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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________________ to _____________________
---------------------------------
COMMISSION FILE NUMBER 001-13781
---------------------------------
KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 22-2889587
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
5555 SAN FELIPE ROAD, HOUSTON, TEXAS 77056
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 877-8006
--------------------------
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common stock, par value $0.01 New York Stock Exchange
per share 8-7/8% Senior New York Stock Exchange
Subordinated Notes due 2006
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [X] No [ ]
The aggregate market value of the 34,788,616 shares of the registrant's
common stock, par value $0.01 per share, held by non-affiliates of the
registrant at the $5.39 closing price on June 30, 2003 (the last business day of
the registrant's most recently completed second fiscal quarter) was
$187,510,640.
Indicate by check mark whether the registrant has filed all documents
and reports required to be filed by Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes [ ] No [ ]
Not applicable. Although the registrant was involved in bankruptcy
proceedings during the preceding five years, the registrant did not distribute
securities under its plan of reorganization.
The number of shares of the registrant's common stock, par value $0.01
per share, outstanding as of the close of business on March 5, 2004: 48,736,596.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held on May 27, 2004 are incorporated by reference into Part
III of this annual report on Form 10-K.
TABLE OF CONTENTS
PAGE
----
PART I.
Item 1. Business.................................................................. 1
Item 2. Properties................................................................ 17
Item 3. Legal Proceedings......................................................... 17
Item 4. Submission of Matters to a Vote of Security Holders....................... 17
PART II.
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters................................................... 18
Item 6. Selected Financial Data................................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................. 21
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................ 36
Item 8. Financial Statements and Supplementary Data............................... 39
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................. 68
Item 9A. Controls and Procedures................................................... 68
PART III.
Item 10. Directors and Executive Officers of the Registrant........................ 69
Item 11. Executive Compensation.................................................... 69
Item 12. Security Ownership of Certain Beneficial Owners and Management ........... 69
Item 13. Certain Relationships and Related Transactions............................ 69
Item 14. Principle Accounting Fees and Services.................................... 69
PART IV.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 70
(i)
Quantities of natural gas are expressed in this annual report on Form
10-K in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion
cubic feet (Bcf). Natural gas sales volumes and amounts hedged under derivative
contracts may be expressed in terms of one million British thermal units
(MMBtu), which is equal to one Mcf containing 1,000 British thermal units (Btu)
per cubic foot. The average Btu content of our natural gas reserves is in excess
of 1,000 Btu per cubic foot. Oil and natural gas liquids are quantified in terms
of barrels (bbls) and thousands of barrels (Mbbls). Oil and natural gas liquids
are compared with natural gas in terms of thousand cubic feet equivalent (Mcfe),
million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe).
For purposes of comparing oil and natural gas liquids to natural gas on a per
unit equivalent basis, one barrel of oil or natural gas liquids is the energy
equivalent of six Mcf of natural gas. With respect to information relating to
our working interest in wells or acreage, "net" oil and gas wells or acreage is
determined by multiplying gross wells or acreage by our working interest in the
oil and gas wells or acreage. Unless otherwise specified, all references to
wells and acres are gross. Working interest (WI) is the net percentage ownership
interest in a well that gives the owner the right to drill, produce and conduct
operating activities on the property and a share of the production.
References to "proved reserves" in this annual report on Form 10-K
refer to the estimated quantities of crude oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. The term "proved developed reserves" refers
to reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. The term "proved undeveloped reserves"
refers to reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. The term "recompletion" refers to the completion for
production of an existing wellbore in another formation from that in which the
well has previously been completed. The term "productive well" refers to a well
that is producing oil or natural gas or that is capable of production. The term
"workover" refers to operations on a producing well to restore or increase
production from an existing formation or recomplete to a new formation.
This annual report on Form 10-K refers to the pre-tax present value of
estimated future net revenues, or "PV-10 value," of our oil and natural gas
reserves. The PV-10 value of reserves refers to the pre-tax present value of
estimated future net revenues, computed by applying year-end prices to estimated
future production from the reserves, deducting estimated future expenditures,
and applying a discount factor of 10%. In accordance with applicable
requirements of the Securities and Exchange Commission, the PV-10 value is
generally based on prices and costs as of the date of the estimate. In contrast,
the actual future prices and costs may be materially higher or lower. Please do
not interpret the PV-10 values as the current market value of our properties'
estimated oil and natural gas reserves. The standardized measure of discounted
future net cash flows, or Standardized Measure, differs from PV-10 because
Standardized Measure includes the effect of future income taxes.
(ii)
PART I
ITEM 1. BUSINESS.
GENERAL
KCS Energy, Inc., a Delaware corporation, is an independent oil and gas
company engaged in the acquisition, exploration, development and production of
natural gas and crude oil. Our properties are primarily located in the
Mid-Continent and onshore Gulf Coast regions of the United States. We also have
interests in producing properties in Michigan, California and Wyoming. As of
December 31, 2003, our oil and natural gas properties were estimated to have net
proved reserves of 268.3 Bcfe with a PV-10 value, net of asset retirement
obligations, of approximately $630 million. Approximately 85% of our net proved
reserve base was natural gas and approximately 74% was classified as proved
developed. We operate approximately 78% of our proved oil and natural gas
reserve base. The following table sets forth the estimated quantities of
proved reserves attributable to our principal operating regions as of
December 31, 2003.
ESTIMATED PROVED RESERVES
--------------------------------------
NATURAL GAS OIL TOTAL PERCENT OF
(MMcf) (Mbbls) (MMcfe) RESERVES
------------ ----------- ----------- ------------
Mid-Continent Region 153,076 532 156,268 58%
Gulf Coast Region 53,480 1,488 62,408 23%
Other Properties (1) 21,562 4,675 49,612 19%
------- ----- ------- ---
Total Company 228,118 6,695 268,288 100%
======= ===== ======= ===
- --------------------
(1) Michigan, California and Wyoming.
In 2003, we produced an average of 95.2 MMcfe per day. We plan to
continue growing our reserves and production through a balanced investment
program in low-risk exploitation activities in the Mid-Continent and Gulf Coast
regions and moderate-risk, higher potential exploration drilling programs in the
onshore Gulf Coast region.
We are a publicly owned company whose stock is traded on the New York
Stock Exchange under the symbol "KCS." We were formed in 1988 in connection with
the spin-off of the non-utility businesses of a New Jersey-based natural gas
distribution company. Our principal executive offices are located at 5555 San
Felipe, Suite 1200, Houston, Texas 77056. Our telephone number is (713)
877-8006. Unless the context otherwise requires, the terms "KCS," "we," "our" or
"us" refer to KCS Energy, Inc. and its subsidiaries.
2003 HIGHLIGHTS
The year ended December 31, 2003 was one of the most successful in our
history. We focused on a low-risk drilling program in our core areas of
operation where we experienced significant increases in oil and natural gas
reserves and production. We drilled 78 wells during 2003, of which 72 were
completed, resulting in a 92% success rate. Production from our properties
averaged 77.2 MMcf per day of natural gas and 3,002 barrels of oil and natural
gas liquids per day, or 95.2 MMcfe per day for 2003. We increased production
24%, from an average of 83.9 MMcfe per day during the first quarter to an
average of 104.1 MMcfe per day during the fourth quarter. Oil and natural gas
reserves increased during 2003 to 268.3 Bcfe, which includes reserve additions
of 93.8 Bcfe, replacing 336% of our 2003 net production. Including positive
reserve revisions of 10.5 Bcfe, our overall reserve replacement rate was 373%.
We took several major steps during 2003 to further strengthen our
financial condition, lower interest costs and provide increased financial
flexibility. The balance of our outstanding Series A Convertible Preferred Stock
was converted into shares of our common stock. This conversion simplified our
overall capital structure and eliminated the 5% dividend obligation associated
with the preferred stock. In the first quarter we paid off our maturing senior
1
note obligations. In the fourth quarter, we amended and restated our bank
credit facility, which increased our revolving credit capacity to $100 million
and significantly reduced our borrowing costs. We also completed a public
offering of 6.9 million shares of our common stock. We used a portion of the net
proceeds of approximately $52 million to repay borrowings under our bank credit
facility and to accelerate our drilling program in certain core areas. Our
successful drilling program, along with strong oil and natural gas prices and
proceeds from our public common stock offering, allowed us to reduce debt from
$186.8 million, or $0.95 per Mcfe of reserves, at the beginning of the year to
$142.0 million, or $0.53 per Mcfe of reserves, at the end of the year.
We believe that the steps taken during 2003, along with our multi-year
drilling prospect inventory, position us to increase production and reserves in
2004 and beyond.
COMPETITIVE STRENGTHS AND BUSINESS STRATEGIES
We intend to continue to increase production and reserves and further
reduce debt per Mcfe to optimize stockholder value by executing the following
strategies:
- GROW THROUGH THE DRILL BIT - We believe our personnel possess
exceptional knowledge in identifying, drilling and stimulating tight
rock formations. We also think that the economics of drilling
self-generated prospects are superior to those of acquiring reserves.
Over the last three years, we have added 192 Bcfe to our reserves, of
which 86% were through the drill bit. With our extensive inventory of
drilling prospects, we believe that we are well-positioned to continue
growing our reserves and production.
- FOCUS ON NATURAL GAS - As of December 31, 2003, our proved reserves
were 85% natural gas. We believe that the future need for natural gas
in the United States will continue to grow and that natural gas is
better insulated from the price volatility associated with global
geopolitical instability. In addition, North American supplies of
natural gas have been declining in recent years. Lease operating
expenses associated with natural gas properties are also typically less
than oil properties, which allows us to maintain our low per-unit cost
structure.
- EXPLOIT OUR LARGE INVENTORY OF DRILLING PROJECTS - During the last four
years, we have built a significant inventory of future drilling
locations in targeted areas. We have identified approximately 130
proved undeveloped drilling locations and over 450 potential locations
that create additional reserve growth opportunities. Generally, these
locations range in depth from 5,000 feet to 13,000 feet and are low
risk opportunities. Most of the locations are step-out or extension
wells from existing production.
- CONCENTRATE IN CORE AREAS - We concentrate our drilling programs
predominately in the Mid-Continent and Gulf Coast regions. Operating in
concentrated areas helps us to better control our overhead by enabling
us to manage a greater amount of acreage with fewer employees and
minimize incremental costs of increased drilling and production. Our
strategy of targeting our operations in relatively concentrated areas
permits us to more efficiently capitalize on our base of geological,
engineering, exploration, development, completion and production
experience in these regions. The areas we produce generally have high
price realizations relative to benchmark prices for natural gas
production and favorable operating costs.
- CONTROL DRILLING AND PRODUCTION OPERATIONS - We operate approximately
78% of our proved oil and natural gas reserve base as of December 31,
2003. We prefer to generate and retain operating control over our own
prospects rather than owning non-operated interests. This allows us to
more effectively control operating costs, the timing and plans for
future development, the level of drilling and the marketing of
production on the properties. In addition, as an operator, we receive
reimbursements for overhead from other working interest owners, which
reduces our general and administrative expenses. During the year ended
December 31, 2003, we controlled the drilling operations on 60 of the
78 wells in which we participated.
- EMPLOY EXPERIENCED TECHNICAL PROFESSIONALS - We employ oil and gas
professionals, including geophysicists, petrophysicists, geologists,
petroleum engineers, production and reservoir engineers and landmen who
have an average of approximately 23 years of experience in their
technical fields. We continually apply our extensive in-house expertise
and advanced technologies to benefit our drilling and completion
operations.
2
- MAINTAIN FINANCIAL FLEXIBILITY - The timing of most of our capital
expenditures is discretionary. Consequently, we have a significant
degree of flexibility to adjust the level of expenditures
according to market conditions. We currently anticipate spending
approximately $105 million on capital projects in 2004. We expect that
these projects will be funded primarily with internally generated cash
flow.
