,721) (18) (722) (740) (27,637) (34,525) (62,162)
Purchases of reserves in place 576 840 1,416 0 15 15 576 929 1,505
Sales of reserves in place (34,016) (21,352) (55,368) (18) (1,509)(1,527) (34,123) (30,412) (64,535)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1995 515,556 374,294 889,850 219 5,091 5,310 516,869 404,838 921,707
------- ------- ------- --- ----- ----- ------- ------- ---------
Revisions of prior estimates (487) 3,261 2,774 (2) (130) (132) (501) 2,481 1,980
Extensions, discoveries and
other additions 40,703 29,005 69,708 137 249 386 41,526 30,500 72,026
Production (26,783) (31,979) (58,762) (21) (576) (597) (26,910) (35,435) (62,345)
Purchases of reserves in place 21,207 16,190 37,397 8 207 215 21,255 17,430 38,685
Sales of reserves in place (23,337) (2,013) (25,350) (7) (9) (16) (23,377) (2,065) (25,442)
------- ------- ------- --- ----- ----- ------- ------- ---------
DECEMBER 31, 1996 526,859 388,758 915,617 334 4,832 5,166 528,862 417,749 946,611
======= ======= ======= === ===== ===== ======= ======= =========
PROVED DEVELOPED RESERVES:
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
December 31, 1995 430,165 317,070 747,235 219 4,751 4,970 431,477 345,579 777,056
December 31, 1996 434,558 333,540 768,097 334 4,351 4,685 436,560 359,646 796,206
- ---------
APP = Appalachian Region
WEST = Western Region(1)
(1) For the year ended December 31, 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.
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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.
Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------
Net Wellhead Sales Volume:
Natural Gas (Bcf)(1)
Appalachian Region 26.2 26.4 28.7
Western Region(2) 32.6 29.8 28.3
Crude/Condensate/Ngl (MBbl)
Appalachian Region 21 18 20
Western Region 576 722 804
Produced Natural Gas Sales Price ($/Mcf)(3)
Appalachian Region $ 2.72 $ 2.22 $ 2.42
Western Region $ 2.02 $ 1.33 $ 1.65
Weighted Average $ 2.34 $ 1.75 $ 2.04
Crude/Condensate Sales Price ($/Bbl)(3) $21.14 $17.95 $ 16.66
Production Costs ($/Mcfe)(4) $ 0.56 $ 0.55 $ 0.62
- ---------
(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.
(3) Represents the average sales prices for all production volumes (including
royalty volumes) sold by the Company during the periods shown net of
related costs (principally purchased gas royalty, transportation and
storage).
(4) Production costs include direct lifting costs (labor, repairs and
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.
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ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1996. 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.
LEASEHOLD ACREAGE
At December 31, 1996
Developed Undeveloped Total
- ---------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
STATE
Alabama -- -- 312 312 312 312
Arkansas -- -- 240 3 240 3
Colorado 14,742 13,406 60,283 53,314 75,025 66,720
Indiana -- -- 54,022 26,725 54,022 26,725
Kansas 33,104 29,210 6,591 2,785 39,695 31,995
Kentucky 2,680 990 15,677 7,656 18,357 8,646
Louisiana 1,541 290 4,697 904 6,238 1,194
Michigan 457 118 25,161 5,232 25,618 5,350
Montana 157 52 680 303 837 355
New York 19,365 15,557 2,282 2,216 21,647 17,773
North Dakota 160 20 870 96 1,030 116
Ohio 2,906 1,372 25,151 10,972 28,057 12,344
Oklahoma 172,234 113,811 43,832 28,737 216,066 142,548
Pennsylvania 129,577 122,144 58,454 53,209 188,031 175,353
Texas 70,453 41,447 20,708 7,849 91,161 49,296
Utah 1,740 446 23,231 19,133 24,971 19,579
Virginia 4,541 3,820 20,092 18,010 24,633 21,830
West Virginia 552,797 517,911 92,541 76,609 645,338 594,520
Wyoming 46,235 23,312 89,938 43,438 136,173 66,750
--------- ------- ------- ------- --------- ---------
Total 1,052,689 883,906 544,762 357,503 1,597,451 1,241,409
========= ======= ======= ======= ========= =========
CANADA
Alberta 1,429 563 316 79 1,745 642
British Columbia 665 166 1,992 498 2,657 664
--------- ------- ------- ------- --------- ---------
Total 2,094 729 2,308 577 4,402 1,306
========= ======= ======= ======= ========= =========
MINERAL FEE ACREAGE
At December 31, 1996
Developed Undeveloped Total
- ---------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
STATE
Colorado 174 25 265 21 439 46
Kansas 160 128 -- -- 160 128
Montana -- -- 589 75 589 75
New York -- -- 6,545 1,636 6,545 1,636
Oklahoma 16,581 13,979 240 49 16,821 14,028
Pennsylvania 70 70 1,618 547 1,688 617
Texas 27 27 847 424 874 451
Virginia 17,917 17,851 -- -- 17,917 17,851
West Virginia 89,201 75,436 56,882 55,921 146,083 131,357
--------- ------- ------- ------- --------- ---------
Total 124,130 107,516 66,986 58,673 191,116 166,189
========= ======= ======= ======= ========= =========
Aggregate Total 1,178,913 992,151 614,056 416,753 1,792,969 1,408,904
========= ======= ======= ======= ========= =========
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Total Net Acreage by Area of Operation
At December 31, 1996
Developed Undeveloped Total
- -------------------------------------------------------------
Appalachian Region 755,269 258,733 1,014,002
Western Region 236,882 158,020 394,902
======= ======= --=======
Total 992,151 416,753 1,408,904
======= ------- ---------
PRODUCTIVE WELL SUMMARY(1)
The following table reflects the Company's ownership at December 31, 1996
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, North Texas, Kansas, North Dakota, Utah, South Texas,
Colorado, Wyoming and Canada).
Natural Gas Oil Total
Gross Net Gross Net Gross Net
- ----------------------------------------------------------------------
Appalachian Region 3,837 3,564.9 21 13.9 3,858 3,578.8
Western Region 1,006 572.9 245 106.2 1,251 679.1
----- ------- --- ----- ----- -------
Total 4,843 4,137.8 266 120.1 5,109 4,257.9
===== ======= === ===== ===== =======
- ---------
(1) "Productive" wells are producing wells and wells capable of production in
which the Company has a working interest.
