1
EXHIBIT 13
CABOT OIL & GAS CORPORATION
SELECTED HISTORICAL FINANCIAL DATA
The following table sets forth a summary of selected consolidated financial
data for the Company for the periods indicated. This information should be read
in conjunction with Management's Discussion and Analysis of Financial Condition
and Results of Operations and the Consolidated Financial Statements and related
Notes thereto.
THREE
MONTHS
ENDED YEAR ENDED
YEAR ENDED DECEMBER 31, DECEMBER SEPTEMBER 30,
----------------------------------- 31, ----------------------
1993 1992 1991 1990 1990 1989
--------- --------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA
Revenues $164,295 $147,608 $140,484 $ 48,519 $128,621 $149,422
Income from
Operations 20,007 17,983 13,707 13,047 18,889 28,534
Net Income Available
to All Common
Stockholders 2,088 2,227 229 7,224 11,697
EARNINGS PER SHARE
AVAILABLE TO ALL
COMMON STOCKHOLDERS
Historical(1) $ 0.10 $ 0.11 $ 0.01 $ 0.35 $ 0.57
Pro Forma
(Unaudited)(2) 0.27
BALANCE SHEET DATA
Oil and Gas
Properties $322,163 $229,778 $229,538 $217,937 $212,251 $203,151
Total Assets 445,001 348,696 334,311 320,740 302,107 289,476
Long-Term Debt 169,000 120,000 105,000 91,500 80,000 --
Stockholders'
Equity 153,529 118,313 119,241 121,933 114,912 184,981
- ---------------
(1) See "Earnings Per Share" under Note 2 of the Notes to the Consolidated
Financial Statements.
(2) Adjusted to reflect the effect as though the Company's IPO had occurred on
October 1, 1989.
17
2
CABOT OIL & GAS CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OFOPERATIONS
The following review of operations should be read in conjunction with the
Consolidated Financial Statements and the Notes thereto included elsewhere.
OVERVIEW
The Company continues to focus its operations in the Appalachian and
Anadarko Regions through development of undeveloped reserves and acreage,
acquisition of oil and gas producing properties and, to a lesser extent,
exploration. In addition, the Company is engaged in a wide array of gas
marketing activities. The Company has expanded its strategic plan to include
exploring possible acquisition opportunities outside of the Company's core areas
and broadening its gas marketing capabilities.
During 1993, the Company undertook several important steps toward the full
execution of its strategic plan: expanding its drilling program, successfully
acquiring over $84 million of natural gas and oil properties in the Appalachian
and Anadarko Regions, and realigning its senior management team.
-- The Company drilled 150 net wells, of which 97 were connected to a
pipeline by year end. The 1993 drilling program, which was expanded at
mid-year, reflects the Company's strong development drilling
capabilities on existing acreage and the benefit from acquisitions made
during the year. The 1993 drilling program compares with 95 net wells
drilled in 1992. The Company recorded a drilling success rate of 92
percent on wells drilled in 1993.
-- Acquisitions closed during the year represent potential recoverable
reserves in excess of 150 Bcfe. The two largest acquisitions were:
Anadarko properties purchased in May from Harken Anadarko Partners
L.P. brought proved reserves of 52.1 Bcfe by year end, including
new proved undeveloped locations.
Appalachian properties purchased from Emax Oil Company brought
proved reserves of 52.3 Bcfe and 69 future drilling locations
including those associated with a related farmout agreement with
another operator.
-- The Company also realigned its senior management to better reflect
requirements for the future and to further cultivate a team approach to
managing our assets.
During 1994, the Company will continue to aggressively pursue its growth
strategy, through the exploitation of current development drilling
opportunities, selective acquisitions and expanded marketing activities. The
acquisition program will focus on opportunities to add strategically located
properties in our core operating areas of the Appalachia and Anadarko Regions.
Acquisitions in other natural gas producing areas throughout the United States
have potential attraction where production and exploration opportunities are
similar to core areas where the Company has demonstrated expertise. Toward this
end:
-- On February 25, 1994, the Company and Washington Energy Company
announced the signing of a merger agreement between a Company subsidiary
and Washington Energy Resources Company (WERCO), a wholly-owned
subsidiary of Washington Energy. The Company will acquire the capital
stock of WERCO in a tax-free exchange for total consideration of $180
million, subject to certain adjustments. As of January 1, 1994 WERCO
held approximately 230 Bcfe of proved reserves located primarily in the
Green River Basin of Wyoming and in South Texas. The reserves are 82%
natural gas. Excluded from the
18
3
transaction are certain firm transportation, storage and other
contractual arrangements of WERCO's marketing affiliate which will be
retained by Washington Energy.
-- Included in the 1994 capital expenditure budget is $8.8 million related
to two pending acquisitions of certain proved reserves and pipeline
facilities from CNG Transmission Corporation which await regulatory
approval prior to closing.
The Company also intends to expand its marketing presence by placing
greater emphasis on increased brokerage and risk management activities.
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 flow depend upon many
factors, including the price of oil and natural gas and its ability to market
production on a cost-effective basis. Demand for oil and gas is subject to
seasonal influences characterized by peak demand and higher prices in the winter
heating season.
Primary sources of cash for the Company during the three-year period ended
December 31, 1993 were from funds generated from operations and bank borrowings.
Primary uses of cash for the same period were funds used in operations,
exploration and development expenditures, acquisitions, repayment of debt and
dividends.
The Company had a net cash inflow of $1.8 million in 1993. Net cash
outflows from operating and investing activities totalled $43.5 million in 1993,
consisting primarily of capital expenditures. Funding from the Company's $210
million credit facility was used to finance these cash requirements.
1993 1992 1991
------ ------ ------
(IN MILLIONS)
Cash Flows Provided by Operating Activities $55.4 $27.9 $39.1
----- ----- -----
----- ----- -----
Cash flows from operating activities in 1993 were higher by $27.5 million
compared to the previous year primarily due to a higher funding requirement of
working capital in 1992, described below.
Cash flows from operating activities in 1992 were lower than 1991 by $11.2
million primarily due to an $8.8 million increase in accounts receivable, as a
result of increased prices and timing.
1993 1992 1991
------ ------ ------
(IN MILLIONS)
Cash Flows Used by Investing Activities $98.9 $42.5 $52.2
----- ----- -----
----- ----- -----
Cash flows used by investing activities in 1993 were $56.4 million higher
than in 1992 primarily due to increased capital expenditures, most notably the
Emax Acquisition for $46.4 million. Cash flows used by investing activities in
1992 and 1991 were substantially attributable to capital and exploration
expenditures, $43.2 million and $54.2 million, respectively. The Company reduced
its capital spending in 1992 primarily in response to a decline in natural gas
prices in the first half of the year.
1993 1992 1991
------ ------ ------
(IN MILLIONS)
Cash Flows Provided by Financing Activities $45.3 $13.5 $10.2
----- ----- -----
----- ----- -----
19
4
Cash flows provided by financing activities from 1991 to 1993 are primarily
borrowings under the Company's revolving credit facility. The increase in 1993
of $31.8 million was primarily attributable to indebtedness incurred to finance
the Emax Acquisition.
The Company increased its revolving credit facility from $150 million
to $210 million on October 29, 1993. The Company also increased the available
credit line from $130 million to $180 million, of which $89 million was
outstanding at December 31, 1993, and increased the borrowing rate by 1/8 of 1%
for LIBOR and CD based rates. The increase in the available credit was due to
an increased oil and gas reserve valuation, primarily due to higher gas prices
and to the Emax and Harvard Acquisitions. The available credit line is subject
to adjustment on the basis of the projected present value (as determined by a
petroleum engineer's report incorporating certain assumptions provided by the
lender) of estimated future net cash flows from proved oil and gas reserves and
other assets. If supported by such an adjustment, the borrowing presently may
be increased up to $210 million. Pending the successful closing of the WERCO
transaction, the Company intends to seek a further expansion of the borrowing
capacity under such agreement.
During 1993, the Company executed interest rate swap agreements with four
banks that effectively converted the Company's $80 million fixed-rate notes into
variable rate notes. Under the swap agreements, the Company will pay a variable
rate of interest equal to the six-month LIBOR. The banks will pay the Company
fixed rates of interest that average 5.00%. The difference paid or received
under such agreements is charged or credited to interest expense over the life
of the agreements. The four agreements have notional principal of $20 million
each with terms of two, three, four and five years. The fair value is determined
by obtaining termination values from third parties.
The Company's 1994 debt service is projected to be approximately $13.0
million. No principal payments are due in 1994.
Capitalization information on the Company is as follows:
1993 1992 1991
------ ------ ------
(IN MILLIONS)
Stockholders' Equity
Common Stock $118.9 $118.3 $119.2
Preferred Stock 34.6 -- --
Long-Term Debt 169.0 120.0 105.0
------ ------ ------
Total Capitalization $322.5 $238.3 $224.2
------ ------ ------
------ ------ ------
Debt to Capitalization 52.4% 50.4% 46.8%
------ ------ ------
------ ------ ------
20
5
Capital and Exploration Expenditures
The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1993.
1993 1992 1991
------- ------ ------
(IN MILLIONS)
Capital Expenditures:
Drilling and Facilities $ 34.6 $ 19.9 $ 30.1
Leasehold Acquisitions 3.9 1.9 2.5
Proved Property Acquisitions 82.4 1.6 0.9
Pipeline and Gathering 6.8 8.2 11.5
Other 1.3 5.4 1.1
------- ------ ------
129.0 37.0 46.1
Exploration Expenses 6.9 6.2 8.1
------- ------ ------
Total $ 135.9 $ 43.2 $ 54.2
------- ------ ------
------- ------ ------
As part of its long-term growth strategy, the Company placed greater
emphasis on acquiring proved oil and gas properties in 1993.
In May 1993, the Company purchased oil and natural gas properties located
in the Anadarko Region of Texas and Oklahoma, and in the East Texas Basin from
Harken Anadarko Partners, L.P. (the 'Harvard Acquisition"). The Company issued
692,439 shares of $3.125 convertible preferred stock to Harvard University. The
preferred stock has a total stated value of $34.6 million, or $50 per share, and
is convertible, subject to certain adjustments, into 1,648,662 shares of Common
Stock at $21 per share, also subject to certain adjustments. As of the
acquisition date, the properties had approximately 38.2 billion cubic feet
equivalent of proved reserves which are 80% natural gas and included 518 (166
net) wells, of which almost 45% are operated by the Company. Average net daily
production on these properties in 1993 was 10.95 million cubic feet equivalent
("MMcfe").