- CONTROL RISK - We allocate approximately 80% of our capital on an
annual basis to low risk development and exploitation projects and the
remainder to moderate risk exploration plays. We set limits on the
amount of capital we will invest in any one exploration project. We
hedge a portion of our oil and natural gas to protect against downward
price swings, and we control costs closely to ensure the best possible
profit margins. In addition, we turnkey our drilling operations where
economic in order to reduce drilling risk.
CORE OPERATING AREAS
Mid-Continent
In the Mid-Continent region, we concentrate our drilling programs
primarily in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins)
and west Texas. Our Mid-Continent operations provide us with a solid base for
production and reserve growth. We plan to continue to exploit areas within the
various basins that require low-risk exploitation wells for additional reservoir
drainage. Our exploitation wells are generally step-out and extension type wells
with moderate reserve potential. During 2003, we drilled 58 wells in this region
with a success rate of 95%. We have a multi-year inventory of locations in the
Mid-Continent region and plan to increase the level of drilling in our Elm
Grove, Talihina and Joaquin fields and to continue the development program in
our Sawyer Canyon Field in 2004.
- Elm Grove Field - Located in Bossier Parish of north Louisiana,
production from this field comes from the Hosston and Cotton Valley
formations. These zones are composed of low permeability rocks that
require large fracture stimulation treatments to produce. We operate
nine sections with working interests (WI) ranging from 91-100%. We also
have a non-operated 33% WI interest in one section. In 2003, the field
contributed about 20% of our net production. As of year-end, 2003, we
had 77 Bcfe of proved reserves in this field that accounted for
approximately 34% of our PV-10.
We began a development program in late 2002 that included the drilling
of six wells. In 2003, we worked over 15 wells and drilled 19
additional wells, all of which were successful. This workover and
drilling activity increased gross operated production from 6 MMcfe per
day in 2002 to approximately 30 MMcfe per day at December 31, 2003. In
2004, we plan to drill 37-40 proved undeveloped and step-out locations
to continue growing production and reserves.
- Sawyer Canyon Field - Our second largest field, contributing
approximately 12% of our net production in 2003, is located in Sutton
County, west Texas. We have rights to drill and produce on 31,600
acres. Over the last several years, we have been conducting drilling
programs targeting shallow Canyon sandstone formations. We have a
90%-100% working interest in most of the areas we are actively
drilling. We drilled 18 wells in 2003 and plan to drill 12-20
additional wells in 2004 in order to maintain production levels.
- Joaquin Field - We operate and have rights to earn up to 5,000 acres
in this property located just west of the Texas-Louisiana border in
Shelby County, Texas. We drilled six wells in 2003, which produce
Travis Peak sands at depths of 6,000-8,600 feet. We anticipate drilling
10-12 additional wells in 2004.
- Talihina Field - We acquired the majority of our acreage in this Arkoma
basin field in 2002. We now have approximately 11,000 acres in this
Jackfork formation play. In the 24 sections in which we have ownership,
working interest varies from 19%-70%. We drilled our first well in late
2002, followed by two additional wells in 2003. We plan to drill six to
ten additional wells in 2004 with follow up drilling dependent upon
continuing step-out success. We also participated in four development
wells in the nearby Panola and Wilburton fields.
Gulf Coast
In the Gulf Coast region, we concentrate our drilling programs
primarily in south Texas. We also have working interests in several minor
non-operated offshore and Mississippi salt basin properties. We conduct
3
development programs and pursue moderate-risk, higher potential exploration
drilling programs in this region. Our Gulf Coast operations have numerous
exploration prospects that are expected to provide us additional growth. During
2003, we drilled 6 exploratory and 13 development wells in this region with a
success rate of 84%. All of the wells drilled during 2003, except one
non-operated offshore well, were located in south Texas. We anticipate drilling
20-26 wells in this region in 2004, approximately half of which will be
exploratory.
- Wilcox Trend - Our projects in the Wilcox trend are mostly located in
Harris, Goliad, Victoria, and Live Oak counties in Texas. Our primary
objectives are the abnormally pressured Middle Wilcox sands, although
we also produce from normal-pressured Frio, Yegua and Upper Wilcox
zones. Sandstones in these formations are found at depths between 4,000
- 13,000 feet. In 2003, we drilled five Wilcox exploration wells, of
which four were successful. In addition, we drilled eight Wilcox
development wells. Normally, we generate these prospects and retain a
25%-60% working interest.
- Vicksburg Trend - We also pursue Vicksburg formation prospects
primarily in our La Reforma Field in Hidalgo County. We drilled a
successful initial test well in late 2002, drilled one additional well
in 2003 and anticipate drilling two to three additional wells in 2004.
- Other Gulf Coast - We have minor, non-operated interests in offshore
blocks and in several fields in the Mississippi salt basin.
OTHER OPERATING AREAS
We also operate and own majority interests in fields located in the
Niagran Reef play of Michigan, the Big Horn basin in Wyoming and the Los Angeles
basin in California. As of December 31, 2003, these properties accounted for
approximately 14% of our PV-10 value. In 2003, we drilled one well in Michigan
and used the cash flow generated from these properties to fund drilling
operations in our core operating areas.
OIL AND GAS PROPERTIES
We hold interests in all of our oil and gas properties through two
operating subsidiaries: KCS Resources, Inc., a Delaware Corporation and
Medallion California Properties Company, a Texas Corporation. The oil and gas
properties referred to in this annual report on Form 10-K are held by these
subsidiaries. We treat all operations as one line of business.
The following table sets forth the number of gross and net producing
wells by region as of December 31, 2003.
PRODUCING WELLS
----------------------------------------
NATURAL GAS OIL
-------------------- -------------------
GROSS NET GROSS NET
------- ------- ------- ------
Mid-Continent Region 716 466.4 22 11.2
Gulf Coast Region 221 90.1 28 10.2
Other Properties (1) 81 55.2 105 68.8
----- ----- --- ----
Total Company 1,018 611.7 155 90.2
===== ===== === ====
- ------------------
(1) Michigan, California and Wyoming.
OIL AND NATURAL GAS RESERVES
The following table sets forth, as of December 31, 2003, summary
information with respect to estimates of our proved oil and natural gas reserves
based on year-end prices. Oil and natural gas prices as of December 31, 2003 are
not necessarily indicative of the prices that we expect to receive in the
future. Accordingly, the pre-tax present value of future net revenues in the
following table should not be construed to be the current market value of the
estimated oil and natural gas reserves. The reserve estimates and associated net
revenues for our properties were audited by Netherland, Sewell & Associates,
Inc., or NSAI.
4
AS OF DECEMBER 31, 2003
---------------------------------------------------------------------------
NATURAL FUTURE NET
GAS OIL TOTAL REVENUES PV-10
(MMCF) (MBBLS) (MMCFE) ($000) ($000)
---------- ------- ------- ----------- ---------
Proved developed reserves 164,787 5,685 198,897 $ 805,936 $ 483,702
Proved undeveloped reserves 63,331 1,010 69,391 271,052 150,107
------- ----- ------- ----------- ---------
Proved reserves 228,118 6,695 268,288 $ 1,076,988 $ 633,809
======= ===== ======= =========== =========
In addition, incremental asset retirement obligations not reflected in
the future net revenues above were $7.4 million and PV-10, net of those asset
retirement obligations, was approximately $630 million.
In accordance with Securities and Exchange Commission guidelines, the
estimates of future net revenues from our proved reserves and the present values
of our proved reserves are made using oil and natural gas sales prices in effect
as of the dates of those estimates and are held constant throughout the life of
the properties except where those guidelines permit alternate treatment. Natural
gas prices are based on either a contract price or a December 31, 2003 spot
price of $5.97 per MMBtu, adjusted by lease for Btu content, transportation fees
and regional price differentials. Oil prices are based on a December 31, 2003
West Texas Intermediate posted price of $29.25 per barrel, adjusted by lease for
gravity, transportation fees and regional price differentials. The prices for
natural gas and oil are subject to substantial seasonal fluctuations, and prices
for each are subject to substantial fluctuations as a result of numerous other
factors. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Business - Risk Factors" for further
discussion of these and other factors.
PRODUCTION
The following table presents certain information with respect to
production attributable to our properties and average sales prices for the years
ended December 31, 2003, 2002 and 2001.
YEAR ENDED DECEMBER 31,
-----------------------------
2003 2002 2001
------- ------- -------
Production: (a)
Natural Gas (MMcf) 28,166 29,672 36,873
Oil (Mbbl) 838 1,003 1,230
Natural gas liquids (Mbbl) 258 288 373
------- ------- -------
Total (MMcfe) 34,741 37,417 46,491
Summary (MMcfe)
Working interest (b) 34,741 34,959 41,966
Purchased VPP (c) -- 2,458 4,525
------- ------- -------
Total 34,741 37,417 46,491
Dedicated to
Production Payment (6,807) (11,196) (15,716)
------- ------- -------
Net Production 27,934 26,221 30,775
Average Price:
Natural gas (per Mcf) $ 4.79 $ 3.25 $ 3.90
Oil (per bbl) 25.34 20.52 20.67
Natural gas liquids (per bbl) 14.58 10.05 13.74
Total (per Mcfe) (d) $ 4.60 $ 3.21 $ 3.75
- ---------------------
(a) Production includes volumes dedicated to the Production Payment sold
in February 2001. Please read Notes 1 and 2 to our Consolidated
Financial Statements for more information on the Production Payment.
(b) We sold properties in 2002 and 2001 to reduce debt.
(c) We discontinued making new investments in VPPs in 1999, and final
deliveries from our VPP program were received in November 2002.
5
(d) Excluding the non-cash effects of volumes delivered under the
Production Payment sold in February 2001 and terminated derivative
contracts associated with the acquisition of Medallion California
Properties Company and related entities, our total average realized
price per Mcfe was $5.05, $3.19 and $3.90 in 2003, 2002 and 2001,
respectively. For further information, please read Item 7.
"Management's Discussion and Analysis of Financial Condition and
Results of Operation - Major Influences on Results of Operations."
ACREAGE
The following table sets forth our developed and undeveloped leased
acreage as of December 31, 2003. The leases in which we have an interest are for
varying primary terms, and many require the payment of delay rentals to continue
the primary term. The operator may surrender the leases at any time by notices
to the lessors, the cessation of production, fulfillment of commitments, or
failure to make timely payments of delay rentals.
DEVELOPED ACRES UNDEVELOPED ACRES
------------------------- ------------------------
State GROSS NET GROSS NET
- ---------- ------- ------- ------ ------
Texas 92,874 55,716 33,053 21,287
Louisiana 31,014 23,720 11,474 8,124
Oklahoma 43,789 25,541 8,302 6,282
Michigan 12,620 6,733 138 138
Wyoming 61,851 39,746 27,750 23,151
Offshore 80,063 9,683 - -
Other 12,672 6,091 9,039 1,877
------- ------- ------ ------
Total 334,883 167,230 89,756 60,859
======= ======= ====== ======
TITLE TO INTERESTS
We believe that title to the various interests set forth above is
satisfactory and consistent with the standards generally accepted in the oil and
gas industry, subject only to immaterial exceptions that do not detract
substantially from the value of the interests or materially interfere with their
use in our operations. Our owned interests may be subject to one or more
royalty, overriding royalty and other outstanding interests customary in the
industry. The interests may additionally be subject to obligations or duties
under applicable laws, ordinances, rules, regulations and orders of arbitral or
governmental authorities. In addition, the interests may be subject to burdens,
including production payments, net profits interests, development obligations
under oil and gas leases and other encumbrances, easements and restrictions.