DRILLING ACTIVITY
The Company drilled, participated in the drilling of, or acquired wells
as set forth in the table below for the periods indicated:
Year Ended December 31,
1996 1995 1994
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------
APPALACHIAN REGION:
Development Wells
Natural Gas 85 81.6 18 16.7 133 128.2
Oil 1 1.0 0 0.0 0 0.0
Dry 12 12.0 6 4.8 7 6.5
Exploratory Wells
Natural Gas 10 5.0 2 0.5 0 0
Oil 5 0.9 2 0.5 0 0
Dry 10 5.2 5 2.0 2 0.5
--- ----- -- ---- --- -----
Total 123 105.7 33 24.5 142 135.2
=== ===== == ==== === =====
Wells Acquired(1)
Natural Gas 15 11.8 3 3.7 9 21.1
Oil 0 0.0 0 0.0 0 0.0
--- ----- -- ---- --- -----
Total 15 11.8 3 3.7 9 21.1
=== ===== == ==== === =====
Wells in Progress at End
of Period 2 1.5 3 3.0 2 1.3
10
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Year Ended December 31,
1996 1995 1994
- ---------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------
WESTERN REGION:
Development Wells
Natural Gas 52 35.4 42 21.2 48 24.7
Oil 1 .1 2 1.9 7 3.1
Dry 15 10.6 7 3.8 8 5.3
Exploratory Wells
Natural Gas 1 0 1 0.3 0 0.0
Oil 0 0 0 0 0 0.0
Dry 4 2.4 8 3.9 3 0.8
-- ---- - --- --- -----
Total 73 48.5 60 31.1 66 33.9
== ==== = === === =====
Wells Acquired(1)
Natural Gas 25 11.9 0 2.7 413 115.7
Oil 3 0.4 0 0.1 140 52.3
-----
Total 28 12.3 0 2.8 553 168.0
== ==== = === === =====
Wells in Progress at End
of Period 4 1.5 6 5.3 7 1.9
- ---------
(1) Includes the acquisition of net interest in certain wells in the
Appalachian Region and in the Western Region in 1996, 1995 and 1994 in
which the Company already held an ownership interest.
COMPETITION
Competition in the Company's primary producing areas is intense. 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. The Company also actively competes against
some companies with substantially larger financial and other resources,
particularly in the Western Region.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the
Company's total gross revenues in 1996.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with
peak demand and typically higher prices occurring during the colder winter
months.
REGULATION OF OIL AND NATURAL GAS PRODUCTION
The Company's oil and gas production and transportation operations are
subject to various types of regulation by federal, state and local authorities.
Legislation affecting the oil and natural gas industry is under constant review
for amendment or expansion. Further, numerous departments and agencies, both
federal and state, have issued rules and regulations affecting the oil and
natural gas industry and its individual members, compliance with which is often
difficult and costly and some of which may carry substantial penalties for
non-compliance.
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The regulatory burden on the oil and natural gas industry increases its cost of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations. However, the Company does not believe that under present
regulations it is affected in a significantly different manner by these
regulations than others in the industry.
EXPLORATION AND PRODUCTION
Exploration and production operations of the Company are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, maintaining
bonding requirements in order to drill or operate wells, and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled and the plugging and
abandoning of wells. The Company's operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which
may be drilled and the unitization or pooling of oil and natural gas
properties. In this regard, some states allow the forced pooling or integration
of tracts to facilitate exploration while other states rely on voluntary
pooling of lands and leases. In addition, state conservation laws establish
maximum rates or production from oil and natural gas wells, generally prohibit
the venting or flaring of natural gas and impose certain requirements regarding
the ratability of production. In this regard, such states as Texas, Oklahoma
and Louisiana have in recent years reviewed and substantially revised methods
previously used to gather the necessary information and make monthly
determinations of appropriate field and well allowables. The effect of these
regulations is to limit the amounts of oil and natural gas the Company can
produce from its wells, and to limit the number of wells or the locations at
which the Company can drill.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION
Federal legislation and regulatory controls have historically affected
the price of the natural gas produced by the Company and the manner in which
such production is marketed. The Federal Energy Regulatory Commission (the
"FERC") regulates the interstate transportation and sale for resale of natural
gas by interstate and intrastate pipelines. The FERC previously regulated the
maximum selling prices of certain categories of gas sold in "first sales" in
interstate and intrastate commerce under the Natural Gas Policy Act. Effective
January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") deregulated natural gas prices for all "first sales" of
natural gas, which includes all sales by the Company of its own production. As
a result, all sales of the Company's domestically produced natural gas may be
sold at market prices, unless otherwise committed by contract. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act.
The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas suppliers, the FERC, commencing in
April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have
altered significantly the interstate transportation and sale of natural gas.
Among other things, Order No. 636 required pipelines to unbundle the various
services that they had provided in the past, such as sales, transmission and
storage, and to offer these services individually to their customers. By
requiring interstate pipelines to "unbundle" their services and to provide
their customers with direct access to pipeline capacity held by them, Order No.
636 has enabled pipeline customers to choose the levels of transportation and
storage service they require, as well as to purchase natural gas directly from
third-party merchants other than the pipelines and obtain transportation of
such gas on a nondiscriminatory basis. The effect of Order No. 636 has been to
enable the Company to market its natural gas production to a wider variety of
potential purchasers. The Company believes that these changes generally have
improved the Company's access to transportation and have enhanced the
marketability of its natural gas production. To date, Order No. 636 has not had
any material adverse effect on the Company's ability to market and transport
its natural gas production. However, even though Order No. 636 has been
affirmed on appeal, with minor exceptions, and most individual pipelines have
final open access tariffs now in place, the FERC is continuing to review and
assess the effectiveness of it regulations and the Company cannot predict what
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new regulations may be adopted by the FERC and other regulatory authorities, or
what effect subsequent regulations may have on the Company's activities.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline-owned
gathering facilities either to non-affiliated companies (a "spin off") or to
the pipeline's nonregulated affiliate (a "spin down "), (ii) the completion of
a rulemaking proceeding involving the regulation of pipelines with marketing
affiliates under Order No. 497, (iii) FERC's ongoing efforts to promulgate
standards for pipeline electronic bulletin boards and electronic data exchange,
(iv) a generic inquiry into the pricing of interstate pipeline capacity, (v)
efforts to refine FERC's regulations controlling the operation of the secondary
market for released pipeline capacity, (vi) a policy statement regarding
market-based rates and other non-cost-based rates for interstate pipeline
transmission and storage capacity and (vii) appropriate ratemaking procedures
for pipeline expansions and extensions. Several of these initiatives are
intended to enhance competition in natural gas markets, although some, such as
the so-called "spin-down" of previously regulated gathering facilities by
interstate pipelines to their affiliates, may have the adverse effect on some
in the industry of increasing the cost of doing business as a result of the
monopolization of those facilities by their new, unregulated owners. FERC
attempted to address some of these concerns in its orders authorizing such
"spin-downs," but one of its principal devices, the use of "default" contracts
to assure continuity of gathering services for two years after spin down, was
found unlawful on appeal and it remains to be seen what effect the FERC's other
activities will have on access to markets and the cost to do business. In
response to the FERC's policy of authorizing the interstate pipeline industry's
divestiture of these gathering facilities, several states (most notably
Oklahoma and Texas) have enacted or are considering laws and regulations
enhancing state level oversight over gathering. As to all of these recent FERC
and state initiatives, the ongoing, or, in some instances, preliminary evolving
nature of these regulatory initiatives makes it impossible at this time to
predict their ultimate impact upon the Company's activities.