In September 1993, the Company purchased oil and natural gas properties and
related assets located in the Appalachian Region of West Virginia and
Pennsylvania from Emax Oil Company (the "Emax Acquisition") for cash of
approximately $44.1 million, subject to certain adjustments. As of the
acquisition date, the properties had approximately 47.1 billion cubic feet
equivalent of proved reserves of which 99% are natural gas. The properties
include 300 (291 net) wells, all but one of which are operated by the Company.
Average net daily production on these properties in 1993 was 8.70 MMcfe. As part
of the acquisition, the Company entered into a development agreement that
provides for the acquisition of additional drilling locations for approximately
$106 thousand per location. The agreement provides for the drilling of 78 such
wells under a farmout from a local producer. Total expected drilling costs for
these 78 wells are estimated at $13.6 million. The Company drilled 22 of these
wells in 1993, which added approximately 5.2 Bcfe to the proved reserves
acquired and increased the total acquisition cost by $2.3 million. At year end
the Company had identified 69 future drilling locations, including the remaining
locations associated with the farmout agreement mentioned above.
Total capital and exploration expenditures in 1993 increased $92.7 million
compared to 1992 primarily due to the $84.6 million of oil and gas property
acquisitions including the two acquisitions discussed above. Drilling and
facilities expenditures in 1991 were $10.2 million higher than 1992 largely due
to exceptionally low expenditures in 1992. Other capital expenditures are $4.3
million lower in comparison to 1992 which included a $4.7 million capital
investment to modernize the Company's computer systems.
Capital and exploration expenditures in 1992 decreased $11 million, or 20%,
compared to 1991 primarily due to a comparable decline in drilling and
facilities expenditures. Such expenditures were
21
6
unusually low in 1992 due to a corresponding decrease in cash generated from
operations when natural gas prices collapsed early in 1992.
The Company generally funds most of 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.
The Company has a $81.2 million capital and exploration expenditures budget
for 1994 which should permit the Company to continue to expand its reserves and
production. COG plans to drill 188 wells, 171 net to its interest, compared with
162 wells, 150 net, drilled in 1993. Capital dedicated to the drilling program
for 1994 is $39.7 million.
The 1994 budget also includes $20.5 million for producing property
acquisitions in its core areas of the Appalachian and Anadarko Regions. At
year-end 1993, letters of intent were in hand for two acquisitions in West
Virginia from CNG Transmission Corporation for $8.8 million. Both of these
transactions include pipeline assets which require approval of the Federal
Energy Regulatory Commission before closing.
The remaining $21.0 million of capital expenditures budgeted for 1994 will
be used primarily as follows: $9.9 million to assure the integrity of and expand
the Company's gathering and pipeline infrastructure, $3.7 million to acquire
additional acreage for future development and $5.1 million to administer the
exploratory effort. Depending on future natural gas prices, the Company intends
to review and perhaps adjust the capital and exploration expenditures budgeted
in 1994 as industry conditions dictate.
During 1993, dividends were paid on the Company's common stock totalling
$3.3 million and on the Company's $3.125 convertible preferred stock totalling
$0.9 million.
Other Capital Requirements and Contingencies
Pending Acquisition. On February 25, 1994, the Company and Washington
Energy Company jointly announced the signing of a merger agreement between a
Company subsidiary and Washington Energy Resources Company ("WERCO"), a
wholly-owned subsidiary of Washington Energy Company. The Company will acquire
the stock of WERCO in a tax-free exchange for total consideration of $180
million, subject to certain adjustments. Excluded from the transaction are
certain firm transportation, storage and other contractual arrangements of
WERCO's marketing affiliate which will be retained by Washington Energy Company.
COG will issue 2,133,000 shares of common stock and 1,134,000 shares of 6
percent convertible redeemable preferred stock to Washington Energy Company in
exchange for the capital stock of WERCO. The preferred stock will be convertible
into 1,972,174 shares of common stock at $28.75 per share. In addition, the
Company will advance cash to repay intercompany indebtedness outstanding at
closing and assume $5.9 million of third-party debt. The intercompany debt of
WERCO was $69.1 million at December 31, 1993, as adjusted.
Hancock Dispute. In July 1992, the John Hancock Mutual Life Insurance
Company ("John Hancock") asserted that as a result of the operation by the
Company of certain wells in northwestern Pennsylvania jointly owned by John
Hancock and the Company (the "Properties"), a permanent diminution of up to 5.1
Bcfe in the oil and gas reserves available from the Properties has occurred.
John Hancock also asserted that the value of its loss resulting from such
diminution in reserves is approximately $6 million. Since that time, management,
along with its outside technical advisors, has undertaken a comprehensive and
continuing review of its operating practices related to the Properties. Based
upon that review, management believes that its operation of the Properties has
been appropriate. While the Company cannot predict the ultimate outcome of the
claim, the Company believes that the resolution of the claim will not have a
material adverse effect on the Company's financial position.
22
7
Corporate Income Tax. The Company is a beneficiary of tax credits for the
production of certain qualified fuels, including natural gas produced from tight
formations and Devonian Shale. The credit for natural gas from a tight formation
(or, "tight gas sands") amounts to $0.52 per MMbtu for natural gas sold prior to
2003 from qualified wells drilled in 1991 and 1992. In 1991 and 1992, a number
of wells drilled in the Appalachian Region qualified for the "tight gas sands"
tax credit. The credit for natural gas produced from Devonian Shale is
approximately $1.00 per MMbtu in 1993. However, the benefits of such credits
have been, and may continue to be, lost or deferred depending on the amount of
regular taxable income earned by the Company. Under current tax provisions, the
Company expects to benefit by the carryforward of credits that become a part of
the minimum tax credit carryforward.
The Company may benefit in 1994 and in the future from the alternative
minimum tax ("AMT") relief granted under the Comprehensive National Energy
Policy Act of 1992. The Act repealed provisions of the AMT requiring a
taxpayer's alternative minimum taxable income to be increased on account of
certain intangible drilling costs ("IDCs") and percentage depletion deductions.
The repeal of these provisions generally applies to taxable years beginning
after 1992. The repeal of the "excess IDC preference" cannot reduce a taxpayer's
alternative minimum taxable income by more than 40% (30% for 1993) of the amount
of such income determined without regard to the repeal of such preference.
FERC Order 636. The marketing of natural gas has changed significantly as
a result of Order 636 (the "Order"), which was issued by the FERC in 1992. The
Order required interstate 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. The
Order has created greater competition in the industry, but has also provided the
Company the opportunity to reach broader markets. In 1993, this has meant an
increase in the number of third-party producers that use the Company to market
their gas and in margin pressures from increased competition for markets.
Environmental Regulation. The Company operates under numerous state and
federal laws regulating the discharge of materials into, and the protection of,
the environment, including the Federal Clean Air Act. In the ordinary course of
business, the Company conducts an ongoing review of the effect of these various
environmental laws, based upon the information currently available. It is
impossible to determine whether and to what extent the Company's future
performance may be affected by environmental laws; however, management does not
believe that such laws will have a material adverse effect on the Company's
financial position or results of operations.
Restrictive Covenants. The Company's ability to incur debt, to pay
dividends on its common and preferred stock, and to make certain types of
investments is dependent upon certain restrictive debt covenants in the
Company's various debt instruments. Among other requirements, the Company's
Revolving Credit Facility specifies a minimum cash flow to debt service coverage
ratio. The Company's cash flow to debt service coverage ratio, using cash flow
estimates provided by the agent bank, was 5.8 to 1.0 compared with the minimum
requirement of 1.2 to 1.0.
Conclusion
The Company's financial results depend upon many variables, particularly
the price of natural gas, and its ability to market gas on economically
attractive terms. The Company's average 1993 natural gas price increased 10%
over the average natural gas price received for 1992. However, given the
inherent price volatility of natural gas prices in recent years, management
cannot predict with certainty, a continuing trend of higher prices for the
remainder of 1994. Because future cash flows are subject to such variables,
there can be no assurance that the Company's operations will provide cash
sufficient to fully fund its capital expenditures.
In addition, the Company has adopted a plan to pursue potential
acquisitions as part of its stated corporate strategy. Such acquisitions may
require capital resources beyond those provided
23
8
from operations. The Company's ability to fund such acquisitions, if necessary,
with external financing is dependent, among other things, upon available
borrowing capacity under its committed bank line and the Company's access to and
the general conditions of debt and equity capital markets.
However, the Company believes its capital resources, supplemented, if
necessary, with external financing, are adequate to meet its capital
requirements, including acquisitions.
RESULTS OF OPERATIONS
For the purpose of reviewing the Company's results of operations, "Net
Income" is defined as net income available to all common shareholders.
SELECTED FINANCIAL AND OPERATING DATA
1993 1992 1991
------- ------- -------
(IN MILLIONS, EXCEPT WHERE
SPECIFIED)
Revenues $ 164.3 $ 147.6 $ 140.5
Costs and Expenses 145.6 130.2 126.7
Interest Expense 10.3 9.8 7.6
Net Income 2.1 2.2 0.2
Earnings Per Share $ 0.10 $ 0.11 $ 0.01
Natural Gas Production (Bcf)
Appalachia 26.2 25.6 26.6
Anadarko 19.8 19.9 17.1
------- ------- -------
Total Company 46.0 45.5 43.7
------- ------- -------
------- ------- -------
Natural Gas Sales (Bcf)
Appalachia 39.9 40.7 41.7
Anadarko 24.5 23.8 20.6
------- ------- -------
Total Company 64.4 64.5 62.3
------- ------- -------
------- ------- -------
Natural Gas Prices ($/Mcf)
Appalachia $ 2.69 $ 2.50 $ 2.43
Anadarko $ 1.94 $ 1.62 $ 1.49
Total Company $ 2.40 $ 2.18 $ 2.12
Crude/Condensate
Volume (MBbl) 345 162 148
Price $/Bbl $ 16.58 $ 19.03 $ 19.80
24
9
The table below presents the effects of certain selected items ("selected
items") on the Company's results of operations for the three years ended
December 31, 1993.
1993 1992 1991
------- ------- -------
(IN MILLIONS)
Net Income Before Selected Items $ 5.1 $ 6.4 $ 5.7
Early adoption of SFAS 112 (0.4)
Consolidation of office space (0.3)
Deferred tax adjustment due to federal rate change (2.3)
Early adoption of SFAS 106 (1.5)
Settlement of Cabot tax dispute (2.7)
Cost reduction program (1.5)
Deferred tax adjustment due to state tax law change (3.1)
Cost associated with stock exchange (0.9)
------- ------- -------
Net Income $ 2.1 $ 2.2 $ 0.2
------- ------- -------
------- ------- -------
1993 and 1992 Compared
Net Income and Revenues. Net income, excluding the impact of the selected
items, was $1.3 million, or $0.06 per share, lower than 1992. Excluding the
pre-tax effects of the selected items, income from operations was $0.8 million
higher. Operating revenues increased $16.7 million, or 11%, in 1993. Natural gas
made up 94%, or $154.8 million, of operating revenue. The increase in operating
revenues was driven primarily by an increase in the average natural gas prices
as discussed below.