DRILLING ACTIVITIES
During the three-year period ended December 31, 2003, we participated
in drilling 237 (120.1 net) wells with a success rate of 86%. During 2003, we
participated in drilling 78 (55.4 net) wells with a success rate of 92%. Our
drilling results for 2003 include 71 development wells and 7 exploration wells
with success rates of 93% and 86%, respectively. All of our drilling activities
are conducted through arrangements with independent contractors. The following
table sets forth certain information with respect to our drilling activities
during the years ended December 31, 2003, 2002 and 2001.
6
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
2003 2002 2001
----------------- ---------------- ----------------
TYPE OF WELL Gross Net Gross Net Gross Net
- ------------ ----- ---- ----- ---- ----- ----
Development:
Oil - - 1 0.8 2 0.5
Natural gas 66 49.3 28 13.4 63 29.0
Non-productive 5 2.9 5 1.2 6 3.4
-- ---- -- ---- -- ----
Total 71 52.2 34 15.4 71 32.9
== ==== == ==== == ====
Exploratory:
Oil - - - - 4 0.9
Natural gas 6 2.7 10 4.5 23 7.0
Non-productive 1 0.5 9 2.2 8 1.8
-- ---- -- ---- -- ----
Total 7 3.2 19 6.7 35 9.7
== ==== == ==== == ====
As of December 31, 2003, we were participating in the drilling of 8 (5.2 net)
wells.
OTHER FACILITIES
Our principal executive offices and those of our operating subsidiaries
are leased in modern office buildings in Houston, Texas and Tulsa, Oklahoma.
We believe that all of our property, plant and equipment are well
maintained, in good operating condition and suitable for the purposes for which
they are used.
REGULATION
GENERAL. Our business is affected by numerous laws and regulations,
including energy, environmental, conservation, tax and other laws and
regulations relating to the energy industry. Changes in any of these laws and
regulations could have a material adverse effect on our business. In light of
the many uncertainties related to current and future laws and regulations,
including their applicability to us, we may be unable to predict the overall
effect of current and future laws and regulations on our future operations.
We believe that our operations comply in all material respects with all
applicable laws and regulations. Although applicable laws and regulations have a
substantial impact upon the energy industry, generally these laws and
regulations do not appear to affect us any differently, or to any greater or
lesser extent, than other similar companies in the energy industry. The
following discussion describes certain laws and regulations applicable to the
energy industry and is qualified in its entirety by the foregoing.
STATE REGULATIONS AFFECTING PRODUCTION OPERATIONS. Our onshore
exploration, production and exploitation activities are subject to regulation at
the state level. Laws and regulations vary from state to state, but generally
include laws to regulate drilling and production activities and to promote
resource conservation. Examples of these state laws and regulations include laws
that:
- require permits and bonds to drill and operate wells;
- regulate the method of drilling and casing wells;
- establish surface use and restoration requirements for properties
upon which wells are drilled;
- regulate plugging and abandonment of wells;
- regulate the disposal of fluids used or produced in connection
with operations;
- regulate the location of wells, including establishing the minimum
size of drilling units and the minimum spacing between wells;
- concern unitization or pooling of oil and gas properties;
- establish maximum rates of production from oil and gas wells; and
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- restrict the venting or flaring of natural gas.
These laws and regulations may adversely affect the profitability of
affected properties or our operations. We are unable to predict the future cost
or impact of complying with these regulations.
FEDERAL REGULATIONS AFFECTING PRODUCTION OPERATIONS. We also operate
federal oil and gas leases that are subject to the regulation of the United
States Bureau of Land Management, or BLM, and the United States Minerals
Management Service, or MMS.
Leases regulated by the BLM and MMS contain relatively standardized
terms requiring compliance with detailed regulations and orders. These
regulations specify, for example, lease operating, safety and conservation
standards, well plugging and abandonment requirements, and surface restoration
requirements. In addition, the BLM and MMS generally require us to post surety
bonds or other acceptable financial assurances to assure that our obligations
will be met. The cost of these bonds or other financial assurances can be
substantial and we may be unable to obtain bonds or other financial assurances
in all cases. Under certain circumstances, the BLM or MMS may require operations
on federal leases to be suspended or terminated. Any suspension or termination
under these leases may adversely affect our interests.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the Federal Energy Regulatory Commission,
or FERC, the MMS, the BLM, state commissions and the courts. We are unable to
predict when or whether any such proposals may become effective. Historically,
the natural gas industry has been very heavily regulated and for many years was
subject to price controls imposed by the federal government. The current
regulatory approach pursued by various agencies and Congress may not continue
indefinitely and it is possible Congress (or in the case of some natural gas
sales, the FERC) could reimpose price controls in the future. Notwithstanding
the foregoing, we do not anticipate that compliance with existing federal, state
and local laws, rules and regulations will have a material or significantly
adverse effect upon our capital expenditures, earnings or competitive position.
OPERATING HAZARDS AND ENVIRONMENTAL MATTERS. The oil and gas business
involves a variety of operating risks, including the risk of fires, explosions,
well blow-outs, pipe failure, oil spills, natural gas leaks or ruptures, and
discharges of toxic gases or other pollutants. The occurrence of these risks
could result in substantial losses to us due to personal injury, loss of life,
damage to or destruction of wells, production facilities or other property or
equipment, or damage to the environment. These occurrences could also subject us
to clean-up obligations, regulatory investigation, penalties or suspension of
operations. Although we believe we are adequately insured, these hazards may
hinder or delay drilling, development and production operations.
Oil and gas operations are subject to extensive federal, state and
local laws and regulations that regulate the discharge of materials into the
environment or otherwise relate to the protection of the environment. These laws
and regulations may:
- require the acquisition of a permit before drilling commences;
- restrict the types, quantities and concentration of substances
that can be released into the environment;
- restrict drilling activities on certain lands, including wetlands
or other protected areas; and
- impose substantial liabilities for pollution resulting from
drilling and production operations.
Failure to comply with these laws and regulations may also result in civil and
criminal fines and penalties.
Our properties, and any wastes spilled or disposed of by us, may be
subject to federal or state environmental laws that could require us to remove
the wastes or remediate contamination. For example, the Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, also known as
the "Superfund" law, imposes liability, without regard to fault or the original
conduct, on certain classes of persons who are considered to be responsible for
the release of a "hazardous substance" into the environment. These persons
include the present or former owner or operator of the disposal site or sites
where the release occurred and companies that disposed, or arranged for the
disposal, of the hazardous substances. Under CERCLA, these persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances, for damages to natural resources and for the
8
costs of certain health studies. In addition, neighboring landowners and other
third parties may assert claims for personal injury and property damage
allegedly caused by the release of hazardous substances.
Our operations may also be subject to the Clean Air Act, or CAA, and
comparable state and local requirements. Pursuant to these requirements, we may
be required to incur certain capital expenditures for air pollution control
equipment in connection with maintaining or obtaining permits and approvals
relating to air emissions. We do not believe that our operations will be
materially adversely affected by these requirements.
In addition, the United States Oil Pollution Act, or OPA, requires
owners and operators of facilities in or near rivers, creeks, wetlands, coastal
waters, offshore waters, and other United States waters to adopt and implement
plans and procedures to prevent oil spills. OPA also requires affected facility
owners and operators in coastal waters to demonstrate that they have at least
$10 million in financial resources to pay for the costs of the remediation of an
oil spill and compensating any parties damaged by an oil spill. These financial
assurances may be increased to as much as $150 million depending on a facility's
worst case oil spill discharge volume and other relative operational,
environmental and human health risks.
Our operations are also subject to the federal Clean Water Act, or CWA,
and analogous state laws. Among other matters, these laws may prohibit the
discharge of waters produced in association with hydrocarbons into coastal
waters. To comply with this prohibition, we may be required to incur capital
expenditures or increased operating expenses. The CWA also regulates discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under a
general permit. While certain of our properties may require permits for
discharges of storm water runoff, we believe that we will be able to obtain, or
be included under, these permits as necessary. Coverage under these permits may
require us to make minor modifications to existing facilities and operations
that would not have a material adverse effect on us.
Pursuant to the Safe Drinking Water Act, underground injection control,
or UIC, wells, including wells used in enhanced recovery and disposal operations
associated with oil and gas exploration and production activities, are subject
to regulation. These regulations include permitting, bonding, operating,
maintenance and reporting requirements.
In addition, the disposal of wastes containing naturally occurring
radioactive material, which is commonly encountered during oil and natural gas
production, is regulated under state law. Typically, wastes containing naturally
occurring radioactive material can be managed on-site or disposed of at
facilities licensed to receive such waste at costs that are not expected to be
material.
RISK FACTORS
THE OIL AND NATURAL GAS MARKET IS VOLATILE AND THE PRICE OF OIL AND NATURAL GAS
FLUCTUATES, WHICH MAY ADVERSELY AFFECT OUR CASH FLOWS AND THE VALUE OF OUR OIL
AND NATURAL GAS RESERVES.
Our future revenues and profits and the value of our oil and natural
gas reserves will depend substantially on the demand and prices we receive for
produced oil and natural gas. Oil and natural gas prices have been and are
likely to continue to be volatile and subject to wide fluctuations in response
to a variety of factors including the following:
- relatively minor changes in the supply of, and demand for, oil and
natural gas;
- market uncertainty;
- political conditions in international oil producing regions;
- weather conditions;
- domestic and foreign government regulations and taxes;
- price and availability of alternative fuels; and
- overall economic conditions.
9
As oil and natural gas prices decline, we are affected in two significant ways.
First, we are paid less for our oil and natural gas. Second, exploration and
development activity may decline as some projects may become uneconomic and
either are delayed or eliminated. Accordingly, a decline in oil or natural gas
prices may have adverse effects on our cash flow, liquidity and profitability.
It is impossible to predict future oil and natural gas price movements.
WE MAY BE UNABLE TO SATISFY OUR FUTURE CAPITAL REQUIREMENTS.
We make substantial capital expenditures in connection with the
acquisition, exploration and development of our oil and gas properties. In the
past, we have funded these capital expenditures with cash flow from operations,
funds from long-term debt financings, including bank financing secured by our
oil and gas assets, and funds from equity financings. Our future cash flows are
subject to a number of factors, including the following:
- prices of oil and natural gas;
- the level of production from existing wells;
- operating and development costs; and
- our success in locating and producing new reserves.
The availability of long-term debt and equity financing is also subject
to these factors. Investors in our debt securities view our future cash flow as
a measure of our ability to make principal and interest payments. In addition,
the availability of funds under our bank credit facility is based on the value
of our estimated oil and natural gas reserves and our cash flows, which in turn
are based on prices of oil and natural gas and the amount and timing of
production. Similarly, investors in our equity securities consider both the
value of our oil and gas properties and our cash flow in evaluating our
prospects for growth and profitability.
WE MAY BE UNABLE TO SUCCESSFULLY IDENTIFY, EXECUTE OR EFFECTIVELY INTEGRATE
FUTURE ACQUISITIONS, WHICH MAY NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS.
Acquisitions of oil and gas businesses and properties have been an
important element of our business, and we will continue to pursue acquisitions
in the future. In the last several years, we have pursued and consummated
acquisitions that allow us to drill development and extension wells. Although we
regularly engage in discussions with, and submit proposals to, acquisition
candidates, suitable acquisitions may not be available in the future on
reasonable terms. If we do identify an appropriate acquisition candidate, we may
be unable to successfully negotiate the terms of an acquisition, finance the
acquisition or, if the acquisition occurs, effectively integrate the acquired
business into our existing business. Negotiations of potential acquisitions and
the integration of acquired business operations may require a disproportionate
amount of management's attention and our resources. Even if we complete
additional acquisitions, continued acquisition financing may not be available or
available on reasonable terms, any new businesses may not generate revenues
comparable to our existing business, the anticipated cost efficiencies or
synergies may not be realized and these businesses may not be integrated
successfully or operated profitably. The success of any acquisition will depend
on a number of factors, including the ability to estimate accurately the
recoverable volumes of reserves, rates of future production and future net
revenues attainable from the reserves and to assess possible environmental
liabilities. Our inability to successfully identify, execute or effectively
integrate future acquisitions may negatively affect our results of operations.