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
General. 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. Such government regulation can increase the cost of
planning, designing, installing and operating oil and gas facilities. In most
instances, the regulatory requirements impose water and air pollution control
measures. Although the Company believes that compliance with environmental
regulations will not have a material adverse effect on the Company, risks of
substantial costs and liabilities related to environmental compliance issues
are inherent in oil and gas production operations, and no assurance can be
given that significant costs and liabilities will not be incurred. Moreover, it
is possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or persons resulting from oil
and gas production would result in substantial costs and liabilities to the
Company.
Solid and Hazardous Waste. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other solid wastes may have been disposed or released on
or under the properties owned or leased by the Company. In addition, many of
the properties have been operated by third parties. The Company had no control
over such parties' treatment of hydrocarbons or other solid wastes and the
manner in which such
13
15
substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed or released by
prior owners and operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
The Company generates some wastes that are subject to the Federal
Resource Conservation and Recovery Act ("RCRA") and comparable State statutes.
The Environmental Protection Agency ("EPA") has limited the disposal options
for certain "hazardous wastes." Furthermore, it is possible that certain wastes
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" under RCRA or other applicable statues, and
therefore be subject to more rigorous and costly disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA") , also known as the "Superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a site and any party that disposed or arranged for the disposal of the
hazardous substance found at a site. CERCLA also authorizes the EPA, and in
some cases, third parties, to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible parties
the costs of such action. In the course of the Company's operations, the
Company has generated and will generate wastes that may fall within CERCLA's
definition of "hazardous substances." The Company may also be an owner of sites
on which "hazardous substances" have been released. Therefore, the Company may
be responsible under CERCLA for all or part of the costs to clean up sites at
which such wastes have been disposed.
Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose a variety of regulations on "responsible parties"
related to the prevention of oil spills and liability for damages resulting
from such spills in "waters of the United States." The term "waters of the
United States" has been broadly defined to include inland waste bodies,
including wetlands and intermittent streams. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages.
Air Emissions. The operations of the Company are subject to local, state
and federal laws and regulations for the control of emissions from sources of
air pollution. Administrative enforcement actions for failure to comply
strictly with air regulations or permits are generally resolved by payment of
monetary fines and correction of any identified deficiencies. Alternatively,
regulatory agencies could require the Company to cease construction or
operation of certain air emission sources. The Company believes that it is in
substantial compliance with the emission standards under local, state and
federal laws and regulations.
EMPLOYEES
The Company had 360 active employees as of December 31, 1996. The Company
believes that its relations with its employees are satisfactory. The Company
has not entered into any collective bargaining agreements with its employees.
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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, 1996, the
Company owned or operated approximately 3,400 miles of natural gas gathering
and pipeline systems. As part of its normal maintenance program, the Company
has identified certain segments of its pipelines which it believes require
repair, replacement or additional maintenance. 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. The Company is also 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 and cash flows of any period but would
not have a material adverse effect on the Company's financial position.
On February 10, 1997, Washington Energy Company and Puget Sound Power &
Light Company merged to form Puget Sound Energy, Inc. ("Puget"). As a result of
the merger, Puget is the holder of 2,133,000 shares of Common Stock and
1,134,000 shares of the Company's 6% Convertible Redeemable Preferred Stock
(convertible into 1,972,174 shares of Common Stock), all of which were
previously held by Washington Energy Company. Mr. William P. Vititoe, a member
of the Company's Board of Directors, is a consultant to Puget and was formerly
an officer and director of Washington Energy Company.
The Company sells approximately 20% of its natural gas production in the
Western Region to a cogeneration plant located in Bellingham, Washington and
owned by Encogen Northwest, L.P. ("Encogen") under a gas sales contract
containing a fixed price that escalates annually, a firm delivery arrangement
and a term continuing through June 30, 2008. Encogen sells all the electrical
power generated in the plant to Puget under an Agreement for Firm Power
Purchase ("Power Agreement"). The Company is aware that a dispute has arisen
between Puget and Encogen over the appropriate interpretation of certain
provisions of the Power Agreement, which dispute is currently being litigated.
Puget has requested the court, among other matters, to declare that Encogen is
in material breach of the Power Agreement. A finding by the court that Encogen
is in material breach of the Power Agreement could lead to termination of the
Power Agreement. Any restructuring or termination of the Power Agreement may
have a negative impact on the Company's gas sales arrangement with Encogen.
Encogen has requested that the Company consider restructuring its gas sales
arrangement with Encogen. To date the Company has been unwilling to restructure
its gas sales agreement without being fully compensated for the agreement's
value.
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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, 1996 to December 31, 1996.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive
officers of the Company as of March 1, 1997, as such term is defined in Rule
3b-7 promulgated under the Securities Exchange Act of 1934, and certain other
officers of the Company.
Name Age Position Officer Since
- --------------------------------------------------------------------------------------------
Charles P. Siess, Jr. 70 Chairman of the Board, Chief Executive 1995
Officer and President
Ray R. Seegmiller 61 Executive Vice President, Chief Operating 1995
Officer and Treasurer
Jim L. Batt 61 Vice President, Land 1988
Jeff W. Hutton 41 Vice President, Marketing 1995
Gerald F. Reiger 45 Vice President and Regional Manager 1995
James M. Trimble 48 Vice President, Business Development 1987
and Engineering
H. Baird Whitehead 46 Vice President and Regional Manager 1987
Paul F. Boling 43 Controller 1996
Lisa A. Machesney 41 Corporate Secretary and Managing Counsel 1995
All officers are elected annually by the Company's Board of Directors.