Natural gas sales volumes were down 0.8 Bcf to 39.9 Bcf in the Appalachian
Region. Production volume in the Appalachian Region was up 0.6 Bcf, or 2%,
primarily due to the Emax Acquisition. Production volume in the Anadarko Region
was down 1.7 Bcf, or 9%, excluding 1.7 Bcf of production from the Harvard
Acquisition. Natural gas sales volumes in the Anadarko Region were down 1.0 Bcf,
excluding 1.7 Bcf of sales from the Harvard Acquisition. The decrease in
Anadarko was primarily attributable to insufficient replacement well production
necessary to offset the significant production declines on several high
deliverability but short-lived wells drilled in 1990.
The average Appalachian natural gas sales price increased $0.19 per Mcf, or
8%, to $2.69, increasing operating revenues by approximately $7.6 million. In
the Anadarko Region, the average natural gas sales price increased $0.32 per
Mcf, or 20%, to $1.94, increasing operating revenues by approximately $7.8
million. Due to the weighted mix of sales volume, the overall weighted average
natural gas sales price increased $0.22 per Mcf, or 10%, to $2.40.
Crude oil and condensate sales increased 183 MBbl, or 113%, due primarily
to the Harvard Acquisition.
Cost and Expenses. Excluding the pre-tax effects of the selected items,
total costs and expenses increased $16.6 million, or 13%, due primarily to
the following:
- The costs of natural gas increased $8.1 million, or 20%. The increase was
primarily due to a $0.19 per Mcf increase in the average price of gas
purchased for resale and a 1.7 Bcf increase in gas purchased for resale
and gas exchanges.
- Direct operations expenses increased $3.5 million, or 14%. Such expenses
included $0.8 million of relocation costs associated with the
consolidation of regional offices in Appalachia and Anadarko, $1.7
million of operating expenses attributable to the Harvard and Emax
Acquisitions and $0.5 million of higher subsurface maintenance and
pipeline right-of-way maintenance costs.
- Exploration expense increased $0.7 million, or 11%, due primarily to
higher dry hole expenses.
25
10
- Depreciation, depletion, amortization and impairment expense increased
$0.4 million, or 1%, excluding the $2.5 million attributable to the
Harvard and Emax Acquisitions.
- General and administrative costs decreased $1.1 million, or 7%,
excluding the impact of the $2.4 million charge for postretirement
benefits cost recorded in 1992 (a selected item). The $1.1 million
decrease was primarily attributable to personnel reductions in
connection with the 1991 cost reduction program that were made in the
regional and corporate offices in late 1992. Effective January 1, 1992,
the Company elected the early adoption of the Statement of Financial
Accounting Standards ("SFAS") 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions," and elected to amortize
the accumulated postretirement benefit obligation at January 1, 1992
("Transition Obligation") over 20 years. Due to an amendment of the
postretirement benefits plan, effective January 1, 1993, the
amortization cost of the unrecognized Transition Obligation for 1993 was
significantly reduced. The Company's postretirement benefits cost for
1993 was approximately $20 thousand.
- Taxes other than income increased $2.5 million, or 35%, due primarily to
higher taxes on production and reserves, as a result of higher natural
gas prices, and to the Harvard and Emax Acquisitions.
Income tax expense was up $0.6 million, or 18%, and is comparable to the
increase in earnings before income tax.
1992 and 1991 Compared
Net Income and Revenues. Net income, excluding the impact of the selected
items, was $0.7 million, or $0.03 per share, higher in 1992 compared with 1991.
Excluding the pre-tax effects of the selected items, income from operations was
$3.0 million, or 17%, higher than 1991. Operating revenues increased $7.1
million, or 5%. Natural gas made up 95%, or $140.7 million, of operating
revenues.
Natural gas sales volumes rose 2.2 Bcf, or 4%, increasing revenues by
approximately $4.7 million in 1992. The Company's Appalachian natural gas sales
volume decreased 1.0 Bcf, or 2%, due primarily to decreased production volumes.
In the Anadarko Region, the Company increased natural gas sales volume 3.2 Bcf,
or 16%. This increase was attributable primarily to production enhancements
(such as the installation of new field compression, plunger-lifts and other
down-hole equipment), to new drilling, and to improved transportation
arrangements to market natural gas.
The average Appalachian natural gas sales price increased $0.07 per Mcf, or
3%. The average Anadarko natural gas sales price increased by $0.13 per Mcf, or
9%. The Company's weighted average natural gas sales price increased $0.06 per
Mcf, or 3%. The effect of the higher weighted average price on revenues was
approximately $3.9 million.
Crude oil and condensate sales increased 14 MBbl, or 9%, due primarily to
new drilling. The average price decreased by $0.77 per Bbl, or 4%.
Cost and Expenses. Excluding the pre-tax effects of the selected items,
total costs and expenses increased $4.8 million, or 4%, due primarily to the
following:
- The costs of natural gas increased $4.0 million, or 11%, due primarily to
a $0.15 per Mcf increase in the average cost of purchased natural gas to
$1.90.
- Exploration expense decreased $1.8 million, or 23%, due primarily to
reduced dry hole expense.
- Depreciation, depletion, amortization and impairment expense increased
$4.3 million, or 16%, due in part to higher unit of production cost as a
result of downward reserve revisions in certain Appalachian Basin
properties at the end of 1991, to increased production from newer
26
11
wells and to a higher impairment provision due to early abandonments of
leasehold acquisitions.
- General and administrative expenses were down $1.5 million, or 8%. The
decline is largely attributable to the cost reduction program. Selected
items for 1991 were a $2.4 million one-time charge in the fourth quarter
for the cost reduction program and $1.4 million associated with the Stock
Exchange. The cost reduction program provided for a 12% reduction in the
Company's work force by the end of 1992 and included the cost of
severance, relocation and other related expenses. The selected item in
1992 was a $2.4 million charge to record early adoption of SFAS 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions.
The Statement requires employers to recognize the cost of providing
postretirement benefits to employees over the employees' service periods.
The Company elected to amortize the accumulated postretirement benefit
obligation at January 1, 1992 over 20 years, resulting in a non-cash
charge of $2.4 million in 1992.
Interest income decreased $1.8 million because the Cabot Note was retired
on March 28, 1991 (See Note 11 of the Notes to the Consolidated Financial
Statements).
Interest expense increased $0.4 million because of the increase in
long-term debt, partly offset by a decline in interest rates in 1992.
The Company's income tax expense in 1992 included a $2.7 million charge due
to the settlement of the Cabot tax dispute. The Company's income tax expense in
1991 included a $3.1 million charge associated with a change in a state tax law
no longer allowing unused state net loss carryforwards. Both of these tax
charges are selected items.
27
12
CABOT OIL & GAS CORPORATION
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheet of Cabot Oil &
Gas Corporation as of December 31, 1993 and 1992, and the related consolidated
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 1993. 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, 1993 and 1992, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1993, in conformity with generally accepted accounting
principles.
As discussed in Note 7 to the financial statements, the Company changed its
method of accounting for Postretirement Benefits Other Than Pensions in 1992.
COOPERS & LYBRAND
Houston, Texas
February 25, 1994
28
13
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS EXCEPT PER SHARE
AMOUNTS)
REVENUES
Natural Gas $ 154,792 $ 140,676 $ 132,043
Crude Oil and Condensate 5,715 3,088 2,924
Other 3,788 3,844 5,517
--------- --------- ---------
164,295 147,608 140,484
COSTS AND EXPENSES
Costs of Natural Gas 48,479 40,403 36,420
Direct Operations 28,681 25,152 25,472
Exploration 6,943 6,227 8,060
Depreciation, Depletion and Amortization 31,621 27,966 24,548
Impairment of Unproved Properties 2,834 3,575 2,651
General and Administrative (Notes 7 and 15) 17,539 19,867 22,727
Taxes Other Than Income 9,490 7,034 6,851
--------- --------- ---------
145,587 130,224 126,729
Gain (Loss) on Sale of Assets 1,299 599 (48)
--------- --------- ---------
INCOME FROM OPERATIONS 20,007 17,983 13,707
Other (Income) Expense
Interest Income (8) (6) (1,800)
Interest Expense 10,336 9,763 9,394
--------- --------- ---------
10,328 9,757 7,594
--------- --------- ---------
Income Before Income Tax Expense 9,679 8,226 6,113
Income Tax Expense (Note 9) 6,159 5,999 4,812
--------- --------- ---------
NET INCOME 3,520 2,227 1,301
Dividend Requirement on Preferred Stock and Class B
Common Stock, Respectively 1,432 -- 1,072
--------- --------- ---------
Net Income Available to All Common Stockholders $ 2,088 $ 2,227 $ 229
--------- --------- ---------
--------- --------- ---------
EARNINGS PER SHARE AVAILABLE TO ALL COMMON
STOCKHOLDERS $ 0.10 $ 0.11 $ 0.01
--------- --------- ---------
--------- --------- ---------
Average Common Shares Outstanding 20,507 20,465 20,465
--------- --------- ---------
--------- --------- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
29
14
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
------------------------
1993 1992
--------- ---------
(IN THOUSANDS)
ASSETS
Current Assets
Cash and Cash Equivalents $ 2,897 $ 1,102
Accounts Receivable 35,296 34,516
Inventories 5,693 5,758
Other 752 356
--------- ---------
Total Current Assets 44,638 41,732
Properties and Equipment (Successful Efforts Method) 400,270 306,723
Other Assets 93 241
--------- ---------
$ 445,001 $ 348,696
--------- ---------
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Short-Term Debt $ 530 $ 1,810
Accounts Payable 26,538 19,786
Accrued Liabilities 10,223 11,178
--------- ---------
Total Current Liabilities 37,291 32,774
Long-Term Debt 169,000 120,000
Deferred Income Taxes 78,698 71,640
Other Liabilities 6,483 5,969
Commitments and Contingencies (Note 10)
Stockholders' Equity
Preferred Stock:
Authorized -- 5,000,000 Shares of $.10 Par Value
Issued and Outstanding -- $3.125 Cumulative Convertible
Preferred; $50 Stated Value; 692,439 Shares in 1993 69 --
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding -- 20,583,220 Shares and
20,465,000 Shares at December 31, 1993
and 1992, Respectively 2,058 2,046
Class B Common Stock:
Authorized 800,000 Shares of $.10 Par Value
No Shares Outstanding -- --
Additional Paid-in Capital 143,264 106,936
Retained Earnings 8,138 9,331
--------- ---------
Total Stockholders' Equity 153,529 118,313
--------- ---------
$ 445,001 $ 348,696
--------- ---------
--------- ---------
The accompanying notes are an integral part of these consolidated financial
statements.