Even though we perform a due diligence review (including a review of
title and other records) of the major properties we seek to acquire that we
believe is consistent with industry practices, these reviews are inherently
incomplete. It is generally not feasible for us to review in-depth every
individual property and all records involved in each acquisition. However, even
an in-depth review of records and properties may not necessarily reveal existing
or potential problems or permit us to become familiar enough with the properties
to assess fully their deficiencies and potential. Even when problems are
identified, we may assume certain environmental and other risks and liabilities
in connection with the acquired businesses and properties. The discovery of any
material liabilities associated with our acquisitions could harm our results of
operations.
In addition, acquisitions of businesses may require additional debt or
equity financing, resulting in additional leverage or dilution of ownership. Our
bank credit facility and the indenture governing our senior subordinated notes
contain certain covenants that limit, or which may have the effect of limiting,
among other things, acquisitions, capital expenditures the sale of assets and
the incurrence of additional indebtedness.
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THERE ARE NUMEROUS UNCERTAINTIES INHERENT IN ESTIMATING QUANTITIES OF PROVED OIL
AND NATURAL GAS RESERVES AND FUTURE NET REVENUES.
Reserve estimating is a subjective process of determining the size of
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. Estimates of economically recoverable oil and natural gas reserves
and of future net revenues may vary considerably from the actual results because
of a number of variable factors and assumptions involved. These include:
- the effects of regulation by governmental agencies;
- future oil and natural gas prices;
- operating costs;
- the method by which the reservoir is produced as well as the
properties of the rock;
- relationships with landowners, working interest partners, pipeline
companies and others;
- severance and excise taxes;
- development costs; and
- workover and remedial costs.
In addition, volumetric calculations are often used to estimate initial
reserves from a field. These estimates utilize data including the area that a
well is expected to drain, rock properties derived from log analysis,
anticipated reservoir fluid properties, abandonment pressure and estimates of
recovery factors. As production data becomes available, the actual performance
is often used to project the final reserves. As such, initial reserve estimates
are much less precise in nature.
Therefore, the estimates of the quantities of oil and natural gas and
the expected future net revenues computed by different engineers or by the same
engineers (but at different times) may vary significantly. The actual
production, revenues and expenditures related to our reserves may vary
materially from the engineers' estimates.
Furthermore, we may make changes to our estimates of reserves and
future net revenues. These changes may be based on the following factors:
- well performance;
- results of development including drilling and workovers;
- oil and natural gas prices;
- performance of counterparties under agreements to which we are a
party; and
- operating and development costs.
Actual future net revenues may also be affected by the following
factors:
- the amount and timing of actual production and costs incurred with
such production;
- the supply of, and demand for, oil and natural gas; and
- the changes in governmental regulations or taxation.
Ultimately, the timing in producing and the costs incurred in
developing and producing will affect the actual present value of oil and natural
gas. In addition, the Securities and Exchange Commission requires that we apply
a 10% discount factor in calculating PV-10 value for reporting purposes. This
may not be the most appropriate
11
discount factor to apply because it does not take into account the interest
rates in effect, the risks associated with us and our properties, or the oil and
gas industry in general.
OUR OPERATING ACTIVITIES INVOLVE SIGNIFICANT RISKS THAT ARE INHERENT IN THE OIL
AND GAS INDUSTRY.
Our operations are subject to numerous operating risks inherent in the
oil and gas industry that could result in substantial losses. These risks
include:
- fires;
- explosions;
- well blowouts;
- mechanical problems, including pipe failure;
- abnormally pressured formations; and
- environmental accidents, including oil spills, natural gas leaks
or ruptures, or other discharges of toxic gases or other
pollutants.
The occurrence of these risks could result in substantial losses due to
personal injury, loss of life, damage to or destruction of wells, production
facilities or other property or equipment, or damages to the environment. These
occurrences could also subject us to clean-up obligations, regulatory
investigation, penalties or suspension of operations. Further, our operations
may be materially curtailed, delayed or canceled as a result of numerous
factors, including:
- the presence of unanticipated pressure or irregularities in
formations;
- equipment failures or accidents;
- title problems;
- weather conditions;
- compliance with governmental requirements; and
- shortages or delays in obtaining drilling rigs or in the delivery
of equipment and services.
In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. The levels of insurance
we maintain may not be adequate to fully cover any losses or liabilities. We may
not be able to maintain insurance at commercially acceptable premium levels or
at all.
WE MAY BE UNABLE TO PRODUCE SUFFICIENT AMOUNTS OF OIL AND NATURAL GAS AND, AS A
RESULT, OUR PROFITABILITY AND CASH FLOW MAY DECLINE.
We may drill new wells that are not productive or we may not recover
all or any portion of our investment. Drilling for oil and natural gas may be
unprofitable due to a number of risks, including:
- wells may not be productive, either because commercially
productive reservoirs were not encountered or for other reasons;
- wells that are productive may not provide sufficient net reserves
to return a profit after taking into account leasehold,
geophysical and geological, drilling, operating and other costs;
and
- the costs of drilling, completing and operating wells are often
uncertain.
If we are unable to produce sufficient amounts of oil and natural gas, our
profitability and cash flow will decline.
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IF WE ARE UNABLE TO ACQUIRE OR DISCOVER ADDITIONAL RESERVES, OUR RESERVES AND
PRODUCTION WILL DECLINE MATERIALLY.
Our prospects for future growth and profitability depend primarily on
our ability to replace oil and natural gas reserves through acquisitions, and
exploratory and development drilling. Acquisitions may not be available at
attractive prices or at all. The decision to purchase, explore or develop a
property depends in part on geophysical and geological analyses and engineering
studies that are often inconclusive or subject to varying interpretations. As a
consequence, our acquisition, exploration and development activities may not
result in significant additional reserves. Without the acquisition, discovery or
development of additional reserves, our proved reserves and production will
decline materially.
OUR FAILURE TO REMAIN COMPETITIVE WITH OUR NUMEROUS COMPETITORS, MANY OF WHICH
HAVE SUBSTANTIALLY GREATER RESOURCES THAN WE DO, COULD ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS.
The oil and gas industry is highly competitive in the search for, and
development and acquisition of, reserves and in the marketing of oil and natural
gas production. We compete with major oil and gas companies, other independent
oil and gas concerns and individual producers and operators in most aspects of
our business, including the following:
- the acquisition of oil and gas businesses and properties;
- the exploration, development, production and marketing of oil and
natural gas;
- the acquisition of properties and equipment; and
- the retention of personnel necessary to explore for, develop,
produce and market oil and natural gas.
Many of these competitors have substantially greater financial and
other resources. If we are unable to successfully compete against our
competitors, our business, prospects, financial condition and results of
operations may be adversely affected.
WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL
REGULATIONS, THAT MAY ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY OF DOING
BUSINESS.
Our business is subject to numerous federal, state and local laws and
regulations, including energy, environmental, conservation, tax and other laws
and regulations relating to the energy industry. We, as an owner or lessee and
operator of oil and gas properties, are subject to various federal, state and
local laws and regulations relating to the discharge of materials into, and
protection of, the environment. These laws and regulations may, among other
things, limit the location of drilling or the level of production allowed from a
well, affect the cost, terms and availability of oil and natural gas
transportation by pipeline, impose liability on the lessee under an oil and gas
lease for the cost of pollution clean-up resulting from operations, subject the
lessee to liability for pollution damages, and require suspension or cessation
of operations in affected areas.
Environmental laws have in recent years become more stringent and have
generally sought to impose greater liability on a larger number of potentially
responsible parties. While we are not currently aware of any situation involving
an environmental claim that would likely have a material adverse effect on our
business, it is always possible that an environmental claim with respect to one
or more of our current properties or a business or property that one of our
predecessors owned or used could arise and could involve the expenditure of a
material amount of funds. Although we maintain insurance coverage which we
believe is customary in the industry, we are not fully insured against all
environmental risks.
The oil and gas regulatory environment could change in ways that could
substantially increase the cost of complying with the requirements of
environmental and other regulations. Hydrocarbon-producing states regulate
conservation practices and the protection of correlative rights. These
regulations affect our operations and limit the quantity of hydrocarbons we may
produce and sell. We cannot predict whether, or when, new laws and regulations
may be enacted or adopted, and we cannot predict the cost of compliance with
changing laws and regulations or their effects on oil and natural gas use or
prices.
13
THE CONCENTRATION OF OUR CUSTOMERS IN THE ENERGY INDUSTRY COULD INCREASE OUR
EXPOSURE TO CREDIT RISK, WHICH COULD RESULT IN LOSSES.
The concentration of our customers in the energy industry may impact
our overall exposure to credit risk, either positively or negatively, in that
customers may be similarly affected by prolonged changes in economic and
industry conditions. We perform ongoing credit evaluations of our customers and
do not generally require collateral in support of our trade receivables. We
maintain reserves for credit losses and, generally, actual losses have been
consistent with our expectations, with the exception of losses we sustained
relating to obligations of certain Enron entities to KCS.
IF WE ARE UNSUCCESSFUL TRANSPORTING OUR OIL AND NATURAL GAS TO MARKET AT
COMMERCIALLY ACCEPTABLE PRICES, OUR PROFITABILITY WILL DECLINE.
Our ability to transport our oil and natural gas to market at
commercially acceptable prices depends on, among other factors, the following:
- the availability and capacity of gathering systems and pipelines;
- changes in supply and demand; and
- general economic conditions.
Our inability to respond appropriately to changes in these factors could
negatively affect our profitability.
In addition, the transportation by pipeline of oil and natural gas in
interstate commerce is heavily regulated by the FERC, including regulation of
the cost, terms and conditions for such transportation service, and in the case
of natural gas, the construction and location of pipelines. The transportation
by pipeline of oil and natural gas in intrastate commerce is generally subject
to varying degrees of state regulation of the cost, terms and conditions of
service. While we are not directly subject to these regulations, they affect the
cost and availability of transportation of our production to market.
UNINSURED JUDGMENTS OR A RISE IN INSURANCE PREMIUMS COULD ADVERSELY IMPACT OUR
RESULTS OF OPERATIONS.
Exploration for, and production of, oil and natural gas can be
hazardous, involving unforeseen occurrences. Accordingly, in the ordinary course
of business, we are subject to various claims and litigation. Although we
maintain insurance to cover certain potential claims and losses arising from our
operations in accordance with customary industry practices and in amounts that
management believes to be prudent, we could become subject to a judgment for
which we are not adequately insured and beyond the amounts that we currently
have reserved or anticipate reserving. Additionally, the terrorist attacks of
September 11, 2001 and the continued hostilities in the Middle East and other
sustained military campaigns may adversely impact our ability to obtain
insurance or impact the cost of this insurance, which may adversely impact our
results of operations.
TERRORIST ATTACKS AND CONTINUED HOSTILITIES IN THE MIDDLE EAST OR OTHER
SUSTAINED MILITARY CAMPAIGNS MAY ADVERSELY IMPACT OUR BUSINESS.
The terrorist attacks that took place in the United States on September
11, 2001 were unprecedented events that have created many economic and political
uncertainties, some of which may materially adversely impact our business. The
long-term impact that terrorist attacks and the threat of terrorist attacks may
have on our business is not known at this time. Uncertainty surrounding
continued hostilities in the Middle East or other sustained military campaigns
or terrorist attacks may adversely impact our business in unpredictable ways.
OUR SUCCESS DEPENDS ON KEY MEMBERS OF SENIOR MANAGEMENT, THE LOSS OF WHOM COULD
DISRUPT OUR CUSTOMER RELATIONSHIPS AND BUSINESS OPERATIONS.