With the exception of the following, all executive officers of the Company have
been employed by the Company for at least the last five years.
Charles P. Siess, Jr. has been Chairman of the Board, Chief Executive
Officer and President of the Company since May 1995. From February 1993 until
January 1994, Mr. Siess served as Acting General Manager of Bridas S.A.P.I.C.
(oil exploration in Argentina). Prior thereto, Mr. Siess served as Chairman of
the Board, Chief Executive Officer and President of the Company from December
1989 to December 1992.
Gerald F. Reiger has been Vice President, Regional Manager of the Company
since February 1995. From May 1994 until February 1995, Mr. Reiger served as
Regional Manager of the Company. Prior thereto, Mr. Reiger was associated with
Washington Energy Resources Company, a subsidiary of Washington Energy Company,
from 1992 to 1994. Prior thereto, Mr. Reiger served as U.S. Operations Manager
of DeKalb Energy Company.
Ray R. Seegmiller joined the Company as Vice President, Chief Financial
Officer and Treasurer in August 1995. From May 1988 until 1993, Mr. Seegmiller
served as President and Chief Executive of Terry Petroleum Company. Prior
thereto, Mr. Seegmiller held various officer positions with Marathon
Manufacturing Company.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock
Exchange under the ticker symbol "COG". 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:
Cash
High Low Dividends
- -------------------------------------------------------------
1996
First Quarter $ 16.88 $ 13.13 $ 0.04
Second Quarter 17.63 13.75 0.04
Third Quarter 18.38 13.75 0.04
Fourth Quarter 18.38 14.38 0.04
1995
First Quarter $ 16.00 $ 12.38 $ 0.04
Second Quarter 17.00 13.63 0.04
Third Quarter 15.38 13.00 0.04
Fourth Quarter 15.75 13.13 0.04
As of January 31, 1997, there were 1,478 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.
ITEM 6. 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.
Year Ended December 31,
(In thousands, except per share amounts) 1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
Net Operating Revenues $ 163,061 $ 121,083 $ 140,295 $ 115,816 $ 107,205
Income (Loss) from Operations 48,787 (116,758) 15,013 20,007 17,983
Net Income (Loss) Applicable to
All Common Stockholders 15,258 (92,171) (5,444) 2,088 2,227
EARNINGS (LOSS) PER SHARE APPLICABLE
TO ALL COMMON STOCKHOLDERS(1) $ .67 $ (4.05) $ (0.25) $ 0.10 $ 0.11
DIVIDENDS PER COMMON SHARE $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.16
BALANCE SHEET DATA:
Properties and Equipment, Net $ 480,511 $ 474,371 $ 634,934 $ 400,270 $ 306,723
Total Assets 561,341 528,155 688,352 445,001 348,696
Long-Term Debt 248,000 249,000 268,363 169,000 120,000
Stockholders' Equity 160,704 147,856 243,082 153,529 118,313
- ---------
(1) See "Earnings (Loss) Per Common Share" under Note 1 of the Notes to the
Consolidated Financial Statements.
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ITEM 7. 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 substantial up swing in gas prices, coupled with actions taken in
1995 designed to return the Company to long-term profitability, played an
important part in the Company's performance in 1996 with record earnings and
operating cash flows. Operating results for 1996 included the benefit of the
following realizations:
o The average produced natural gas price was $2.34 per Mcf, up 34%
compared to 1995.
o As a result of the improved pricing environment, margins on brokered
natural gas sales increased 124%, or $3.1 million over 1995.
o Under its continued program to divest non-strategic properties, the
Company sold 339 wells located in the Appalachian Region, generating
$4.6 million in cash proceeds and a gain on sale of $1.6 million.
o Net interest costs were down $7.5 million, or 30%, primarily due to
the absence of interest rate swaps that were in place in 1995, lower
interest rates, a reduced debt balance and $1.7 million of interest
income related to an income tax refund for tax periods prior to 1990.
o Depreciation, depletion and amortization ("DD&A") expenses were down
$6.9 million or $0.11 per Mcfe of production. This reduction was
primarily the result of the impairment of long-lived assets recorded
as a result of adopting SFAS 121 in September 1995, which reduced the
depreciable basis of properties and equipment by $113.8 million.
Operating cash flows reached a record level, increasing $34.0 million,
or 82%, over 1995. Cash flows from operations, along with the $5.7 million of
proceeds from the sale of non-strategic properties, predominantly funded (1)
$73.3 million of capital and exploration expenditures, $49 million higher than
1995, and (2) $9.2 million of preferred and common stock dividend payments.
The Company drilled 154.2 net wells with a net success rate of 80%
compared to 55.4 net wells and a net 75% success rate in 1995. Along with the
higher success rate in 1996, the Company replaced 118% of production, through
drilling additions and revisions, versus 73% production replacement in 1995. In
1997 the Company plans to drill 256 wells and spend $78.3 million in capital
and exploration expenditures, 7% higher than 1996 expenditures.
Natural gas production equivalent was 62.3 Bcf, virtually unchanged
compared to 1995. The production from new wells reversed the downward trend in
production experienced in the early part of 1996 due to (1) the low level of
development activity in 1995, drilling only 55 net wells compared to an average
of 135 net wells per year over the previous five years, and (2) the sale of
non-strategic properties, representing quarterly production of 0.6 Bcf.
The Company had a number of gas price swaps in place to hedge a
significant portion of its production for the first four months of 1996. For
the remainder of 1996, the Company had one small hedge contract for the months
of May through September 1996 in a notional quantity equal to 5,000 Mmbtu per
day, or less than 4% of the Company's daily production. While the Company will
selectively use gas price hedges from time-to-time to protect certain markets
when substantial downside risks are perceived, management intends to structure
the hedge positions in a manner that retains upside potential.
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The Company's strategic pursuits are sensitive to energy commodity
prices, particularly the price of natural gas. While gas prices in many regions
of the U.S. moved up sharply in November and December of 1996 to near record
levels and some industry analysts predict continued improvements in 1997
pricing over 1996, the gas market has demonstrated significant price volatility
during the months of January, February, and March 1997. Consequently, there is
considerable uncertainty about gas prices for the rest of 1997 and beyond.