30
15
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
---------------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 3,520 $ 2,227 $ 1,301
Adjustments to Reconcile Net Income to
Cash Provided by Operating Activities:
Depletion, Depreciation, and Amortization 34,455 31,541 27,199
Deferred Income Taxes 7,058 (1,344) 2,649
(Gain) Loss on Sale of Assets (1,299) (599) 48
Exploration Expense 6,943 6,227 8,060
Postretirement Benefits Other Than Pensions
(Note 7) (339) 2,460 --
Cabot Note (Note 11) -- -- (1,072)
Other, Net (67) (20) 207
Changes in Assets and Liabilities:
Accounts Receivable (780) (8,847) 1,337
Inventories 65 (1,249) (937)
Other Current Assets (395) 178 (143)
Other Assets 147 99 341
Accounts Payable and Accrued Liabilities 5,591 (3,314) 36
Other Liabilities 551 556 78
--------- --------- ---------
Net Cash Provided by Operating Activities 55,450 27,915 39,104
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures(1) (94,377) (36,966) (46,094)
Proceeds from Sale of Assets 2,410 653 1,997
Exploration Expense (6,943) (6,227) (8,060)
--------- --------- ---------
Net Cash Used by Investing Activities (98,910) (42,540) (52,157)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt 47,720 16,810 13,500
Exercise of Stock Options 1,742 -- --
Dividends Paid (4,207) (3,275) (3,274)
Collection of Cabot Note -- -- 93,432
Special Dividend Paid to Cabot -- -- (93,432)
--------- --------- ---------
Net Cash Provided by Financing Activities 45,255 13,535 10,226
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 1,795 (1,090) (2,827)
Cash and Cash Equivalents, Beginning of Year 1,102 2,192 5,019
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 2,897 $ 1,102 $ 2,192
--------- --------- ---------
--------- --------- ---------
- ---------------
(1) Excludes non-cash acquisition of oil and gas properties in exchange for
preferred stock with a stated value of $34.6 million. See Note 13. Property
Acquisitions.
The accompanying notes are an integral part of these consolidated financial
statements.
31
16
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
AMOUNTS
COMMON PREFERRED PAID-IN RETAINED DUE FROM
STOCK(1) STOCK CAPITAL EARNINGS AFFILIATES TOTAL
------- ---- --------- -------- --------- ---------
(IN THOUSANDS)
Balance at December 31, 1990 $ 2,046 $ -- $ 191,463 $ 17,496 $ (89,072) $ 121,933
------- ---- --------- -------- --------- ---------
Net Income 1,301 1,301
Dividends Paid at $.16 Per
Share (3,274) (3,274)
Interest on Cabot Note, Net of
Tax (1,072) (1,072)
Collection of Cabot Note 93,432 93,432
Special Dividend Paid to
Cabot (85,000) (5,144) (3,288) (93,432)
Other 353 353
------- ---- --------- -------- --------- ---------
Balance at December 31, 1991 2,046 -- 106,816 10,379 -- 119,241
------- ---- --------- -------- --------- ---------
Net Income 2,227 2,227
Dividends Paid at $.16 Per
Share (3,275) (3,275)
Other 120 120
------- ---- --------- -------- --------- ---------
Balance at December 31, 1992 2,046 -- 106,936 9,331 -- 118,313
------- ---- --------- -------- --------- ---------
Net Income 3,520 3,520
Exercise of Stock Options 12 1,730 1,742
Issuance of Preferred Stock 69 34,552 34,621
Common Stock Dividends at $.16
Per Share (3,281) (3,281)
Preferred Stock Dividends at
$2.07 Per Share (1,432) (1,432)
Other 46 46
------- ---- --------- -------- --------- ---------
Balance at December 31, 1993 $ 2,058 $ 69 $ 143,264 $ 8,138 $ -- $ 153,529
------- ---- --------- -------- --------- ---------
------- ---- --------- -------- --------- ---------
- ---------------
(1) Class B Common Stock included. Exchanged for Common Stock on March 28, 1991.
The accompanying notes are an integral part of these consolidated financial
statements.
32
17
CABOT OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Cabot Oil & Gas Corporation and subsidiaries (the "Company") are engaged in
the exploration, development, production and sale of natural gas and, to a
lesser extent, crude oil. The Company also transports, stores, gathers and
purchases natural gas for resale.
The Company, previously a subsidiary of Cabot Corporation ("Cabot"), was
incorporated December 1989. Effective December 15, 1989, Cabot transferred all
of its oil and gas business segment to the Company by contributing the capital
stock of each of three subsidiary companies. Because each of such subsidiaries
was an entity under the common control of Cabot, this transfer was accounted for
in a manner similar to a pooling of interest.
In February 1990, the Company completed its initial public offering (the
"IPO") of 3,565,000 shares of Class A Common Stock ("Common Stock"), consisting
of approximately 18% of the total outstanding shares of Common Stock and,
accordingly, ceased to be a wholly-owned subsidiary of Cabot. In connection with
the IPO, the Company effected a financial restructuring pursuant to which (i)
Cabot issued to the Company an $85 million promissory note (the "Cabot Note") to
evidence a portion of the net intercompany receivable owed to the Company by
Cabot and (ii) the Company distributed to Cabot the remaining net intercompany
receivables of approximately $29.6 million.
On March 28, 1991, Cabot completed an exchange offer in which approximately
90% of the shares of the Common Stock held by Cabot were exchanged for tendered
shares of Cabot common stock. In connection with the transaction, Cabot paid the
Company the principal and interest due on the Cabot Note, and the Company paid a
special dividend on its Class B Common Stock (all of which was owned by Cabot)
in an equal amount. The Class B Common Stock owned by Cabot was then exchanged
for Common Stock. Thereafter, the remaining Common Stock owned by Cabot
(including the shares issued in exchange for the Class B Common Stock) was
distributed pro rata to the remaining shareholders of Cabot as a special
dividend on April 25, 1991. Following the completion of the exchange offer and
the special dividend (collectively, the "Stock Exchange"), the Company became
100% publicly-owned and ceased to be a subsidiary of Cabot.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of the Company include the accounts
of Cabot Oil & Gas Corporation and its subsidiaries after elimination of all
significant intercompany balances and transactions. The results of operations of
certain oil and gas properties, acquired in two separate transactions, have been
included with those of the Company since May 3, 1993 and September 30, 1993 (See
Note 13. Property Acquisitions).
Pipeline Exchanges
Natural gas gathering and pipeline operations normally include exchange
arrangements with customers and suppliers. The volumes of natural gas due to or
from the Company under exchange agreements are recorded at average selling or
purchase prices, as the case may be, and are adjusted monthly to reflect market
changes. The net value of exchanged natural gas is included in inventories in
the consolidated balance sheet.
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and
gas producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized
33
18
when incurred. Exploration costs, including geological and geophysical costs,
the costs of carrying and retaining unproved properties and exploratory dry hole
drilling costs, are expensed. Development costs, including the costs to drill
and equip development wells, and successful exploratory drilling costs that
locate proved reserves, are capitalized.
Capitalized costs of proved oil and gas properties, after considering
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values, are depreciated and depleted on a property-by-property basis by
the unit-of-production method using proved developed reserves. The costs of
unproved oil and gas properties are generally aggregated and amortized over a
period that is based on the average holding period for such properties and the
Company's experience of successful drilling. Properties related to gathering and
pipeline systems and equipment are depreciated using the straight-line method
based on estimated useful lives ranging from 10 to 25 years. Certain other
assets are also depreciated on a straight-line basis.
Future estimated plug and abandonment cost is accrued and amortized over
the productive life of the oil and gas properties. The accrued liability for
plug and abandonment cost is included in accumulated depreciation, depletion and
amortization.
Upon the sale or retirement of a property, the cost and related accumulated
depreciation, depletion, and amortization are removed from the consolidated
financial statements, and the resultant gain or loss, if any, is recognized.
Production Imbalances
Natural gas production operations normally include joint interest owners
who may take more or less than their interest ownership of natural gas volumes
from jointly owned reservoirs. Volumetric production is monitored to minimize
imbalances. The Company follows the sales method of accounting for imbalances;
however, a liability is recorded if takes of natural gas volumes from jointly
owned reservoirs exceed the Company's interest in the reservoir's remaining
estimated natural gas reserves. The liability is recorded in other liabilities
in the consolidated balance sheet.
Income Taxes
The Company follows an asset and liability approach in accounting for
income taxes in accordance with the Financial Accounting Standards ("SFAS") 109,
adopted in 1992. Deferred assets and liabilities are determined using the tax
rate for the period in which those amounts are expected to be received or paid.
Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances or imbalances resulting from such calculations
are inherent in natural gas sales, production, operation, measurement, and
administration. Management does not believe that differences between actual and
estimated natural gas revenues or purchase costs attributable to the unresolved
variances or imbalances are material.
Accounts Payable
This account includes credit balances to the extent that checks issued have
not been presented to the Company's bank for payment. These credit balances
included in accounts payable were approximately $6.1 million and $5.3 million at
December 31, 1993 and 1992, respectively.
34
19
Earnings Per Common Share
Earnings per common share is computed by dividing net income, as adjusted
for dividends on preferred stock in 1993 and earnings dedicated to Class B
Common Stock in 1991, by the weighted average number of common shares
outstanding during the respective periods. The dilutive effect of unexercised
stock options on earnings per common share is insignificant for all periods and
is not included in the computation of earnings per common share.
The $3.125 cumulative convertible preferred stock ("preferred stock"),
issued May 1993, had an antidilutive effect on earnings per common share in
1993. At the time of issuance, the preferred stock was determined not to be a
common stock equivalent.
Risk Management Activities
The Company has entered into certain gas price swap agreements ("price
swaps") in 1993. These price swaps call for payments to (or to receive payments
from) counterparties based upon the differential between a fixed and a variable
gas price. Gains or losses on hedging activities are recognized in revenues over
the period that production is hedged. Unrealized gains or losses on all other
price swap activities are recognized currently.