We believe our continued success depends in large part on the sustained
contributions of our chief executive officer and chairman of the board of
directors, James W. Christmas, our president and chief operating officer,
William N. Hahne, our management team and technical personnel. We rely on our
executive officers and senior management to identify and pursue new business
opportunities and identify key growth opportunities. In addition, the
relationships and reputation that members of our management team have
established and maintained in
14
the oil and gas community contribute to our ability to maintain positive
customer relations and to identify new business opportunities. The loss of
services of Messrs. Christmas or Hahne or one or more senior management or
technical staff could significantly impair our ability to identify and secure
new business opportunities and otherwise disrupt operations. We do not maintain
key person life insurance on any of our senior management members.
WE ENGAGE IN HEDGING TRANSACTIONS, WHICH MAY LIMIT OUR POTENTIAL GAINS AND
EXPOSE US TO RISK OF FINANCIAL LOSS.
We periodically purchase or sell derivative instruments covering a
portion of our expected production in order to manage our exposure to price risk
in marketing our oil and natural gas. These instruments may include futures
contracts and options sold on the New York Mercantile Exchange and privately
negotiated forwards, swaps and options. These transactions may limit our
potential gains if oil and natural gas prices were to rise substantially over
the prices established by hedging. These transactions also may expose us to the
risk of financial loss in certain circumstances, including the following:
- production is less than the volume hedged;
- there is a widening of price differentials between delivery points
for our production and the delivery point assumed in hedging
arrangements;
- the counterparties to our derivative instruments fail to perform;
- we fail to make timely deliveries; and
- a sudden unexpected event materially impacts oil or natural gas
prices.
SHORTAGE OF RIGS, EQUIPMENT, SUPPLIES OR PERSONNEL MAY RESTRICT OUR OPERATIONS.
The oil and gas industry is cyclical and, from time to time, there is a
shortage of drilling rigs, equipment, supplies or personnel. During these
periods, the costs and delivery times of rigs, equipment and supplies are
substantially greater. In addition, demand for, and wage rates of, qualified
drilling rig crews rise with increases in the number of active rigs in service.
Shortages of drilling rigs, equipment, supplies or personnel could delay or
restrict our exploration and development operations, which in turn could impair
our financial condition and results of operations.
OUR DEBT SERVICE OBLIGATIONS MAY ADVERSELY AFFECT OUR CASH FLOW AND OUR
FINANCIAL AND OPERATING ACTIVITIES.
Our level of indebtedness may have important consequences for us,
including the following:
- our ability to obtain additional financing for acquisitions,
working capital or other expenditures could be impaired or
financing may not be available on acceptable terms;
- a substantial portion of our cash flow will be used to make
interest and principal payments on our debt, reducing the funds
that would otherwise be available for our operations and future
business opportunities;
- a substantial decrease in our revenues as a result of lower oil
and natural gas prices, decreased production or other factors
could make it difficult for us to meet debt service requirements
and force us to modify our operations; and
- making us more vulnerable to a downturn in our business or the
economy in general.
THE COVENANTS IN OUR DEBT AND FINANCING ARRANGEMENTS RESTRICT OUR FINANCIAL AND
OPERATING FLEXIBILITY AND OUR FAILURE TO COMPLY WITH THEM COULD HAVE A MATERIAL
ADVERSE EFFECT ON OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our debt and financing arrangements contain a number of significant
limitations that restrict our ability to, among other things, borrow additional
money and sell assets. These restrictions may affect our flexibility in planning
for and reacting to changes in our business, including possible acquisition
activities. The restrictions may
15
also affect our ability to obtain additional future financing for working
capital, capital expenditures, acquisitions, general corporate purposes or other
purposes.
From time to time, we may require consents or waivers from our lenders
to permit any necessary actions that are prohibited by our debt and financing
arrangements. If in the future our lenders refuse to provide any necessary
waivers of the restrictions contained in our debt and financing arrangements,
then we could be in default under our debt and financing arrangements, and we
could be prohibited from undertaking actions that are necessary to maintain and
expand our business.
INVESTORS IN OUR SECURITIES MAY ENCOUNTER DIFFICULTIES IN OBTAINING, OR MAY BE
UNABLE TO OBTAIN, RECOVERIES FROM ARTHUR ANDERSEN LLP WITH RESPECT TO ITS AUDITS
OF OUR FINANCIAL STATEMENTS.
On March 14, 2002, our previous independent public accountant, Arthur
Andersen LLP, was indicted on federal obstruction of justice charges arising
from the federal government's investigation of Enron Corp. On June 15, 2002, a
jury returned with a guilty verdict against Arthur Andersen following a trial.
As a public company, we are required to file with the Securities and Exchange
Commission periodic financial statements audited or reviewed by an independent
public accountant. In July 2002, we engaged Ernst & Young LLP to serve as our
new independent auditors for fiscal 2002. However, included in this annual
report on Form 10-K for the year ended December 31, 2003 is financial data and
other information for the year ended December 31, 2001 that was audited by
Arthur Andersen. Investors in our securities may encounter difficulties in
obtaining, or be unable to obtain, from Arthur Andersen with respect to its
audits of our financial statements, relief that may be available to investors
under the federal securities laws against auditing firms.
ANTI-TAKEOVER PROVISIONS IN OUR CERTIFICATE OF INCORPORATION, BY-LAWS AND
DELAWARE LAW COULD DISCOURAGE A CHANGE OF CONTROL OF OUR COMPANY AND COULD
NEGATIVELY AFFECT OUR STOCK PRICE.
Provisions in our certificate of incorporation and by-laws, each as
amended to date, and applicable provisions of the Delaware General Corporation
Law may make it more difficult and expensive for a third party to acquire
control of us even if a change of control would be beneficial to the interests
of our stockholders. These provisions could discourage potential takeover
attempts and could adversely affect the market price of our common stock. Our
certificate of incorporation and by- laws, each as amended to date:
- classify the board of directors into staggered, three-year terms,
which may lengthen the time required to gain control of our board
of directors;
- limit who may call special meetings;
- prohibit stockholder action by written consent, requiring all
actions to be taken at a meeting of the stockholders;
- do not permit cumulative voting in the election of directors,
which would otherwise allow holders of less than a majority of
stock to elect some directors;
- limit the ability of stockholders to remove directors by providing
that they may only be removed for cause; and
- allow our board of directors to determine the powers, preferences
or rights and the qualifications, limitations and restrictions of
shares of our preferred stock.
In addition, Section 203 of the Delaware General Corporation Law may discourage,
delay or prevent a change in control by prohibiting us from engaging in a
business combination with an interested stockholder for a period of three years
after the person becomes an interested stockholder.
COMPETITION
We operate in the highly competitive exploration and production segment
of the oil and gas industry. We compete with major oil and gas companies, other
independent oil and gas concerns and individual producers and operators in the
areas of reserve and leasehold acquisitions and the exploration, development,
production and marketing of oil and natural gas, as well as contracting for
equipment and the hiring of personnel. The principal
16
competitive factors in acquiring, discovering, producing and marketing oil and
natural gas reserves are the availability and hiring of qualified personnel,
technology and financial resources. We may be at a disadvantage to many of our
competitors in one or more of these areas due to our size relative to other
companies in the industry.
MARKETING AND CUSTOMERS
We market the majority of the natural gas and oil production from
properties we operate for both our account and the account of the other working
and royalty interest owners in these properties. In some instances, we also
market our non-operated natural gas and crude oil production to enhance price
realization and cash flow. The production is sold to a variety of purchasers.
The terms of sale under the majority of existing contracts are short- term,
usually one to three months in duration. The prices received for natural gas and
oil sales are tied to monthly or daily indices as quoted in industry
publications.
In order to achieve more predictable cash flow and reduce exposure to
price volatility of natural gas and crude oil, we utilize fixed price sales and
derivative agreements for a portion of our production with unaffiliated third
parties. Please read Note 10 to our Consolidated Financial Statements for
information regarding our derivative instruments.
Other than the amortization of deferred revenue associated with the
Production Payment, no customer accounted for more than 10% of our revenues in
2003, 2002 or 2001.
SEASONALITY
Demand for natural gas and oil is seasonal and is principally related
to weather conditions and access to pipeline transportation.
EMPLOYEES
At December 31, 2003, we employed a total of 129 persons. None of our
employees are represented by a labor union. Relations between us and our
employees are considered to be satisfactory.
AVAILABLE INFORMATION
Our Internet website is www.kcsenergy.com. The Investor Relations
portion of our Internet website is www.kcsenergy.com/html/investor.html and it
contains information about us, including our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended. These reports are available free of
charge on the Investor Relations portion of our Internet website on the same day
that we electronically file these materials with, or furnish these materials to,
the Securities and Exchange Commission.
ITEM 2. PROPERTIES.
Reference is made to Item 1. Business, "-Oil and Gas Properties," "-Oil
and Natural Gas Reserves," "-Production," "-Acreage," "-Title to Interests,"
"-Drilling Activities" and "-Other Facilities" included elsewhere in this annual
report on Form 10-K.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to Note 11 to our Consolidated Financial Statements
included elsewhere in this annual report on Form 10-K.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted to a vote of our security holders through the
solicitation of proxies or otherwise during the fourth quarter of the fiscal
year ended December 31, 2003.
17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock is traded on the New York Stock Exchange under the
symbol "KCS." As of March 5, 2004, there were approximately 949 holders of
record of our common stock. This number does not include any beneficial owners
for whom shares of common stock may be held in "nominee" or "street" name. The
following table sets forth, for each quarterly period during fiscal 2003 and
2002, the high and low sales price per share of our common stock, as reported in
the composite transaction reporting system.
COMMON STOCK
PRICE RANGE
----------------------------
HIGH LOW
------ ------
FISCAL 2002
First Quarter $ 3.32 $ 1.63
Second Quarter 4.01 1.75
Third Quarter 2.70 1.14
Fourth Quarter 2.25 1.15
FISCAL 2003
First Quarter $ 3.06 $ 1.76
Second Quarter 5.70 2.31
Third Quarter 7.64 4.71
Fourth Quarter 10.84 6.77
On March 12, 2004, the last reported sale price of our common stock on
the New York Stock Exchange was $10.91 per share.
DIVIDEND POLICY
We have not declared or paid any cash dividends on our common stock
since 1999. We intend to retain earnings for use in the operation and expansion
of our business, and therefore do not anticipate declaring or paying a cash
dividend on our common stock in the foreseeable future. In addition, our bank
credit facility prohibits the payment of cash dividends on our common stock.
18
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information with respect to shares of
our common stock that may be issued upon the exercise of options, warrants and
rights under all of our existing equity compensation plans as of December 31,
2003.
EQUITY COMPENSATION PLAN INFORMATION
-------------------------------------------------------------------------------
NUMBER OF SECURITIES
NUMBER OF SECURITIES REMAINING AVAILABLE
TO BE ISSUED UPON WEIGHTED-AVERAGE FOR FUTURE ISSUANCE UNDER
EXERCISE OF EXERCISE PRICE OF EQUITY COMPENSATION
OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, PLANS (EXCLUDING SECURITIES
WARRANTS AND RIGHTS WARRRANTS AND RIGHTS REFLECTED IN COLUMN ( a ))
PLAN CATEGORY ( a ) ( b ) (C)
- ------------- ----------------------------------------------- ---------------------------
Equity compensation
plans approved by security holders - - -
Equity compensation
plans not approved by
security holders 1,885,722(1) $ 4.36 2,736,674 (2)
------------------------------------------ ---------------------------
Total 1,885,722(1) $ 4.36 2,736,674 (2)
========================================== ===========================
- ----------
(1) Represents options granted under the KCS Energy, Inc. 2001 Employee and
Directors Stock Plan.