The Company remains focused on the following goals established in 1995,
applying a three pronged strategy of growth through the drill bit, growth
through synergistic acquisitions and growth through greater emphasis on
marketing. The Company believes that progress toward these goals is appropriate
in the current industry environment, enabling the Company to effectively
achieve its strategy over the long term.
o Increase cash flows, using a balance of increased production and
reduced costs. Significant progress has been made toward this goal,
and the Company expects to be profitable in 1997 if the Henry Hub
average price for the full year is $1.80 or more, assuming a
traditional correlation between Henry Hub prices and prices realized
by the Company in its regional markets.
o Maintain reserves per share while increasing production to protect
long-term shareholder value. An aggressive 1997 drilling program is
designed to result in 1997 production exceeding 1996, and reserves
are also expected to increase.
o Reduce debt as a percentage of total capitalization without diluting
existing shareholder value. To achieve this goal, project returns
will be compared with the marginal cost of debt when deciding whether
to reinvest or pay down debt. Other financing alternatives will also
be reviewed.
The preceding paragraphs, discussing the Company's strategic pursuits
and goals, contain forward-looking information. See FORWARD-LOOKING INFORMATION
on page 23.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
The Company's capital resources consist primarily of cash flows from its
oil and gas properties and asset-based borrowing supported by its oil and gas
reserves. The Company's level of earnings and cash flows depend on many
factors, including the price of oil and natural gas and its ability to control
and 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. Natural gas prices and demand were up significantly in
1996 over 1995, resulting in higher cash flows.
The primary source of cash for the Company during 1996 was from funds
generated from operations. Primary uses of cash were funds used in operations,
exploration and development expenditures, acquisitions, dividends on preferred
and common stock and repayment of debt.
The Company had a net cash outflow of $1.7 million in 1996. Net cash
inflow from operating and financing activities totalled $65.9 million, funding
in most part the capital and exploration expenditures of $67.6 million, net of
the $5.7 million in proceeds from the sale of assets.
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(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided by Operating Activities $ 75.5 $ 41.5 $ 67.3
-------- ------- --------
Cash flows provided by operating activities in 1996 were substantially
higher, increasing $34 million over 1995, due predominantly to higher natural
gas prices.
Cash flows provided by operating activities in 1995 were lower by $25.8
million compared with 1994 primarily due to lower gas prices and higher
interest costs attributable to the 1994 and 1993 acquisitions.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided (Used) by Investing Activities $ (67.6) $ (14.0) $ (158.8)
-------- ------- --------
Cash flows used by investing activities in 1996 were $53.5 million higher
than in 1995 due primarily to $40.6 million of increased capital and
exploration expenditures over 1995. The Company's 1995 drilling program was
scaled down, drilling only 55.4 net wells, compared to an average of 135 net
wells per year over the previous five years. The 1996 capital expenditures were
offset in part by proceeds of $5.7 million from the sale of assets.
Cash flows used by investing activities in 1995 were $144.8 million lower
than in 1994 due primarily to a $48.0 million decrease in capital expenditures
and the lack of a major acquisition in 1995 compared to the $78.5 million
capital outlay for the WERCO acquisition in 1994. The 1995 capital expenditures
were offset in part by proceeds of $8.4 million for a valuation adjustment on
the WERCO acquisition and $10.3 million in proceeds from the sale of assets.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Cash Flows Provided (Used) by Financing Activities $ (9.6) $ (28.2) $ 92.4
-------- ------- --------
Cash flows provided (used) by financing activities from 1994 to 1995 were
primarily borrowings from or payments on the Company's revolving credit
facility while in 1996 most of the activity was dividend payments. In 1996 and
1995 the Company reduced its debt under this facility by $1.0 million and $19.0
million, respectively. 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
1993 acquisition of proved properties from Emax Oil Company ("Emax"), and $7.1
million for other property acquisitions and capital expenditures.
Since June 1995, the Company's available credit line under the revolving
credit facility has been $235 million. The available credit line is subject 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 $168 million at December 31, 1996.
The Company's 1997 interest expense is projected to be approximately $19
million. No principal payments are due in 1997.
Capitalization information on the Company is as follows:
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Long-Term Debt $ 248.0 $ 249.0 $ 268.3
Stockholders' Equity
Common Stock 69.4 56.6 151.8
Preferred Stock 91.3 91.3 91.3
-------- ------- --------
Total 160.7 147.9 243.1
-------- ------- --------
Total Capitalization $ 408.7 $ 396.9 $ 511.4
======== ======= ========
Debt to Capitalization 60.7% 62.7% 52.5%
-------- ------- --------
20
22
The Company's capitalization reflects the non-cash impact to equity of
the $69.2 million SFAS 121 impairment of long-lived assets recorded in 1995.
(See Note 15 of the Notes to the Consolidated Financial Statements for further
discussion.)
CAPITAL AND EXPLORATION EXPENDITURES
The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1996.
(In millions) 1996 1995 1994
-------------------------------------------------------------------------------------------
Capital Expenditures:
Drilling and Facilities $ 42.7 $ 19.3 $ 47.9
Leasehold Acquisitions 4.3 2.0 4.7
Pipeline and Gathering 6.3 2.2 8.9
Other 0.7 1.2 2.3
-------- ------- --------
54.0 24.7 63.8
-------- ------- --------
Proved Property Acquisitions 6.6 -- 8.9
WERCO Acquisition (5.3)(1) (8.4)(2) 216.2(3)
-------- ------- --------
1.3 (8.4) 225.1
-------- ------- --------
Exploration Expenses 12.6 8.0 8.0
-------- ------- --------
Total $ 67.9 $ 24.3 $ 296.9
======== ======= ========
- ---------
(1) An adjustment to the $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", of the WERCO acquisition as a result of the $8.4 million
valuation adjustment received in 1995.
(2) A net cash payment received in connection with a valuation adjustment on
the 1994 WERCO acquisition.
(3) 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 described in note (1).
The substantial reduction in capital and exploration expenditures in 1995
resulted from the downsized capital expenditures program resulting from
depressed gas prices and the absence of a major acquisition.
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 1997 have been increased 7% compared with 1996.
Depending on the level of future natural gas prices, the Company intends to
review and adjust the capital and exploration expenditures planned for 1997 as
industry conditions dictate. Presently, the Company projects $78 million in
capital and exploration expenditures for 1997. The Company plans to drill 256
wells (167 net), compared with 196 wells (154 net) drilled in 1996. Capital
dedicated to the drilling program for 1997 is $61 million.