The Company has also entered into certain interest rate swap agreements.
The difference paid or received under such agreements is charged or credited to
interest expense over the term of the agreements.
3. INVENTORIES
Inventories are comprised of the following:
DECEMBER 31,
-------------------
1993 1992
------- -------
(IN THOUSANDS)
Natural gas in storage $ 4,722 $ 3,911
Tubular goods and well equipment 1,712 1,454
Exchange balances (741) 393
------- -------
$ 5,693 5,758
------- -------
------- -------
4. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
DECEMBER 31,
-----------------------
1993 1992
---------- --------
(IN THOUSANDS)
Unproved oil and gas properties $ 12,277 $ 12,485
Proved oil and gas properties 533,110 432,880
Gathering and pipeline systems 134,262 127,595
Land, buildings and improvements 7,376 5,580
Other 11,554 10,872
-------- --------
698,579 589,412
-------- --------
Accumulated depreciation, depletion and amortization (298,309) (282,689)
-------- --------
$400,270 $306,723
-------- --------
-------- --------
35
20
Accumulated depreciation, depletion and amortization includes an accrued
liability for future plug and abandonment cost of $14.3 million and $13.4
million at December 31, 1993 and 1992, respectively. At December 31, 1993, the
Company's total future plug and abandonment cost was estimated to be $25.8
million.
5. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
DECEMBER 31,
---------------------
1993 1992
-------- --------
(IN THOUSANDS)
Accounts Receivable
Trade accounts $ 32,527 $ 32,910
Income taxes 1,660 --
Other accounts 1,753 2,071
-------- --------
35,940 34,981
Allowance for doubtful accounts (644) (465)
-------- --------
$ 35,296 $ 34,516
-------- --------
-------- --------
Accounts Payable
Trade accounts $ 8,727 $ 8,662
Income taxes -- 514
Natural gas purchases 4,301 5,414
Royalty and other owners 5,445 1,943
Capital costs 5,721 1,651
Other accounts 2,344 1,602
-------- --------
$ 26,538 $ 19,786
-------- --------
-------- --------
Accrued Liabilities
Employee benefits $ 3,702 $ 3,746
Taxes other than income 3,437 3,975
Interest payable 1,092 1,300
Other accrued 1,992 2,157
-------- --------
$ 10,223 $ 11,178
-------- --------
-------- --------
Other Liabilities
Postretirement benefits other than pensions $ 1,764 $ 1,800
Accrued pension cost 1,964 1,437
Taxes other than income 2,176 2,178
Other 579 554
-------- --------
$ 6,483 $ 5,969
-------- --------
-------- --------
6. DEBT AND CREDIT AGREEMENTS
Short-Term Debt
The Company has a $5.0 million unsecured short-term line of credit with a
bank which it uses as part of its cash management program. At December 31, 1993,
$0.5 million is outstanding and bears interest at the bank's prime rate.
36
21
Senior Notes
In May 1990, the Company issued an aggregate principal amount of $80
million of its 12-year 10.18% senior notes (the "Senior Notes") to a group of
nine institutional investors in a private placement offering. The Senior Notes
require five equal annual principal payments beginning in 1998. The proceeds
from the Senior Notes were used to retire the $80 million Term Loan, as defined
below. The Company may prepay all or any portion of the indebtedness on any date
with a prepayment premium. The Senior Notes contain restrictions on the merger
of the Company or any subsidiary with a third party other than under certain
limited conditions, as well as various other restrictive covenants customarily
found in such debt instruments, including a restriction on the payment of
dividends or the repurchase of equity securities. Such covenants about dividends
and equity securities are less restrictive than the covenants contained in the
Credit Facility referred to below.
Revolving Credit Agreement
In January 1990, the Company entered into an $85 million Revolving Credit
and $80 million Term Loan Agreement (the "Credit Facility" and the "Term
Loan," respectively) with a bank (later expanded to four banks). The $80 million
Term Loan was retired in May 1990 when the Senior Notes were issued. In 1993,
the Company amended certain terms of its Credit Facility, including an increase
in the available credit line, an extension of the revolving term to June 1995
and an extension of the maturity date to June 2001. The available credit line is
subject to adjustment from time-to-time on the basis of the projected present
value (as determined by a petroleum engineer's report incorporating certain
assumptions provided by the lender) of estimated future net cash flows from
certain proved oil and gas reserves and other assets of the Company. If
supported by such an adjustment, the available credit line may be increased up
to $210 million. At present the Company's available credit line is $180 million.
Interest rates are principally based on a reference rate (plus a margin) of
either the prime rate, the rate for certificates of deposit ("CD rate"), or the
LIBOR rate. The margin above the reference rate is presently equal to 3/4 of 1%
for the LIBOR based rate, 7/8 of 1% for the CD based rate, and 1/4 of 1% for the
prime based rate. The Credit Facility provides for a commitment fee on the
unused available balance at an annual rate of 3/8 of 1% and a commitment fee on
the unavailable balance of the credit line at an annual rate of 1/4 of 1%.
Although the revolving term of the Credit Facility expires in June 1995, it may
be extended with the banks' approval. If such term is not extended, the
indebtedness outstanding will be payable in 24 quarterly installments. Interest
rates and commitment fees are subject to increase if the indebtedness is greater
than 80% of the Company's debt limit of $260 million, as noted below. The Credit
Facility contains various restrictive covenants customarily found in such
facilities, including restrictions (i) prohibiting the merger of the Company or
any subsidiary with a third party other than under certain limited conditions,
(ii) prohibiting the sale of all or substantially all of the Company's or any
subsidiary's assets to a third party, and (iii) restricting certain payments
associated with repurchasing equity securities of the Company or declaring
dividends ("Restricted Payments", as defined in the Credit Facility), if
immediately prior to or after giving effect to such payments, the aggregate of
such Restricted Payments exceeds 15% of cash flows available for debt service,
as defined in the Credit Facility, or an event of default has occurred under the
Credit Facility. In addition, the Credit Facility prohibits the Company and its
subsidiaries from incurring recourse indebtedness (determined on a consolidated
basis) in excess of the debt limit (presently $260 million) subject to certain
adjustments, including sales or acquisitions of oil and gas properties and other
changes in projected cash flows available for debt service.
37
22
7. EMPLOYEE BENEFIT PLANS
Pension Plan
The Company has a noncontributory defined benefit pension plan covering all
full-time employees. The benefits for this plan are based primarily on years of
service and pay near retirement. Plan assets consist principally of fixed income
investments and equity securities. The Company funds the plan as determined in
accordance with the Employee Retirement Income Security Act of 1974 and Internal
Revenue Code limitations.
The Company has a non-qualified equalization plan to ensure payments to
certain executive officers of amounts to which they are already entitled under
the provisions of the pension plan, but which are subject to limitations imposed
by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company for the years ended December 31,
1993, 1992 and 1991 is comprised of the following:
1993 1992 1991
------- ------ -------
(IN THOUSANDS)
Qualified
Current year service cost $ 816 $ 787 $ 848
Interest accrued on pension obligation 578 542 490
Actual return on plan assets (366) (342) (478)
Net amortization 118 124 308
Other, net -- (183)(1) --
------ ----- ------
Net Periodic Pension Cost $1,146 $ 928 $1,168
------ ----- ------
------ ----- ------
Non-Qualified
Current year service cost $ 84 $ 49 $ 111
Interest accrued on pension obligation 5 13 33
Net amortization 33 20 22
Other, net -- 268(2) --
------ ----- ------
Net Periodic Pension Cost $ 122 $ 350 $ 166
------ ----- ------
------ ----- ------
- ---------------
(1) In accordance with SFAS 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Plans and for Termination Benefits," the
Company recorded a $183,000 net curtailment gain in the qualified plan for
1992 as a result of the cost reduction program which reduced the Company's
work force by 12%.
(2) Reflects the impact of a special early retirement election by an executive
officer. Based on SFAS 88, the Company recorded a charge to earnings of
approximately $370,000 for a special termination benefit and recognized a
$102,000 net settlement gain. The termination and retirement liabilities
were settled by a lump sum payment to the retiring executive.
38
23
The following table sets forth the funded status of the Company's pension
plans at December 31, 1993 and 1992, respectively:
1993 1992
----------------------- -----------------------
NON- NON-
QUALIFIED QUALIFIED QUALIFIED QUALIFIED
-------- --------- --------- ---------
(IN THOUSANDS)
Actuarial present value of:
Vested benefit obligation $ 3,481 $ -- $ 2,363 $ --
Accumulated benefit obligation 4,090 126 2,796 33
Projected benefit obligation $ 8,737 $ 421 $ 7,038 $ 63
Plan assets at fair value (primarily
fixed-income and equity securities) 4,243 -- 3,989 --
-------- ------ -------- -----
Projected benefit obligation in excess of plan
assets (4,494) (421) (3,049) (63)
Unrecognized net (gain) loss 121 137 (771) 152
Unrecognized prior service cost 1,418 581 1,813 330
-------- ------ -------- -----
Prepaid (Accrued) Pension Cost $ (2,955) $ 297 $ (2,007) $ 419
-------- ------ -------- -----
-------- ------ -------- -----
Assumptions used to determine benefit obligations and pension costs are as
follows:
1993 1992 1991
---- ---- ----
Discount rate 7.50% 8.75%(1) 8.75%
Rate of increase in compensation levels 5.50% 6.00% 6.00%
Long-term rate of return on plan assets 9.00% 9.00% 9.00%
- ---------------
(1) Represents the discount rate used to compute pension costs. An 8.25%
discount rate was used to determine the benefit obligations.
Savings Investment Plan
The Company has a Savings Investment Plan (the "SIP") which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.7 million, $0.7 million and $0.7 million in 1993, 1992, and 1991,
respectively.
Postretirement Benefits Other Than Pensions
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees ("postretirement
benefits"). Substantially all employees become eligible for these benefits if
they meet certain age and service requirements at retirement. Through 1991, the
cost of postretirement benefits was recognized as expense upon payment of claims
or insurance premiums. The Company recorded $0.4 million in 1991 for costs to
provide postretirement benefits to 230 retirees, spouses, eligible dependents
and surviving spouses ("retirees") of the Company. The Company was providing
postretirement benefits to 244 retirees and 250 retirees at the end of 1992 and
1993, respectively.
Effective January 1, 1992, the Company adopted SFAS 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." The Statement
requires employers to recognize the cost of providing postretirement benefits to
employees over the employees' service period. The
39
24
Company elected to amortize the accumulated postretirement benefit obligation at
January 1, 1992 (the "Transition Obligation") of $16.9 million over 20 years.