(2) Includes 1,289,493 shares authorized for issuance pursuant to our 2001
Employee and Directors Stock Plan, 756,595 shares authorized for issuance
pursuant to our employee stock purchase program and 690,586 shares
authorized for issuance in connection with our savings and investment
(401(k)) plan.
INFORMATION REGARDING EQUITY COMPENSATION PLANS THAT HAVE NOT BEEN APPROVED BY
STOCKHOLDERS.
KCS Energy, Inc. 2001 Employees and Directors Stock Plan, or 2001 Stock
Plan. The 2001 Stock Plan was adopted as part of our plan of reorganization, or
the Plan, under Chapter 11 of Title 11 of the United States Bankruptcy Code. The
Plan was approved by our stockholders and creditors. However, our stockholders
did not consider and vote on the 2001 Stock Plan independently of their
consideration of the Plan. Please read Notes 2 and 4 to our Consolidated
Financial Statements. The 2001 Stock Plan provides that stock options, stock
appreciation rights, restricted stock and bonus stock may be granted to our
employees. The 2001 Stock Plan provides that each non-employee director will be
granted stock options for 1,000 shares of our common stock on an annual basis.
The 2001 Stock Plan also provides that in lieu of cash, each non-employee
director may be issued our common stock with a fair market value equal to 50% of
the non-employee directors' annual retainer. The 2001 Stock Plan provides that
the option price of shares issued under the plan shall be equal to the market
price on the date of grant. All options expire 10 years after the date of grant.
The 2001 Stock Plan provides for the issuance of up to 4,362,868 shares of our
common stock. As of December 31, 2003, grants of 681,404 restricted shares were
outstanding under the 2001 Stock Plan.
Other Plans. Shortly after our formation in May 1988, we adopted, among
other benefit programs, an employee stock purchase plan and a savings and
investment plan. The stockholders of our former parent company did not
specifically vote to approve these plans, but they did approve a plan
authorizing our spin-off and formation that included provisions stating the
intent to adopt benefit plans similar to those of the former parent.
Employee Stock Purchase Plan. Under the employee stock purchase plan,
eligible employees and directors may purchase full shares from us at a price per
share equal to 90% of the market value determined by the closing price on the
date of purchase. The maximum annual purchase amount for our employees is the
number of shares costing no more than 10% of the eligible employee's annual base
salary. The maximum annual purchase amount for our directors is 6,000 shares.
Savings and Investment Plan. Under the savings and investment plan,
eligible employees may contribute a portion of their compensation, as defined in
the plan, to the savings and investment plan, subject to certain Internal
19
Revenue Service limitations. We may provide matching contributions, currently
set by the board of directors at 50% of the employee's contribution (up to 6% of
the employee's compensation, subject to certain regulatory limitations). The
savings and investment plan also contains a profit-sharing component whereby the
board of directors may declare annual discretionary profit-sharing
contributions. Our matching contributions and discretionary profit-sharing
contributions vest over a four-year employment period. Once the four-year
employment period has been satisfied, all of our matching contributions and
discretionary profit-sharing contributions immediately vest.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth our selected historical financial data
for each of the five years in the period ended December 31, 2003. The selected
historical financial data set forth below has been derived from our audited
consolidated financial statements included elsewhere in this annual report on
Form 10-K. This information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our audited consolidated financial statements and related notes included
elsewhere in this annual report on Form 10-K.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
2003 (1) 2002 (2) 2001 2000 1999
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT RATIOS)
INCOME STATEMENT DATA:
Oil and natural gas revenue ................................... $ 131,940 $ 74,820 $ 111,345 $ 190,511 $ 134,124
Amortization of deferred revenue of
production payment sold in 2001 ........................... 27,886 45,182 63,089 -- --
Other, net .................................................... 5,001 (1,183) 17,557 1,478 4,494
--------- --------- --------- --------- ---------
Total revenues and other ............................. 164,827 118,819 191,991 191,989 138,618
--------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses .................................. 26,461 25,246 30,456 27,801 28,751
Production taxes .......................................... 8,145 5,589 8,195 6,605 3,524
General and administrative expenses ....................... 8,011 8,255 8,885 8,417 9,797
Stock compensation ........................................ 2,715 782 1,419 -- --
Bad debt expense .......................................... 339 215 4,074 400 50
Restructuring cost ........................................ -- -- -- -- 1,886
Asset retirement obligation accretion ..................... 1,116 -- -- -- --
Depreciation, depletion and amortization .................. 47,885 49,251 58,314 50,451 50,967
--------- --------- --------- --------- ---------
Total operating costs and expenses ................... 94,672 89,338 111,343 93,674 94,975
--------- --------- --------- --------- ---------
Operating income .............................................. 70,155 29,481 80,648 98,315 43,643
Interest and other income ..................................... 112 279 1,319 101 702
Interest expense (contractual interest
for 2000 was $36,220) ..................................... (20,970) (19,945) (21,799) (41,460) (40,005)
--------- --------- --------- --------- ---------
Income before reorganization items and income taxes ........... 49,297 9,815 60,168 56,956 4,340
Reorganization items
Write-off of deferred debt issuance costs
related to senior notes
and senior subordinated notes ......................... -- -- -- (6,132) --
Financial restructuring costs ............................. -- -- (3,175) (10,334) --
Interest income ........................................... -- -- 227 1,033 --
--------- --------- --------- --------- ---------
Reorganization items, net ............................ -- -- (2,948) (15,433) --
--------- --------- --------- --------- ---------
Income before income taxes and cumulative effect of
accounting change ........................................... 49,297 9,815 57,220 41,523 4,340
Federal and state income tax expense (benefit) ................ (20,229) 13,763 (8,359) -- --
--------- --------- --------- --------- ---------
Net income (loss) before cumulative effect
of accounting change ...................................... 69,526 (3,948) 65,579 41,523 4,340
Cumulative effect of accounting change, net of tax ............ (934) (6,166) -- -- --
--------- --------- --------- --------- ---------
Net income (loss) ............................................. 68,592 (10,114) 65,579 41,523 4,340
Dividends and accretion of issuance costs on
preferred stock ........................................... (909) (1,028) (1,761) -- --
--------- --------- --------- --------- ---------
Income (loss) available to common stockholders ................ $ 67,683 $ (11,142) $ 63,818 $ 41,523 4,340
========= ========= ========= ========= =========
Earnings (loss) per common share:
Basic income (loss) ...................................... $ 1.71 $ (0.31) $ 2.02 $ 1.42 $ 0.15
Diluted income (loss) .................................... $ 1.61 $ (0.31) $ 1.69 $ 1.42 $ 0.15
20
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2003 2002 2001 2000 1999
------- ------- ------- ------- -------
(IN THOUSANDS)
OTHER FINANCIAL DATA:
Net cash provided by operating activities..... 71,022 20,825 183,419 128,007 71,463
Capital expenditures ......................... 88,791 47,508 87,192 69,078 59,160
Ratio of earnings to fixed charges ........... 3.20 1.43 3.50 1.97 1.08
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit) .................... (20,792) (16,479) (3,053) 49,230(3) (10,950)(3)
Total assets ................................. 342,966 268,133 346,726 347,335 284,932
Long-term debt:
Bank credit facilities ................... 17,000 500 -- 76,705(4) 107,095 (4)
11% Senior Notes ......................... -- 61,274 79,800 150,000 149,724 (4)
8 7/8% Senior Subordinated Notes ......... 125,000 125,000 125,000 125,000 125,000 (4)
Deferred revenue ............................. 38,696 66,582 111,880 -- --
Preferred stock .............................. -- 12,859 15,589 -- --
Stockholders' equity (deficit) ............... 98,031 (42,716) (39,460) (108,320) (149,843)
- ----------------------------
(1) Includes a $19.0 million non-cash income tax benefit related to the
reversal of a portion of our valuation allowance against net deferred
income tax assets and a $0.9 million non-cash charge related to the
cumulative effect of an accounting change as a result of the adoption of
SFAS No. 143, "Accounting for Asset Retirement Obligations."
(2) Includes a $15.9 million non-cash write-down to zero of the book value of
net deferred tax assets and a $6.2 million non-cash charge for the
cumulative effect of an accounting change related to the amortization
method of oil and gas properties.
(3) Excludes debt classified as current liability.
(4) Included in current liabilities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following is a discussion and analysis of our financial condition
and results of operations and should be read in conjunction with our
consolidated financial statements and related notes included elsewhere in this
annual report on Form 10-K.
FORWARD-LOOKING STATEMENTS
The information discussed in this annual report on Form 10-K includes
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements, other than statements of historical facts, included
herein concerning, among other things, planned capital expenditures, increases
in oil and natural gas production, the number of anticipated wells to be drilled
in the future, our financial position, business strategy and other plans and
objectives for future operations, are forward-looking statements. These
forward-looking statements are identified by their use of terms and phrases such
as "expect," "estimate," "project," "plan," "believe," "achievable,"
"anticipate" and similar terms and phrases. Although we believe that the
expectations reflected in any forward-looking statements are reasonable, they do
involve certain assumptions, risks and uncertainties. Our actual results could
differ materially from those anticipated in these forward-looking statements as
a result of certain factors, including:
- the timing and success of our drilling activities;
- the volatility of prices and supply of, and demand for, oil and
natural gas;
- the numerous uncertainties inherent in estimating quantities of
oil and natural gas reserves and actual future production rates
and associated costs;
- our ability to successfully identify, execute or effectively
integrate future acquisitions;
21
- the usual hazards associated with the oil and gas industry
(including fires, well blowouts, pipe failure, spills, explosions
and other unforeseen hazards);
- our ability to effectively market our oil and natural gas;
- the results of our hedging transactions;
- the availability of rigs, equipment, supplies and personnel;
- our ability to acquire or discover additional reserves;
- our ability to satisfy future capital requirements;
- changes in regulatory requirements;
- the credit risks associated with our customers;
- economic and competitive conditions;
- our ability to retain key members of senior management and key
employees;
- uninsured judgments or a rise in insurance premiums;
- continued hostilities in the Middle East and other sustained
military campaigns and acts of terrorism or sabotage; and
- if underlying assumptions prove incorrect.
These and other risks are described in greater detail in "Business -
Risk Factors" included elsewhere in this annual report on Form 10-K. All
forward-looking statements attributable to us or persons acting on our behalf
are expressly qualified in their entirety by these factors. Other than required
under the securities laws, we do not assume a duty to update these
forward-looking statements, whether as a result of new information, subsequent
events or circumstances, changes in expectations or otherwise.
OVERVIEW
The year ended December 31, 2003 was one of the most successful in our
history. We focused on a low-risk drilling program in our core areas of
operation where we experienced significant increases in oil and natural gas
reserves and production. We drilled 78 wells during 2003, of which 72 were
completed, resulting in a 92% success rate. Production from our properties
averaged 77.2 MMcf per day of natural gas and 3,002 barrels of oil and natural
gas liquids per day, or 95.2 MMcfe per day for 2003. We increased production
24%, from an average of 83.9 MMcfe per day during the first quarter to an
average of 104.1 MMcfe per day during the fourth quarter. Oil and natural gas
reserves increased during 2003 to 268.3 Bcfe, which include reserve additions
of 93.8 Bcfe, replacing 336% of our 2003 net production. Including positive
reserve revisions of 10.5 Bcfe, our overall reserve replacement rate was 373%.