In addition to the drilling program, other 1997 capital expenditures are
planned primarily for producing property acquisitions and for gathering and
pipeline infrastructure maintenance and construction.
During 1996, dividends were paid on the Company's common stock totaling
$3.6 million, on the $3.125 convertible preferred stock totaling $2.2 million,
and on the 6% convertible redeemable preferred stock totaling $3.4 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.
21
23
OTHER ISSUES AND CONTINGENCIES
Encogen Gas Contract. See Item 3. Legal Proceedings on page 15 for a
discussion of this matter.
Corporate Income Tax. The Company generates 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 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 $1.02 per Mmbtu in 1996. In 1995 and 1996, the Company
completed three transactions to monetize the value of these tax credits,
resulting in revenues of $3.4 million in 1996 and approximately $20 million
over the remaining six years (See Note 18 of the Notes to the Consolidated
Financial Statements for further discussion).
The Company has benefited in the past and may benefit 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 ("IDC") 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% of the amount of
such income determined without regard to the repeal of such preference.
Regulations. The Company's operations are subject to various types of
regulation by federal, state and local authorities. See "Regulation of Oil and
Natural Gas Production and Transportation" and "Environmental Regulations" in
the Other Business Matters section of Item 1. Business for a discussion of
these regulations.
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 covenants in the Company's
various debt instruments. Among other requirements, the Company's revolving
credit facility specifies a minimum annual coverage ratio of operating cash
flow to interest expense for the trailing four quarters of 2.8 to 1.0.
At December 31, 1996 the calculated ratio for 1996 was 4.8 to 1.
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 1996 produced natural gas
sales price increased 34% compared to 1995 and is the predominant reason for
its record 1996 earnings and operating cash flow performance since becoming a
public company in 1990. While prices in most regions of the U.S. moved up
sharply in November and December 1996, price volatility in the gas market has
remained prevalent in the last few years, as demonstrated most recently in the
first two months of 1997 with wide price swings in day-to-day trading on the
NYMEX futures market. Given this continued price volatility, management cannot
predict with certainty what pricing levels will be for the rest of 1997 and
beyond. 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 if prices should return to
the depressed levels of 1995.
While the Company's 1997 plans include an increase in capital spending,
potentially negative changes in industry conditions might require the Company
to adjust its 1997 spending plan to ensure the adequate funding of its capital
requirements, including, among other things, reductions in capital expenditures
or common stock dividends.
22
24
The Company believes its capital resources, supplemented, if necessary,
with external financing, are adequate to meet its capital requirements.
The preceding paragraphs contain forward-looking information. See
FORWARD-LOOKING INFORMATION below.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results and the
other statements which are not historical facts contained in this report are
forward-looking statements. The words "expect," "project," "estimate,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and
marketing activity, future production and costs and other factors detailed
herein and in the Company's other Securities and Exchange Commission filings.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary materially
from those indicated.
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 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" in
1994.
SELECTED FINANCIAL AND OPERATING DATA
(In millions except where specified) 1996 1995 1994
- -----------------------------------------------------------------------------
Net Operating Revenues $ 163.1 $ 121.1 $ 140.3
Operating Expenses 116.0 237.2 125.4
Interest Expense 17.4 24.9 16.7
Net Income (Loss) 15.3 (92.2) (5.4)
Earnings (Loss) Per Share $ 0.67 $ (4.05) $ (0.25)
Natural Gas Production (Bcf)
Appalachia 26.8 27.5 29.7
West 32.0 30.2 28.6
------- ------- -------
Total Company 58.8 57.7 58.3
======= ======= =======
Produced Natural Gas Sales Price ($/Mcf)
Appalachia $ 2.72 $ 2.22 $ 2.42
West $ 2.02 $ 1.33 $ 1.65
Total Company $ 2.34 $ 1.75 $ 2.04
Crude/Condensate
Volume (MBbl) 520 618 687
Price ($/Bbl) $ 21.14 $ 17.95 $ 16.66
23
25
The table below presents the after-tax effects of certain selected items
("selected items") on the Company's results of operations for the three years
ended December 31, 1996.
(In millions) 1996 1995 1994
- ------------------------------------------------------------------------
Net Income (Loss) Before Selected Items $ 12.5 $ (17.3) $ (5.4)
Income tax refund 2.8
SFAS 121 impairment (69.2)
Cost reduction program (4.7)
Columbia settlement 2.6
Decoupled gas price hedges (2.0)
Terminated interest rate swaps (1.6)
------- ------- ------
Net Income (Loss) $ 15.3 $ (92.2) $ (5.4)
======= ======= ======
1996 AND 1995 COMPARED
Net Income (Loss) and Revenues. The Company reported a net income in 1996
of $12.5 million, or $0.55 per share, up $29.8 million, or $1.31 per share,
compared with 1995, excluding the impact of the selected items. The $2.8
million special item, or $0.12 per share, in 1996 related to a $1.8 million tax
refund for percentage depletion claimed for certain periods prior to 1990 and
$1.7 million of interest income ($1.0 million after tax) earned on the refund
amount. The $74.9 million from special items, or $3.29 per share, in 1995
consisted of a $113.8 million charge ($69.2 million after tax) related to the
adoption of SFAS 121, $7.7 million ($4.7 million after tax) for the cost
reduction program and other severance costs, $3.2 million ($2.0 million after
tax) loss related to uncovered gas price hedges and a $2.6 million charge ($1.6
million after tax) to interest expense to close interest rate swap contracts,
offset in part by other revenue of $4.3 million ($2.6 million after tax) in
connection with the sale of a Columbia bankruptcy claim. Excluding the pre-tax
effects of the selected items, operating income and net operating revenues
increased $39 million and $43.1 million, respectively. Natural gas sales
comprised 84%, or $137.5 million, of net operating revenue in 1996. The
increase in net operating revenues was driven primarily by a 34% increase in
the produced natural gas sales price. Net income (loss) and operating income
(loss), excluding selected items, were similarly impacted by the increase in
the produced natural gas sales price, as well as lower depreciation, depletion
& amortization and interest expenses.
Natural gas production volumes were down 0.7 Bcf, or 3%, to 26.8 Bcf in
the Appalachian Region, a result from the low level of drilling activity in
1995 and the sale of non-strategic properties. Natural gas production volumes
were up 1.8 Bcf, or 6%, to 32.0 Bcf in the Western Region due primarily to
Rocky Mountains and Gulf Coast area wells drilled and put on line in the second
and third quarters of 1996.