Effective January 1, 1993, the Company amended its postretirement medical
benefits. The effect of this amendment will significantly reduce the Company's
postretirement benefit costs and the accumulated postretirement benefit
obligation. The amendment prospectively reduces the unrecognized Transition
Obligation by $9.8 million and such reduction will be amortized over a 5.75 year
period beginning in 1993. Accordingly, the amortization cost of the unrecognized
Transition Obligation for 1993 was reduced $1.7 million due to this amendment.
Postretirement benefit costs recognized in the years ended December 31,
1993 and 1992 are comprised of the following:
1993 1992
------ -------
(IN THOUSANDS)
Service cost of benefits earned during the year $ 210 $ 558
Interest cost on the accumulated postretirement benefits obligation 667 1,367
Amortization cost of the unrecognized Transition Obligation (858) 846
------ -------
Total Postretirement Benefit Costs $ 19 $ 2,771
------ -------
------ -------
The health care cost trend rates used to measure the expected cost in 1994
for medical benefits to retirees over age 65 were 12.0% graded down to a trend
rate of 0% in 1997. The health care cost trend rates used for retirees under age
65 were 18.0% in 1993 graded down to a trend rate of 0% in 1997. Provisions of
the plan should prevent further increases in employer cost after 1997.
The weighted average discount rate used in determining the actuarial
present value of the benefit obligation at December 31, 1993 and 1992 was 7.5%
and 8.25%, respectively.
A one-percentage-point increase in health care cost trend rates for future
periods would increase the accumulated net postretirement benefit obligation by
approximately $249 thousand and, accordingly, the total postretirement benefit
cost recognized in 1993 would have also increased by approximately $31 thousand.
The funded status of the Company's postretirement benefit obligation at
December 31, 1993 and 1992 are comprised of the following:
1993 1992
-------- ---------
(IN THOUSANDS)
Plan assets at fair value $ -- $ --
Accumulated postretirement benefits other than pensions
Retirees 5,023 11,316
Active participants 1,474 6,914
-------- ---------
6,497 18,230
Unrecognized cumulative net gain 2,755 304
Unrecognized Transition Obligation (7,131) (16,074)
-------- ---------
Accrued Postretirement Benefit Liability $ 2,121 $ 2,460
-------- ---------
-------- ---------
40
25
8. INTEREST INCOME
YEAR ENDED DECEMBER 31,
---------------------------
1993 1992 1991
---- ---- -------
(IN THOUSANDS)
Interest income
Cabot Note $ -- $ -- $ 1,777
Other 8 6 23
---- ---- -------
$ 8 $ 6 $ 1,800
---- ---- -------
---- ---- -------
9. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Current
Federal $ (796) $ 7,145(2) $ 1,794
State (103) 198 369
-------- -------- --------
Total (899) 7,343 2,163
-------- -------- --------
Deferred
Federal 4,909(1) (6,440)(2) (2,196)
State 2,149 5,096 4,845
-------- -------- --------
Total 7,058 (1,344) 2,649
-------- -------- --------
Total Income Tax Expense $ 6,159 $ 5,999 $ 4,812
-------- -------- --------
-------- -------- --------
- ---------------
(1) Deferred tax liability was reduced by a $0.8 million alternative minimum tax
adjustment in 1993.
(2) Alternative minimum tax expense for 1992 of $4.2 million, less a 1991
accrual adjustment of $0.3 million, was offset against the existing
deferred tax liability.
Total income taxes were different than the amounts computed by applying the
statutory federal income tax rate as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Statutory federal income tax rate 35% 34% 34%
Computed "expected" federal income tax $ 3,388 $ 2,797 $ 2,078
Tax credits, net of recapture -- -- (709)
State income tax, net of federal income tax 1,330 3,494 3,443
Tax settlement, net -- 444 --
Other, net 1,441 (736) --
-------- -------- --------
Total Income Tax Expense $ 6,159 $ 5,999 $ 4,812
-------- -------- --------
-------- -------- --------
Income taxes for the year ended December 31, 1993 were increased by $2.3
million due to a change in the federal income tax rate.
41
26
Effective June 30, 1992, the Company took a charge against income of $2.7
million, or 13 cents per share, to reflect the settlement of the previously
disclosed tax dispute with Cabot concerning Cabot's demand for federal and state
taxes for the years ended September 30, 1990 and 1989. In conjunction with the
settlement, Cabot also assumed the responsibility for most potential audit
adjustments of federal and consolidated state tax returns filed for all periods
the Company was consolidated into Cabot's tax returns.
Income taxes for the year ended December 31, 1991 were increased by $3.1
million due to a change in a state tax law no longer allowing unused state net
loss carryforwards. For financial reporting purposes, all net loss carryforwards
in that state had been utilized prior to 1991.
As discussed in Note 2. Summary of Significant Accounting Policies, the
Company adopted SFAS 109 in 1992. The Company had adopted, in 1988, the
liability method of computing deferred income taxes under SFAS 96. The Company
realized no cumulative effect of the accounting change on prior years and,
accordingly, no effect on net income for prior years is reported in the
Consolidated Statement of Income.
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1993 and 1992 were as follows:
1993 1992
-------- --------
(IN THOUSANDS)
Deferred tax liabilities:
Property, plant and equipment, due to differences in depreciation,
depletion and amortization $ 89,871 $ 79,097
-------- --------
Deferred tax assets:
Minimum tax credit carryforwards 3,912 4,174
Net operating loss credit carryforwards 3,809 320
Deferred compensation/retirement related items accrued for financial
reporting purposes 3,452 2,963
-------- --------
Net deferred tax assets 11,173 7,457
-------- --------
Net Deferred Tax Liabilities $ 78,698 $ 71,640
-------- --------
-------- --------
At December 31, 1993, the Company has a net operating loss carryforward for
regular income tax reporting purposes of $3.8 million which will begin expiring
in 2006. In addition, the Company has an alternative minimum tax credit
carryforward of $3.9 million which does not expire and is available to offset
regular income taxes in future years to the extent that regular income taxes
exceed the alternative minimum tax in any such year.
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities,
office space and machinery and equipment under cancelable and non-cancelable
leases, most of which expire within five years and may be renewed by the
Company. Rent expense under such arrangements totalled $5.0 million, $5.1
million and $5.6 million for the years ended December 31, 1993, 1992 and 1991,
42
27
respectively. Future minimum rental commitments under non-cancelable leases in
effect at December 31, 1993 are as follows:
(IN
THOUSANDS)
1994 $ 4,236
1995 1,403
1996 793
1997 431
1998 109
-------
$ 6,972
-------
-------
Minimum rental commitments are not reduced by minimum sublease rental
income of $1.3 million due in the future under non-cancelable subleases.
Contingencies
The Company is a defendant in various lawsuits and is involved in other gas
contract issues. In the opinion of the Company, these suits and claims should
not result in final judgments or settlements which, in the aggregate, would have
a material adverse effect on the Company's financial position.
In July 1992, the John Hancock Mutual Life Insurance Company ("John
Hancock") asserted that as a result of the operation by the Company of certain
wells in northwestern Pennsylvania jointly owned by John Hancock and the Company
(the "Properties"), a permanent diminution of up to 5.1 Bcfe in the oil and gas
reserves available from the Properties has occurred. John Hancock has also
asserted that the value of its loss resulting from such diminution in reserves
is approximately $6 million. Since that time, management, along with its outside
technical advisors, has undertaken a comprehensive and continuing review of its
operating practices related to the Properties. Based upon that review,
management believes that its operation of the Properties has been appropriate.
While the Company cannot predict the ultimate outcome of the claim, the Company
believes that the resolution of the claim will not have a material adverse
effect on the Company's financial position.
11. CASH FLOW INFORMATION
Cash paid to third parties for interest and income taxes is as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------
1993 1992 1991
-------- -------- -------
(IN THOUSANDS)
Interest $ 10,536 $ 9,668 $ 9,384
Income Taxes $ 1,282 $ 10,010 $ 888
The "Cabot Note" line in the Consolidated Statement of Cash Flows
represents the after-tax change in the interest income receivable due from Cabot
on the Cabot Note.
The Company considers all highly liquid short-term investments with
original maturities of three months or less to be cash equivalents. At December
31, 1993, the majority of cash and cash equivalents is concentrated in one
financial institution. Additionally, the Company has accounts receivable that
are subject to credit risk.
43
28
12. CAPITAL STOCK
At December 31, 1993, 3,208,664 shares of Common Stock were reserved for
issuance under various employee incentive plans and for conversion of certain
convertible securities of the Company.
Stock Options
The Company has in place an Incentive Stock Option Plan (the "Incentive
Plan") which provides for granting incentive stock options, non-statutory stock
options and stock appreciation rights and the 1990 Non-Employee Director Stock
Option Plan (the "Director Plan") which provides for granting non-statutory
stock options to the Company's Board of Directors. A maximum of 1,000,000 shares
and 60,000 shares of Common Stock, par value $.10 per share, are subject to
issuance under the Incentive Plan and the Director Plan, respectively. Under the
two plans, incentive and non-statutory stock options have a maximum term of ten
years from the date of grant and vest over time. The options are issued at
market value on the date of grant. The minimum exercise period for stock options
issued under the Incentive and Director Plans is six months from the date of
grant. Information regarding the Company's stock option plans is summarized
below:
DECEMBER 31,
---------------------------------------
1993 1992 1991
--------- --------- ---------
Shares under option at beginning of period 639,200 439,750 453,900
Granted 197,300 302,700 10,000
Exercised 126,835 -- --
Surrendered or expired 25,140 103,250(1) 24,150
Shares under option at end of period 684,525 639,200 439,750
Option price range per share at end of period $ 13.25 $ 13.25 $ 15.63
$ 26.00 $ 17.19 $ 16.25
Options exercisable at end of period 236,120 316,340 183,025
- ---------------
(1) Options surrendered of 100,000 were replaced with the granting of 100,000
stock appreciation rights ("SARs") (not issued under the Incentive Plan)
with a base price of $16.125. On April 1, 1993, such SARs were exercised in
full.
Dividend Restrictions
The determination of the amount of future cash dividends, if any, to be
declared and paid on the Common Stock will be subject to the discretion of the
Board of Directors of the Company and will depend upon, among other things, the
Company's financial condition, funds from operations, the level of its capital
and exploration expenditures and its future business prospects. The Company's
credit agreements restrict certain payments ("Restricted Payments," as defined
in the credit agreements) associated with (i) purchasing, redeeming, retiring or
otherwise acquiring any capital stock of the Company or any option, warrant or
other right to acquire such capital stock or (ii) declaring any dividend, if
immediately prior to or after giving effect to such payments, the aggregate of
such Restricted Payments exceeds 15% of cash flows available for debt service,
as defined in the Credit Agreement, or an event of default has occurred under
the credit agreements. As of December 31, 1993, such restrictions had no adverse
impact on the Company's ability to pay regular dividends.