We took several major steps during 2003 to further strengthen our
financial condition, lower interest costs and provide increased financial
flexibility. The balance of our outstanding Series A Convertible Preferred Stock
was converted into shares of our common stock. This conversion simplified our
overall capital structure and eliminated the 5% dividend obligation associated
with the preferred stock. In the first quarter we paid off our maturing senior
note obligations. In the fourth quarter, we amended and restated our bank credit
facility, which increased our revolving credit capacity to $100 million and
significantly reduced our borrowing costs. We also completed a public offering
of 6.9 million shares of our common stock. We used a portion of the net proceeds
of approximately $52 million to repay borrowings under our bank credit facility
and to accelerate our drilling program in certain core areas. Our successful
drilling program, along with strong oil and natural gas prices and proceeds from
our public common stock offering, allowed us to reduce debt from $186.8 million,
or $0.95 per Mcfe of reserves, at the beginning of the year to $142.0 million,
or $0.53 per Mcfe of reserves, at the end of the year.
In the Mid-Continent region, we concentrate our drilling programs
primarily in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins)
and west Texas. Our Mid-Continent region operations provide us with a solid base
for production and reserve growth. We plan to continue to exploit areas within
the various basins that require low-risk exploitation wells for additional
reservoir drainage. Our exploitation wells are generally step-out and extension
type wells with moderate reserve potential. During 2003, we drilled 58 wells in
this region with a success
22
rate of 95%. We have a multi-year inventory of locations in the Mid-Continent
region and plan to increase the level of drilling in our Elm Grove, Talihina and
Joaquin fields and to continue the development program in our Sawyer Canyon
Field in 2004.
In the Gulf Coast region, we concentrate our drilling programs
primarily in south Texas. We also have working interests in several minor
non-operated offshore and Mississippi salt basin properties. We conduct
development programs and pursue moderate-risk, higher potential exploration
drilling programs in this region. Our Gulf Coast operations have numerous
exploration prospects that are expected to provide us additional growth. During
2003, we drilled 6 exploratory and 13 development wells in this region with a
success rate of 84%. All of the wells drilled during 2003, except one
non-operated offshore well, were located in south Texas. We anticipate drilling
20-26 wells in this region in 2004, approximately half of which will be
exploratory.
We believe that the steps taken during 2003 position us to grow our
reserves and production through a balanced investment program including low-risk
exploitation and development activities in the Mid-Continent and Gulf Coast
regions and moderate-risk, higher potential exploration drilling programs in the
onshore Gulf Coast region.
MAJOR INFLUENCES ON RESULTS OF OPERATIONS
Oil and natural gas prices. Oil and natural gas prices have been, and
are expected to continue to be, volatile. Prices for oil and natural gas
fluctuate widely in response to relatively minor changes in the supply of and
demand for oil and natural gas, market uncertainty, and a variety of additional
factors beyond our control, including worldwide political conditions (especially
in the Middle East and other oil-producing regions), the domestic and foreign
supply of oil and natural gas, the level of consumer demand, weather conditions,
domestic and foreign government regulations and taxes, the price and
availability of alternative fuels and overall economic conditions.
The price we receive for our natural gas production is generally 7 to
12 cents below NYMEX prices. The primary factors for this differential are the
geographic locations of our producing properties and the Btu content of our
natural gas. The average Btu content of our natural gas is in excess of 1,000
Btu per cubic foot. The price we receive for our oil production is generally
$1.60 to $1.75 below the Koch West Texas Intermediate posted prices for sweet
crude in Texas / New Mexico.
Our reported realized prices for oil and natural gas are also affected
by the Production Payment we sold in February 2001 at a weighted average
realized discounted price of $4.05 per Mcfe which has the effect of lowering our
reported realized price in periods when cash prices exceed $4.05 per Mcfe and
raising our reported realized prices when cash prices are lower than $4.05 per
Mcfe. The effect of the Production Payment was to reduce realized prices by
$0.29 per Mcfe in 2003 and to increase realized prices by $0.20 per Mcfe in 2002
and $0.02 per Mcfe in 2001.
Certain terminated derivative instruments also affect our reported
realized prices. In February 2001, we terminated $2.055 per MMBtu swaps on 10.1
million MMBtu through 2005 that we inherited when we acquired Medallion
California Properties Company and related entities. This resulted in a $28
million hedge loss that is being amortized as a non-cash reduction of revenue
over the original term of the derivative instruments. The effect of this
amortization of the cost of these terminated swaps was to reduce realized prices
by $0.16, $0.18 and $0.17 per Mcfe in 2003, 2002 and 2001, respectively.
Production. The primary factors affecting our production levels are
capital availability, the success of our drilling program and, in recent years,
the winding down and expiration of our purchased VPP program in 2002.
In 2002, our main objective was to position ourselves to meet our
Senior Note obligations that were due in January 2003. In order to do so, we
curtailed our capital spending program and sold certain non-core producing
properties. As a result of the property sales and curtailed drilling, our
production declined significantly compared to 2001. In 2003, with our Senior
Note obligations having been met, we were able to direct our cash flow to our
drilling operations and increase production levels throughout the year.
In 2001, 4.5 Bcfe, or 10%, of our 2001 production and in 2002, 2.5
Bcfe, or 7%, of our 2002 production was derived from our purchased VPP program.
We have not made any VPP investments since 1999 as our primary focus since that
time has been to add oil and natural gas reserves through the drill bit. Final
deliveries under our existing VPPs were received in November 2002. Although
specific terms of our VPPs varied, we were generally entitled to receive
delivery of the scheduled oil and natural gas volumes at agreed delivery points,
free of drilling and lease operating expenses and free of state production
taxes.
23
During the life of the program, we invested $213.6 million to acquire reserves
of 120.3 Bcfe of natural gas and oil and realized approximately $293.9 million
from the sale of oil and natural gas acquired as well as an additional 10.6 Bcfe
under a VPP that was converted to a working interest.
Our reported production includes volumes dedicated to the Production
Payment sold in 2001 discussed below. However, we view the net production after
our delivery obligations associated with the Production Payment as more
important because that is what generates cash flow. For example, while total
production declined from 37.4 Bcfe in 2002 to 34.7 Bcfe in 2003 due to the
expiration of purchased VPP's, our net production actually increased from 26.2
Bcfe in 2002 to 27.9 Bcfe in 2003 as delivery obligations associated with the
Production Payment declined from 11.2 Bcfe in 2002 to 6.8 Bcfe in 2003. This 1.7
Bcfe increase in net production in 2003 resulted in incremental cash flow of
approximately $8.6 million.
Sale of Production Payment. In February 2001, we sold a 43.1 Bcfe
production payment, referred to in this annual report on Form 10-K as the
Production Payment, in connection with our emergence from bankruptcy. The net
proceeds from this sale of approximately $175 million was recorded as deferred
revenue and is amortized over the five-year period that scheduled deliveries of
production are made. Deliveries under this Production Payment are recorded as
non-cash oil and gas revenue with a corresponding reduction of deferred revenue
at the weighted average price of approximately $4.05 per Mcfe. We also reflect
the production volumes and depletion expense as deliveries are made. However,
the associated oil and natural gas reserves are excluded from our oil and
natural gas reserve data. Amortization of deferred revenue comprised 17%, 38%
and 36% of our oil and gas revenue during 2003, 2002 and 2001, respectively. At
December 31, 2003, 9.3 Bcfe remained to be delivered under the Production
Payment of which 5.2 Bcfe will be delivered in 2004, 3.9 Bcfe in 2005 and 0.2
Bcfe in 2006.
Operating Costs. We monitor our business to control costs from both a
gross dollar standpoint and from a per unit of production perspective.
We are able to control our lease operating expenses largely because we
are focused in certain core areas which allows us to operate efficiently. Lease
operating expenses were $30.5 million in 2001, $25.2 million in 2002 and $26.5
million in 2003. In terms of gross dollars, these costs fluctuated primarily due
to levels of production and workover activities. In order to measure our
operating performance, we monitor lease operating expenses on a per unit of
production basis excluding the production received under our purchased VPP
program because volumes received under the purchased VPP program were free from
these expenses as discussed above. Lease operating expenses (excluding
production from purchased VPPs) per Mcfe were $0.76 in 2003, $0.72 in 2002 and
$0.73 in 2001.
General and administrative expenses are monitored closely with the
objective of operating an efficient organization with an appropriate cost
structure. In 2001 and 2002, we reduced our staff in response to limited capital
availability and curtailed drilling activity. In 2003, we added staff modestly
in response to our resumed growth. General and administrative expenses were $8.9
million, or $0.19 per Mcfe, in 2001, $8.3 million, or $0.22 per Mcfe in 2002 and
$8.0 million, or $0.23 per Mcfe in 2003.
FACTORS AFFECTING COMPARABILITY
Income Taxes. Our 2003 results included a $19.0 million non-cash income
tax benefit resulting from the reversal of a portion of our valuation allowance
against net deferred income tax assets while 2002 includes a $15.9 million
non-cash write-down to zero of the book value of net deferred tax assets.
During the second quarter of 2002, uncertainty resulting from
relatively low commodity prices and the January 2003 maturity date for our
senior notes led management to increase the valuation allowance by $15.9
million. This increase in the valuation allowance reduced the carrying value of
net deferred assets to zero. Since that time, we have generated significant
levels of taxable income thereby utilizing a portion of our deferred tax asset
and the future outlook for taxable income has improved substantially. Oil and
natural gas prices have improved significantly and are expected to remain
relatively high for the foreseeable future based on existing available
information, including current prices quoted on the New York Mercantile
Exchange. Therefore, during 2003, we reversed approximately $19 million of the
valuation allowance related to expected taxes on future years' taxable income,
which is reflected as an income tax benefit in the condensed statements of
consolidated operations.
Accounting Changes. Our 2002 results included a $6.2 million charge
against earnings related to our change to the
24
unit-of-production method of accounting for depreciation, depletion and
amortization. This charge is reflected as a cumulative effect of accounting
change, net of tax. In 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligation" and recorded a $0.9 million charge against earnings as a
cumulative effect of an accounting change.
Sale of Emission Credits. We sold emission credits totaling $4.9
million and $9.3 million in 2003 and 2001, respectively. We did not sell any
emission credits in 2002. We currently do not anticipate any significant
emission credit sales in 2004.
Purchased VPPs. As discussed above under "Major Influences on Results
of Operations--Production," the decision to cease purchases of VPPs in 1999 and
the expiration of volumes received under the purchased VPP program affects the
comparability of our production, lease operating expenses and production taxes.
Stock Compensation. Stock compensation was $2.7 million, $0.8 million
and $1.4 million in 2003, 2002 and 2001, respectively. These non-cash expenses
reflect the amortization of restricted stock grants and expenses associated with
certain stock options granted in 2001 that are subject to variable accounting.
The stock option expenses can fluctuate significantly as the expense recognized
during a reporting period is directly related to the movement in the market
price of our common stock during that period.
Reorganization. In 2000, we conducted a reorganization in bankruptcy,
and the United States Bankruptcy Court for the District of Delaware confirmed
our plan of reorganization in 2001. Under the reorganization plan, holders of
our senior notes and senior subordinated notes received all accrued and unpaid
interest, our senior noteholders received a partial pre-payment of principal,
our trade creditors were paid in full and our stockholders retained 100% of
their common stock, subject to dilution upon conversion of the $30 million of
Series A Convertible Preferred Stock sold in connection with our emergence from
bankruptcy. The Consolidated Statement of Operations for 2001 included $2.9
million of net costs associated with the reorganization.
CRITICAL ACCOUNTING POLICIES
The discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States, or GAAP. The preparation of these financial statements requires
us to make estimates and judgments that affect our financial condition and
results of operations. Our significant accounting policies are described in Note
1 to our Consolidated Financial Statements contained elsewhere in this annual
report on Form 10-K. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts could have been reported under different
conditions, or if different assumptions had been used. We discussed the
development, selection, and disclosure of each of these critical accounting
estimates with the audit committee of our board of directors. The following
discussion details the more significant accounting policies, estimates and
judgments.