The average Appalachian natural gas production sales price increased
$0.50 per Mcf, or 23%, to $2.72, increasing net operating revenues by
approximately $13.6 million on 26.8 Bcf of production. In the Western Region,
the average natural gas production sales price increased $0.69 per Mcf, or 52%,
to $2.02, increasing net operating revenues by approximately $22.3 million on
32.0 Bcf of production. The overall weighted average natural gas production
sales price increased $0.59 per Mcf, or 34%, to $2.34.
Crude oil and condensate sales decreased 98 MBbl, or 16%, due primarily
to the low drilling activity in 1995 and the sale of various non-strategic oil
properties in 1995.
Brokered natural gas margin was up $3.1 million to $5.6 million due
primarily to a $0.08 per Mcf increase in the net margin to $0.15 per Mcf, a
result of the higher prices environment in 1996. Brokered volume was comparable
to 1995.
24
26
Operating Expenses. Total operating expenses, excluding the selected
items, were virtually unchanged, increasing $0.4 million. The significant
changes are explained as follows:
o Exploration expense increased $4.5 million due to the $4.1 million
increase in dry hole expense and the $0.4 million increase in
geological and geophysical expenses, a direct result of the increased
capital expenditure program in 1996.
o Depreciation, depletion, amortization and impairment expense
decreased $6.9 million, or 13%, due to a $0.11 per Mcfe decline in
the DD&A rate caused by the 1995 impairment of long-lived assets
which reduced depreciable basis by $113.8 million.
o Taxes other than income increased $1.6 million, or 14%, due primarily
to the increase in natural gas production revenues.
o The cost reduction program in 1995 consisted primarily of a 23% staff
reduction, achieved through early retirement and involuntary
termination programs. The pre-tax charges, a selected item, related
to this action totalled $6.8 million, comprised of $3.8 million in
salary and other severance related expense and a $3.0 million
non-cash charge for curtailments to the pension and postretirement
benefits plans.
Interest expense, excluding selected items, declined $3.1 million, or
14%, due primarily to the absence of the interest rate swaps which effectively
increased interest expense in 1995.
Income tax expense, excluding the selected item, was up $67.4 million due
to the comparable increase in earnings before income tax. The Company's
effective tax rate was virtually unchanged.
1995 AND 1994 COMPARED
Net Income (Loss) and Revenues. The Company reported a net loss in 1995
of $17.3 million, or $0.76 per share, down $11.9 million, or $0.52, compared
with 1994, excluding the impact of the selected items. The $74.9 million from
special items, or $3.29 per share, consisted of a $113.8 million charge ($69.2
million after tax) related to the adoption of SFAS 121, $7.7 million ($4.7
million after tax) for the cost reduction program and other severance costs,
$3.2 million ($2.0 million after tax) loss related to uncovered gas price
hedges and a $2.6 million charge ($1.6 million after tax) to interest expense
to close interest rate swap contracts, offset in part by other revenue of $4.3
million ($2.6 million after tax) in connection with the sale of a Columbia
bankruptcy claim. Excluding the pre-tax effects of the selected items,
operating income and operating revenues decreased $8.7 million and $24.3
million, respectively. Natural gas production revenues comprised 84%, or $101.3
million, of total net operating revenues in 1995. The decrease in total net
operating revenues was driven primarily by a 14% decrease in the average
produced natural gas sales price, and in part by a 1% increase in natural gas
production volumes due to higher gas purchased for resale (up 18%) as discussed
below. Net income (loss) and operating income (loss), excluding selected items,
were similarly impacted by the decline in the average natural gas price, as
well as higher financing costs in connection with the 1994 WERCO and 1993 Emax
acquisitions.
Natural gas production volume in the Appalachian Region was down 2.1 Bcf,
or 7%, to 27.5 Bcf due in part to higher pipeline curtailments and normal
production declines not fully replaced by new production due primarily to
reduced drilling activity in 1995. Natural gas production volumes were up 1.5
Bcf to 30.2 Bcf in the Western Region due primarily to a full year of operating
results from the WERCO acquisition.
The average Appalachian natural gas production sales price decreased
$0.20 per Mcf, or 9%, to $2.22, decreasing net operating revenues by
approximately $5.5 million. In the Western Region, the average natural gas
production sales price decreased $0.32 per Mcf, or 19%, to $1.33, decreasing
net operating revenues by approximately $9.7 million. Because the proportion of
lower priced Western Region production sales volume relative to total Company
production sales volume was up significantly, the weighted average natural gas
production sales price for the total Company decreased $0.29 per Mcf, or 14%,
to $1.75.
Crude oil and condensate sales were virtually unchanged at 618 MBbl.
25
27
Costs and Expenses. Total costs and expenses, excluding the selected
items, decreased $13.5 million, or 6%, due primarily to the following:
o The costs of natural gas decreased $3.9 million to $92.8 million. The
decrease was primarily due to a $0.42 per Mcf decrease in the average
price of gas purchased for resale, partially offset by a 10.4 Bcf
increase in gas purchased for resale (including gas exchanges and
storage).
o Direct operations expense decreased $5.0 million, or 15%, due in
large part to reductions in (1) lease maintenance work and workovers,
(2) field and regional office expenses due primarily to the cost
reduction program, and (3) compressor rental and overhaul expenses.
o Depreciation, depletion, amortization and impairment expense,
excluding the $113.8 million impairment of long-lived assets in
connection with SFAS 121, decreased $2.3 million due primarily to the
decrease in the DD&A rate in the fourth quarter resulting from the
SFAS 121 impairment. Due to the adoption of SFAS 121, the Company's
DD&A rate is expected to decrease in future years by $0.13 per Mcfe.
o General and administrative expense decreased $1.4 million, or 8%, due
largely to costs savings realized from the cost reduction program.
o The cost reduction program, recorded in the first quarter, consisted
primarily of a 23% staff reduction, achieved through early retirement
and involuntary termination programs. The pre-tax charges related to
this action totalled $6.8 million, comprised of $3.8 million in
salary and other severance related expense ($3.6 million paid during
the nine months) and a $3.0 million non-cash charge for the impact of
the staff reduction to the pension and postretirement benefits plans.
o Taxes other than income decreased $0.9 million, or 7.6%, due
primarily to the decline in gas revenue.
Interest expense was up $8.2 million, or 49%, due to the increase in debt
primarily attributable to the WERCO acquisition in 1994 and the Emax
acquisition in 1993.