44
29
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. Each right becomes exercisable, at a price of
$55, when any person or group has acquired, obtained the right to acquire or
made a tender or exchange offer for beneficial ownership of 15 percent or more
of the Company's outstanding Common Stock, except pursuant to a tender or
exchange offer for all outstanding shares of Common Stock deemed to be fair and
in the best interests of the Company and its stockholders by a majority of the
independent Continuing Directors (as defined in the plan). Each right entitles
the holder, other than the acquiring person or group, to purchase one-one
hundredth of a share of Series A Junior Participating Preferred Stock ("Junior
Preferred Stock"), or to receive, after certain triggering events, Common Stock
or other property having a market value of twice the exercise price of each
right. After the rights become exercisable, if the Company is acquired in a
merger or other business combination where it is not the survivor or 50 percent
or more of the Company's assets or earning power is sold or transferred, each
right entitles the holder to purchase common stock of the acquiring company with
a market value equal to twice the exercise price of each right. At December 31,
1993, there were no shares of Junior Preferred Stock issued.
The rights, which expire on January 21, 2001, and the exercise price are
subject to adjustment and may be redeemed by the Company for $0.01 per right any
time before they become exercisable. Under certain circumstances, the Continuing
Directors may opt to exchange one share of Common Stock for each exercisable
right.
Preferred Stock
The Company issued 692,439 shares of $3.125 cumulative convertible
preferred stock to Harvard University in connection with an oil and gas property
acquisition (See Note 13. Property Acquisitions). Each share has a stated value
of $50 and is convertible at any time by the holder into Common Stock at a
conversion price of $21 per share ("conversion price"), subject to adjustment.
The preferred stock is redeemable by the Company for a stated redemption price
per share, starting at $55 per share in 1993 declining to $50 per share in 2003,
plus accrued dividends. Prior to May 31, 1997, the Company's option to redeem
the preferred stock is subject to a provision that the Common Stock closing
price must equal at least 130% of the conversion price for 20 of 30 consecutive
trade days. The Company also has the option to convert the preferred stock to
Common Stock at the conversion price provided the Company has the right to
redeem the preferred stock, as described above, and the closing price of the
Common Stock is at least equal to the conversion price for 20 consecutive
trading days.
13. PROPERTY ACQUISITIONS
Anadarko Region
In May 1993, the Company purchased oil and natural gas properties located
in the Anadarko Region of Texas and Oklahoma, and in the East Texas Basin from
Harken Anadarko Partners, L.P. (the "Harvard Acquisition"). The Company issued
692,439 shares of $3.125 convertible preferred stock to Harvard University. The
preferred stock has a total stated value of $34.6 million, or $50 per share, and
is convertible, subject to certain adjustments, into 1,648,662 shares of Common
Stock at $21 per share, also subject to certain adjustments. As of the
acquisition date, the properties had approximately 38.2 billion cubic feet
equivalent of proved reserves which are 80% natural gas and included 518 (166
net) wells, of which almost 45% are operated by the Company. Average net daily
production on these properties in 1993 was 10.95 million cubic feet equivalent
("MMcfe").
45
30
Appalachian Region
In September 1993, the Company purchased oil and natural gas properties and
related assets located in the Appalachian Region of West Virginia and
Pennsylvania from Emax Oil Company (the "Emax Acquisition") for cash of
approximately $44.1 million, subject to certain adjustments. As of the
acquisition date, the properties had approximately 47.1 billion cubic feet
equivalent of proved reserves of which 99% are natural gas. The properties
include 300 (291 net) wells, all but one of which are operated by the Company.
Average net daily production on these properties in 1993 was 8.70 MMcfe. As part
of the acquisition, the Company entered into a development agreement that
provides for the acquisition of additional drilling locations for approximately
$106 thousand per location. The agreement provides for the drilling of 78 such
wells under a farmout from a local producer. Total expected drilling costs for
these 78 wells are estimated at $13.6 million. The Company drilled 22 of these
wells in 1993, which added approximately 5.2 Bcfe to the proved reserves
acquired and increased the total acquisition cost by $2.3 million. At year end,
the Company had identified 69 future drilling locations, including the remaining
locations associated with the farmout agreement mentioned above. The pro forma
results of operations, presented below, includes the results from the 300 wells
acquired in September 1993.
The following represents the pro forma results of operations as if the
Harvard Acquisition and the Emax Acquisition had occurred at the beginning of
the current year, as well as the preceding year:
1993 1992
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
Total Revenue $ 173,608 $ 165,206
Net Income Available to Common Shares 3,220 3,064
Earnings per Common Share $ 0.16 $ 0.15
The preceding results of operations presented above does not purport to be
indicative of the results of future operations, nor the results of historical
operations had the two acquisitions occurred as of the assumed dates.
14. MAJOR CUSTOMER
The Company had sales to no customer which exceeded 10 percent of the
Company's revenues in the years ended December 31, 1993, 1992 and 1991.
15. COST REDUCTION PROGRAM
The Company recorded a $2.4 million non-recurring charge in the fourth
quarter of 1991 for a cost reduction program. The cost reduction program
provided for a 12% reduction in the Company's work force by year-end 1992. The
cost of the program includes severance, relocation and other related expenses.
16. POSTEMPLOYMENT BENEFITS
Prior to 1993, postemployment benefit expenses were recognized on a
pay-as-you-go basis. In the fourth quarter of 1993, the Company adopted,
retroactive to January 1, 1993, SFAS 112, "Employers' Accounting for
Postemployment Benefits." There was no cumulative effect attributable to the
change in accounting for postemployment benefits. The effect of this change on
1993 operating results was an increase in postemployment benefit expense of $0.6
million, or $0.4 million after taxes.
46
31
17. FINANCIAL INSTRUMENTS
The following disclosures on the estimated fair value of financial
instruments are presented in accordance with SFAS 107, Disclosures about Fair
Value of Financial Instruments. Fair value, as defined in SFAS 107, is the
amount at which the instrument could be exchanged currently between willing
parties. The Company uses available marketing data and valuation methodologies
to estimate the fair value of debt.
DECEMBER 31, 1993 DECEMBER 31, 1992
------------------------ ------------------------
ESTIMATED ESTIMATED
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
--------- --------- --------- ---------
(IN THOUSANDS)
Debt
Senior Notes $ 80,000 $ 95,000 $ 80,000 $ 90,100
Credit Facility 89,000 89,000 40,000 40,000
Short-Term Line 530 530 1,810 1,810
--------- --------- --------- ---------
$ 169,530 $ 184,530 $ 121,810 $ 131,910
--------- --------- --------- ---------
--------- --------- --------- ---------
Other Financial Instruments
Interest Rate Swaps $ -- $ (184) $ -- $ --
Price Swaps -- 45 -- --
Long-Term Debt
The fair value of long-term debt is the estimated cost to acquire the debt,
including a premium or discount for the differential between the issue rate and
the year-end market rate.
Interest Rate Swap Agreements
In November 1993, the Company executed interest rate swap agreements with
four banks that effectively converted the Company's $80 million fixed rate notes
into variable rate notes. Under the swap agreements, the Company will pay a
variable rate of interest that is tied to the six-month LIBOR. The banks will
pay the Company fixed rates of interest that average 5.00%. The four agreements
have notional principal of $20 million each with terms of two, three, four and
five years. The fair value is determined by obtaining termination values from
third parties (See Note 2. "Risk Management Activities").
Price Swaps
In 1993, the Company entered into certain price swap agreements. The
estimated fair value of price swaps presented above are for hedged transactions
in which gains or losses are recognized in revenues over the periods that
production is hedged. The current price swaps run for periods of a year or less
and have a remaining notional contract amount of 4,080,000 MMbtu of natural gas
at December 31, 1993 (See Note 2. "Risk Management Activities").
Credit Risk
While notional contract amounts are used to express the volume of price and
interest rate swap agreements, the amounts potentially subject to credit risk,
in the event of nonperformance by third parties, are substantially smaller. The
Company does not anticipate any material impact to its results of operations as
a result of nonperformance by the third parties.
47
32
18. SUBSEQUENT EVENT
On February 25, 1994, the Company entered into an agreement with Washington
Energy Company ("WECO") to merge its subsidiary, Washington Energy Resources
Company ("WERCO"), into a subsidiary of the Company (the "Merger Agreement").
The Company will acquire the common stock of WERCO in a tax-free exchange for
total consideration of $180 million, subject to adjustment. At January 1, 1994,
WERCO held 230 Bcfe of proved reserves (82% natural gas); produced 376 wells
(116 net wells); and operated 184 wells (87 net wells). Daily net production
from such properties is currently 43 MMcf of natural gas, 450 barrels of natural
gas liquids and 1,550 barrels of oil and condensate.
The Company will issue 2,133,000 shares of Common Stock and 1,134,000
shares of 6% convertible redeemable preferred stock ("6% preferred stock") in
exchange for the common stock of WERCO. The 6% preferred stock has a stated
value of $50.00 per share and is convertible into 1,972,174 shares of Common
Stock at $28.75 per share. In addition, the Company will advance cash to repay
intercompany indebtedness outstanding at closing and assume $5.9 million of
third-party debt. The intercompany debt of WERCO was $69.1 million at December
31, 1993, as adjusted.
The closing of the transaction is contingent upon several conditions,
including the successful transfer of certain contractual arrangements from
WERCO's marketing affiliate to a subsidiary of WECO and a condition that would
allow WECO to terminate the transaction should the Company's average Common
Stock price fall below $19 during a defined ten day trading period (the Company
may cure this deficit in cash up to $10 million). The Company anticipates the
transaction will close by the end of April.
48
33
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil
and condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Estimates of proved reserves and proved developed reserves at December 31,
1993, 1992 and 1991 were based on studies performed by the Company's petroleum
engineering staff. The estimates prepared by the Company's engineering staff
were reviewed by Miller and Lents, Ltd., who indicated in their recent letter
dated February 11, 1994 that, based on their investigation and subject to the
limitations described in such letter, it was their judgement that the results of
those estimates and projections for 1993 were reasonable in the aggregate.
No major discovery or other favorable or adverse event subsequent to
December 31, 1993 is believed to have caused a material change in the estimates
of proved reserves or proved developed reserves as of that date.