Income tax benefit was up $54.4 million due to the comparable decrease in
earnings before income tax. The Company's effective tax rate was virtually
unchanged.
26
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
- --------------------------------------------------------------------------
Report of Independent Accountants 28
Consolidated Statement of Operations 29
Consolidated Balance Sheet 30
Consolidated Statement of Cash Flows 31
Consolidated Statement of Stockholders' Equity 32
Notes to Consolidated Financial Statements 33
Supplemental Oil & Gas Information (Unaudited) 49
Quarterly Financial Information (Unaudited) 53
REPORT OF MANAGEMENT
The management of Cabot Oil & Gas Corporation is responsible for the
preparation and integrity of all information contained in the annual report.
The consolidated financial statements and other financial information are
prepared in conformity with generally accepted accounting principles and,
accordingly, include certain informed judgements and estimates of management.
Management maintains a system of internal accounting and managerial
controls and engages internal audit representatives who monitor and test the
operation of these controls. Although no system can ensure the elimination of
all errors and irregularities, the system is designed to provide reasonable
assurance that assets are safeguarded, transactions are executed in accordance
with management's authorization and accounting records are reliable for
financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management, the
independent accountants and internal audit representatives to obtain assurances
to the integrity of the Company's accounting and financial reporting and to
affirm the adequacy of the system of accounting and managerial controls in
place. The independent accountants and internal audit representatives have full
and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
consolidated financial statements and in the other sections of the annual
report.
March 7, 1997 Charles P. Siess, Jr.
Chairman of the Board,
Chief Executive Officer and President
27
29
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, 1996 and 1995, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles.
As discussed in Notes 14 and 15 to the consolidated financial statements,
in 1995 the Company changed its method of applying the unit-of-production
method to calculate depreciation and depletion on producing oil and gas
properties, and accounting for the impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 7, 1997
28
30
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In thousands, except per share amounts) 1996 1995 1994
- ---------------------------------------------------------------------------------------
NET OPERATING REVENUES
Natural Gas Production $ 137,482 $ 101,260 $ 119,076
Crude Oil and Condensate 10,992 11,089 11,445
Brokered Natural Gas Margin 5,619 2,509 3,802
Other 8,968 6,225 5,972
--------- --------- ---------
163,061 121,083 140,295
OPERATING EXPENSES
Direct Operations 28,361 28,328 33,332
Exploration 12,559 8,031 8,014
Depreciation, Depletion and Amortization 42,689 47,206 51,040
Impairment of Long-Lived Assets (Note 15) -- 113,795 --
Impairment of Unproved Properties 2,701 5,047 3,556
General and Administrative 16,823 16,785 17,278
Cost Reduction Program (Note 12) -- 6,820 --
Taxes Other Than Income 12,826 11,215 12,141
--------- --------- ---------
115,959 237,227 125,361
Gain (Loss) on Sale of Assets 1,685 (614) 79
--------- --------- ---------
INCOME (LOSS) FROM OPERATIONS 48,787 (116,758) 15,013
Interest Expense 17,409 24,885 16,651
--------- --------- ---------
Income (Loss) Before Income Tax Expense 31,378 (141,643) (1,638)
Income Tax Expense (Benefit) 10,554 (55,025) (643)
--------- --------- ---------
NET INCOME (LOSS) 20,824 (86,618) (995)
Dividend Requirement on Preferred Stock 5,566 5,553 4,449
--------- --------- ---------
Net Income (Loss) Applicable to
Common Stockholders $ 15,258 $ (92,171) $ (5,444)
========= ========= =========
Earnings (Loss) Per Share Applicable
to Common Stockholders $ 0.67 $ (4.05) $ (0.25)
========= ========= =========
Average Common Shares Outstanding 22,807 22,775 22,018
========= ========= =========
- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
29
31
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
(In thousands) 1996 1995
- ------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 1,367 $ 3,029
Accounts Receivable 67,810 42,014
Inventories 8,797 5,596
Other 1,663 1,709
--------- ---------
Total Current Assets 79,637 52,348
PROPERTIES AND EQUIPMENT (Successful Efforts Method) 480,511 474,371
OTHER ASSETS 1,193 1,436
--------- ---------
$ 561,341 $ 528,155
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable $ 56,338 $ 48,122
Accrued Liabilities 16,279 12,759
--------- ---------
Total Current Liabilities 72,617 60,881
LONG-TERM DEBT 248,000 249,000
DEFERRED INCOME TAXES 69,427 62,752
OTHER LIABILITIES 10,593 7,666
COMMITMENTS AND CONTINGENCIES (Note 8)
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 1996 and 1995 -- 6% Convertible
Redeemable Preferred; $50 Stated Value; 1,134,000
Shares in 1996 and 1995 183 183
Common Stock:
Authorized -- 40,000,000 Shares of $0.10 Par Value
Issued and Outstanding -- 22,847,345 Shares and
22,783,319 Shares at December 31, 1996 and 1995,
respectively 2,284 2,278
Class B Common Stock:
Authorized -- 800,000 Shares of $0.10 Par Value
No Shares Issued -- --
Additional Paid-in Capital 243,283 242,058
Accumulated Deficit (85,046) (96,663)
--------- ---------
Total Stockholders' Equity 160,704 147,856
--------- ---------
$ 561,341 $ 528,155
========= =========
- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
30
32
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In thousands) 1996 1995 1994
- --------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 20,824 $ (86,618) $ (995)
Adjustments to Reconcile Net Income (Loss)
to Cash Provided by Operations:
Depletion, Depreciation, and Amortization 42,689 47,206 51,040
Impairment of Long-Lived Assets -- 113,795 --
Impairment of Unproved Properties 2,701 5,047 3,556
Deferred Income Tax Expense (Benefit) 12,017 (55,055) (796)
Loss (Gain) on Sale of Assets (1,685) 614 (79)
Exploration Expense 12,559 8,031 8,014
Other, Net 176 3,178 (1,535)
Changes in Assets and Liabilities:
Accounts Receivable (25,796) (3,848) (2,870)
Inventories (3,201) 2,788 (2,691)
Other Current Assets 46 (13) (944)
Other Assets 243 (37) (1,306)
Accounts Payable and Accrued Liabilities 11,199 5,838 16,167
Other Liabilities 3,713 565 (258)
--------- --------- ---------
Net Cash Provided by Operations 75,485 41,491 67,303
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (60,719) (24,672) (72,684)