The following table sets forth the Company's net proved reserves, including
changes therein, and proved developed reserves for the periods indicated, as
estimated by the Company's engineering staff (all reserves within the United
States):
NATURAL GAS
-----------------------------------
DECEMBER 31,
-----------------------------------
1993 1992 1991
------- ------- -------
(MILLIONS OF CUBIC FEET)
PROVED RESERVES
Beginning of year 724,666 716,450 726,287
Revisions of prior estimates (18,270) (8,947) (34,851)
Extensions, discoveries
and other additions 58,265 56,875 66,133
Production (46,050) (45,466) (43,687)
Purchases of reserves in place 93,131 5,771 5,994
Sales of reserves in place (3,462) (17) (3,426)
--------- --------- ---------
End of Year 808,280 724,666 716,450
--------- --------- ---------
--------- --------- ---------
PROVED DEVELOPED RESERVES 669,672 583,673 570,665
--------- --------- ---------
--------- --------- ---------
49
34
CRUDE OIL
-----------------------------------
DECEMBER 31,
-----------------------------------
1993 1992 1991
------- ------- -------
(THOUSANDS OF BARRELS)
PROVED RESERVES
Beginning of year 1,799 1,213 1,316
Revisions of prior estimates (355) 235 (29)
Extensions, discoveries and other additions 437 511 110
Production (345) (162) (148)
Purchases of reserves in place 1,331 3 5
Sales of reserves in place (41) (1) (41)
------- ------- -------
End of Year 2,826 1,799 1,213
------- ------- -------
------- ------- -------
PROVED DEVELOPED RESERVES 2,346 1,510 1,204
------- ------- -------
------- ------- -------
Capitalized Costs Relating to Oil and Gas Producing Activities
The aggregate amount of capitalized costs relating to natural gas and crude
oil producing activities and the aggregate amount of related accumulated
depreciation, depletion and amortization (all within the United States) were as
follows:
DECEMBER 31,
-------------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Aggregate capitalized costs relating to oil and gas
producing activities $ 696,520 $ 587,213 $ 550,737
--------- --------- ---------
--------- --------- ---------
Aggregate accumulated depreciation, depletion and
amortization $ 296,764 $ 281,280 $ 250,892
--------- --------- ---------
--------- --------- ---------
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities and Finding and Development Costs of Proved Reserves
Costs incurred in property acquisition, exploration and development
activities were as follows:
YEAR ENDED DECEMBER 31,
---------------------------------
1993 1992 1991
--------- -------- --------
(IN THOUSANDS)
Property acquisition costs -- unproved $ 3,893 $ 1,891 $ 2,517
Exploration and extension wells cost 7,487 6,703 9,933
Development costs 31,391 19,443 28,249
--------- -------- --------
Total finding and development costs 42,771 28,037 40,699
Property acquisition costs -- proved 82,364 1,586 902
--------- -------- --------
Total Costs $ 125,135 $ 29,623 $41,601
--------- -------- --------
--------- -------- --------
Proved reserves of extensions, discoveries and other
additions (includes crude oil converted to natural gas
equivalents), MMcfe 60,887 59,941 66,793
--------- -------- --------
Calculated finding and development cost of proved reserves
of extensions, discoveries and other additions, $/Mcfe $ 0.70 $ 0.47 $ 0.61
--------- -------- --------
50
35
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) -- (CONTINUED)
Historical Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company's oil and gas producing
activities were as follows:
YEAR ENDED DECEMBER 31,
---------------------------------
1993 1992 1991
--------- -------- --------
(IN THOUSANDS)
Operating revenues $ 105,247 $ 96,726 $ 90,475
Costs and expenses
Production 31,065 26,425 25,621
Other operating 17,476 18,081 18,970
Exploration 6,943 6,227 8,060
Depreciation, depletion and amortization 31,648 28,622 24,411
--------- -------- --------
Total cost and expenses 87,132 79,355 77,062
--------- -------- --------
Income before income taxes 18,115 17,371 13,413
Provision for income taxes 6,340 5,906 4,560
--------- -------- --------
Results of Operations $ 11,775 $ 11,465 $ 8,853
--------- -------- --------
--------- -------- --------
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following information has been developed utilizing procedures
prescribed by SFAS 69 and based on natural gas and crude oil reserve and
production volumes estimated by the Company's engineering staff. It may be
useful for certain comparison purposes, but should not be solely relied upon in
evaluating the Company or its performance. Further, information contained in the
following table should not be considered as representative of realistic
assessments of future cash flows, nor should the Standardized Measure of
Discounted Future Net Cash Flows be viewed as representative of the current
value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end oil and gas prices adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved reserves. The
average prices related to proved reserves at December 31, 1993, 1992 and 1991
were for oil ($/Bbl) $16.20, $19.90 and $19.99, respectively, and for gas
($/Mcf) $2.40, $2.42 and $2.16, respectively. Future cash inflows were reduced
by estimated future development and production costs based on year-end costs in
order to arrive at net cash flow before tax. Future income tax expense has been
computed by applying year-end statutory tax rates to future pretax net cash
flows, reduced by the tax basis of the properties involved. Use of a 10%
discount rate is required by SFAS 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves, and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
51
36
Standardized Measure is as follows:
DECEMBER 31,
---------------------------------------------
1993 1992 1991
----------- ----------- -----------
(IN THOUSANDS)
Future cash inflows $ 2,190,400 $ 1,998,543 $ 1,774,642
Future production and development costs (670,390) (593,094) (568,531)
----------- ----------- -----------
Future net cash flows before income
taxes 1,520,010 1,405,449 1,206,111
10% annual discount for estimated timing
of cash flows (878,912) (825,564) (687,042)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows before income taxes 641,098 579,885 519,069
Future income tax expenses, net of 10%
annual discount(1) (173,198) (175,308) (156,708)
----------- ----------- -----------
Standardized Measure of Discounted Future
Net Cash Flows $ 467,900 $ 404,577 $ 362,361
----------- ----------- -----------
----------- ----------- -----------
- ---------------
(1) Future income taxes before discount were $480,817, $456,000 and $390,302 for
the years ended December 31, 1993, 1992 and 1991, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
YEAR ENDED DECEMBER 31,
---------------------------------------
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Beginning of year $ 404,577 $ 362,361 $ 381,884
Discoveries and extensions, net of related future
costs 48,183 47,177 45,011
Net changes in prices and production costs (53,822) 32,671 (43,782)
Accretion of discount 57,989 51,907 55,135
Revisions of previous quantity estimates, timing and
other (33,731) (21,526) (46,217)
Development cost incurred 18,617 15,593 20,908
Sales and transfers, net of production costs (74,182) (70,301) (64,854)
Net purchases of reserves in place 98,159 5,295 1,520
Net change in income taxes 2,110 (18,600) 12,756
--------- --------- ---------
End of Year $ 467,900 $ 404,577 $ 362,361
--------- --------- ---------
--------- --------- ---------
52
37
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
NET ACREAGE BY AREA OF OPERATION
DECEMBER 31, 1993
-------------------------------------
DEVELOPED UNDEVELOPED TOTAL
-------- ----------- ---------
Appalachian Region 758,652 469,088 1,227,740
Anadarko Region 176,158 32,429 208,587
-------- -------- ---------
934,810 501,517 1,436,327
-------- -------- ---------
-------- -------- ---------
Productive Well Summary
The following table reflects the Company's ownership at December 31, 1993
in gas and oil wells in the Appalachian Region (consisting of various fields
located in West Virginia, Pennsylvania, New York, Ohio, Virginia and Kentucky)
and in the Anadarko Region (consisting of various fields located in Oklahoma,
Texas, Kansas, North Dakota and Wyoming).
NATURAL GAS OIL TOTAL
----------------- -------------- -----------------
GROSS NET GROSS NET GROSS NET
------ ------- ---- ------ ------ -------
Appalachian Region 4,001 3,674.8 16 13.6 4,017 3,688.4
Anadarko Region 663 409.9 500 137.1 1,163 547.0
------ ------- ---- ------ ------ -------
4,664 4,084.7 516 150.7 5,180 4,235.4
------ ------- ---- ------ ------ -------
------ ------- ---- ------ ------ -------
"Productive" wells are producing wells and wells capable of production.
Price Range of Common Stock and Dividends
The Common Stock is listed and principally traded on the NYSE. The
following table sets forth for the periods indicated the high and low sales
prices per share of the Common Stock, as reported in the consolidated
transaction reporting system, and the cash dividends paid per share of the
Common Stock:
CASH
HIGH LOW DIVIDENDS
------- ------- ---------
1993
First Quarter $ 24.13 $ 15.50 $ 0.04
Second Quarter 25.88 21.50 0.04
Third Quarter 27.00 20.13 0.04
Fourth Quarter 26.25 17.63 0.04
1992
First Quarter $ 12.75 $ 10.25 $ 0.04
Second Quarter 14.50 11.00 0.04
Third Quarter 19.88 11.75 0.04
Fourth Quarter 19.88 14.50 0.04
As of January 31, 1994, there were 1,389 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.
53
38
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1993
Total Revenues $ 43,475 $ 38,379 $ 33,483 $ 48,958 $164,295
Operating Income 8,290 4,135 2,545 5,037 20,007
Net Income (Loss) Available
to All Common Shareholders 3,895 754 (3,371)(2) 810 2,088
Earnings Per Share $ 0.19 $ 0.04 $ (0.16)(2) $ 0.04 $ 0.10
1993 Restated
Total Revenues $ 43,475 $ 38,379 $ 33,483 $ 48,958 $164,295
Operating Income(1) 8,290 3,947 2,346 5,424 20,007
Net Income (Loss) Available
to All Common Shareholders(1) 3,895 566 (3,570)(2) 1,197 2,088
Earnings Per Share(1) $ 0.19 $ 0.03 $ (0.17)(2) $ 0.06 $ 0.10
1992
Total Revenues $ 38,361 $ 30,685 $ 32,740 $ 45,822 $147,608
Operating Income 5,864 2,408 1,837 7,874 17,983
Net Income (Loss) Available
to All Common Shareholders 2,415 (2,815)(3) (226) 2,853 2,227
Earnings Per Share $ 0.12 $ (0.14)(3) $ (0.01) $ 0.14 $ 0.11
- ---------------
(1) In the fourth quarter of 1993, the Company adopted SFAS 112 retroactive to
January 1, 1993. Accordingly, the quarters have been restated to reflect
the impact of this adoption.
(2) Included a $2.3 million charge, or 11 cents a share, due to a federal income
tax rate increase.
(3) Included a $2.7 million charge, or 13 cents a share, due to the settlement
of the Cabot tax dispute.
54