Full Cost Method of Accounting for Oil and Gas Operations
The accounting for our business is subject to accounting rules that are
unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities: (i) the successful efforts
method and (ii) the full cost method. We have elected to use the full cost
method to account for our investment in oil and gas properties. Under this
method, we capitalize all acquisition, exploration and development costs into
one country-wide cost center. These costs include lease acquisitions, geological
and geophysical services, drilling, completion, equipment, certain salaries and
other internal costs directly attributable to these activities. These costs are
then amortized over the remaining life of the aggregate oil and natural gas
reserves using the "unit-of-production" method of calculating depletion expense
discussed below under "Amortization of Oil and Gas Properties." The full cost
method embraces the concept that dry holes and other expenditures that fail to
add reserves are intrinsic to the oil and gas exploration business and are
therefore capitalized. Although some of these costs will ultimately result in no
additional reserves, they are part of a program from which we expect the
benefits of successful wells to more than offset the costs of any unsuccessful
ones. As a result, we believe the full cost method of accounting is appropriate
and accurately reflects the economics of our programs for the acquisition,
exploration and development of oil and natural gas reserves. Under the
successful efforts method, costs of exploratory dry holes and geological and
geophysical exploration costs that would be capitalized under the full cost
method would be charged against earnings
25
during the periods in which they occur. Accordingly, our financial position and
results of operations may have been significantly different had we used the
successful efforts method of accounting for our oil and gas investments.
Oil and Natural Gas Reserve Estimates
Estimates of our proved oil and natural gas reserves are based on the
quantities of oil and natural gas that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. The accuracy
of any oil and natural gas reserve estimate is a function of the quality of
available data, engineering and geological interpretation and judgment. For
example, we must estimate the amount and timing of future operating costs,
severance taxes, development costs and workover costs, all of which may in fact
vary considerably from actual results. In addition, as prices and cost levels
change from year to year, the estimate of proved reserves also may change. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of our reserves.
Despite the inherent imprecision in these engineering estimates,
estimates of our oil and natural gas reserves are used throughout our financial
statements. For example, as we use the unit-of-production method of calculating
depletion expense, the amortization rate of our capitalized oil and gas
properties incorporates the estimated units-of-production attributable to the
estimates of proved reserves. Our oil and gas properties are also subject to a
"ceiling" limitation based in large part on the quantity of our proved reserves.
Finally, these reserves are the basis for our supplemental oil and gas
disclosures.
The estimates of our proved oil and natural gas reserves have been
audited or prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
Amortization of Oil and Gas Properties
Effective January 1, 2002, we began amortizing the capitalized costs
related to our oil and gas properties under the unit-of-production, or UOP,
method using proved oil and natural gas reserves. Under the UOP method, the
depreciation, depletion and amortization rate is computed based on the ratio of
production to total reserves. This rate is applied to the amortizable base of
our oil and gas properties (the net book value of oil and gas properties less
the costs of unevaluated oil and gas properties plus estimated future costs to
develop the oil and gas properties with proved reserves). The calculation of
depreciation, depletion and amortization requires the use of significant
estimates pertaining to oil and natural gas reserves and future development
costs.
Bad Debt Expense
We routinely review all material trade and other receivables to
determine the timing and probability of collection. Many of our receivables are
from joint interest owners on properties we operate. Therefore, we may have the
ability to withhold future revenue disbursements to recover any non-payment of
joint interest billings. We market the majority of our production and these
receivables are generally collected within a month. The receivables for the
remaining production are typically collected within two months. We accrue a
reserve for a receivable when, based on the judgment of management, it is
doubtful that the receivable will be collected in full and the amount of any
reserve required can be reasonably estimated.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to
a purchaser at fixed or determinable prices, when delivery has occurred and
title has transferred and collection of the revenue is probable. We follow the
sales method of accounting for natural gas revenues. Under this method of
accounting, revenues are recognized based on actual production volume sold. The
volume of natural gas sold may differ from the volume to which we are entitled
based on our working interest. An imbalance is recognized as a liability only
when the estimated remaining reserves will not be sufficient to enable the
under-produced owner(s) to recoup its entitled share through future production.
Natural gas imbalances can arise on properties for which two or more owners have
the right to take production "in-kind." In a typical gas balancing arrangement,
each owner is entitled to an agreed-upon percentage of the property's total
production. However, at any given time, the amount of natural gas sold by each
owner may differ from its allowable percentage. Two principal accounting
practices have evolved to account for natural gas imbalances. These methods
differ as to whether revenue is recognized based on the actual sale of natural
gas (sales
26
method) or an owner's entitled share of the current period's production
(entitlement method). We have elected to use the sales method. If we used the
entitlement method, our reported revenues may have been materially different.
Income Taxes
We record deferred tax assets and liabilities to account for the
expected future tax consequences of events that have been recognized in our
financial statements and our tax returns. We routinely assess the realizability
of our deferred tax assets. In making this assessment, we perform an extensive
analysis of our operations to determine the sources of future taxable income.
The analysis consists of a detailed review of all available data, including our
budget for the ensuing year, forecasts based on current as well as historical
prices, and the independent petroleum engineers' reserve report. The
determinations to establish and adjust a valuation allowance requires
significant judgment as the estimates used in preparing budgets, forecasts and
reserve reports are inherently imprecise and subject to substantial revision as
a result of changes in the outlook for prices, production volumes and costs,
among other factors. It is difficult to predict with precision the timing and
amount of taxable income we will generate in the future. Our current net
operating loss carryforwards aggregating approximately $173 million have
remaining lives ranging from 9 to 19 years, with the majority having a life in
excess of 15 years. However, we examine a much shorter time horizon, usually two
to three years, when projecting estimates of future taxable income and making
the determination as to whether the valuation allowance should be adjusted.
Asset Retirement Obligations
We have significant obligations to remove equipment and restore land at
the end of oil and natural gas production operations. Our removal and
restoration obligations are primarily associated with plugging and abandoning
wells. Estimating future asset removal costs is difficult and requires
management to make estimates and judgments as most of the removal obligations
are many years in the future and because contracts and regulations often contain
vague descriptions of what constitutes removal. Asset removal technologies and
costs are constantly changing, as are political, environmental, safety and
public relations considerations.
SFAS No. 143 requires us to record the fair value of a liability for
legal obligations associated with the retirement obligations of tangible
long-lived assets in the periods in which it is incurred. When the liability is
initially recorded, we increase the carrying amount of the related long-lived
asset. The liability is accreted to the fair value at the time of settlement
over the useful life of the asset, and the capitalized cost is depreciated over
the useful life of the related asset. We adopted SFAS No. 143 as of January 1,
2003. As a result, net property, plant and equipment was increased by $10.2
million, an asset retirement obligation of $11.1 million was recorded and a $0.9
million charge against net income was reported in the first quarter of 2003 as a
cumulative effect of a change in accounting principle.
Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing asset
retirement obligation, a corresponding adjustment is made to the oil and gas
property balance. In addition, increases in the discounted asset retirement
obligation resulting from the passage of time will be reflected as accretion
expense in the consolidated statement of operations.
SFAS No. 143 requires a cumulative adjustment to reflect the impact of
implementing the statement had the rule been in effect since inception. We,
therefore, calculated the cumulative accretion expense on the asset retirement
obligation liability and the cumulative depletion expense on the corresponding
property balance. The sum of these cumulative expenses was compared to the
depletion expense originally recorded. As the historically recorded depletion
was lower than the cumulative expense calculated under SFAS No. 143, the
difference resulted in a loss that we recorded as cumulative effect of a change
in accounting principle as of January 1, 2003.
Upon implementation, we also had to determine if the statement required
us to recalculate our historical full-cost ceiling test. We chose not to
recalculate our historical full-cost ceiling test even though our historical oil
and gas property balance would have been higher had we applied the statement
from its inception. We believe this approach is appropriate because SFAS No. 143
is silent on this issue and was not effective during the prior implementation
test periods. If a recalculation of the historical full-cost ceiling test
resulted in impairment, the charge would have increased the cumulative loss
recorded upon adoption and reduced depletion expense subsequent to adoption.
27
We also had to determine how to incorporate the asset retirement
obligations into our 2003 quarterly calculations of our full-cost ceiling test.
SFAS No. 143 is silent with respect to this issue and although there are various
views, we elected to continue to include the capitalized cost of our asset
retirement obligation in our oil and gas property balance and exclude the cash
outflow associated with future abandonment cost from future development cost
when calculating the pre-tax present value of our future net revenues. This
results in both a higher ceiling test threshold and a higher net oil and gas
property balance. Another widely contemplated view is to include the
undiscounted asset retirement obligation as part of future development cost,
essentially reducing the pre-tax present value of future net revenues and to net
the asset retirement obligation recorded on the balance sheet against the oil
and gas property balance. We believe that our approach is more conservative
although at the present time there is no material difference in our ceiling test
calculation using either of these methods.
Prospectively, our depletion expense will be reduced because we will
deplete a discounted asset retirement cost rather than the undiscounted value
previously depleted. The lower depletion expense under SFAS No. 143 is offset,
however, by higher accretion expense, which reflects increases in the discounted
asset retirement obligation over time.
Derivatives
We use commodity derivative contracts on a limited basis to manage our
exposure to oil and natural gas price volatility. We account for our commodity
derivative contracts in accordance with Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", or SFAS No. 133. Realized gains and losses from our cash flow
hedges, including terminated contracts, are generally recognized in oil and
natural gas production revenue when the hedged volumes are produced and sold. We
do not enter into derivative or other financial instruments for trading
purposes.
RESULTS OF OPERATIONS
Income before income taxes and cumulative effect of accounting change
for 2003 was $49.3 million compared to $9.8 million in 2002. This increase was
primarily attributable to higher natural gas and oil prices and the sale of
emission reduction credits, partially offset by decreased oil and natural gas
production due to the expiration of our volumetric production payment, or VPP,
program and the effect of the sale of certain non-core oil and gas properties in
2002. Income tax benefit for 2003 was $20.2 million compared to an income tax
expense of $13.8 million in 2002 due to changes in our valuation allowance
against our net deferred tax asset. Please read Note 9 to our Consolidated
Financial Statements. The cumulative effect of accounting change was $0.9
million, or a $0.02 loss per basic and diluted share, in 2003 resulting from the
adoption of SFAS No. 143. In 2002, the cumulative effect of accounting change
was $6.2 million, or a $0.17 loss per basic and diluted share, which reflected
the change from the future gross revenue method of accounting for amortization
of capitalized costs related to oil and gas properties to the unit-of-production
method. Income available to common stockholders in 2003 was $67.7 million, or
$1.71 per basic share and $1.61 per diluted share, compared to a loss of $11.1
million, or $0.31 per basic and diluted share in 2002.
Income before income taxes and cumulative effect of accounting change
for 2002 was $9.8 million compared to $57.2 million in 2001. Dramatically lower
natural gas prices, lower non-oil and natural gas revenue and lower production
were partially offset by significantly lower operating, reorganization and
interest expenses. Income tax expense for 2002 was $13.8 million compared to an
income tax benefit of $8.4 million in 2001. We reported a net loss before
cumulative effect of accounting change of $3.9 million, or $0.14 per basic and
diluted share, as a result of the non-cash income tax expense in 2002. In 2002,
the cumulative effect of accounting change to the unit-of-production method of
amortization of oil and gas property costs was a $6.2 million loss, or a $0.17
per basic and diluted share. Loss available to common stockholders in 2002 was
$11.1 million, or $0.31 per basic and diluted share, compared to income
available to common stockholders of $63.8 million, or $2.02 per basic share and
$1.69 per diluted share in 2001.
28
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Production: (a)
Natural gas (MMcf) ................. 28,166 29,672 36,873
Oil (Mbbl) ......................... 838 1,003 1,230
Natural gas liquids (Mbbl) ......... 258 288 373
--------- --------- ---------
Total (MMcfe) ................... 34,741 371,417 46,491
Summary (MMcfe)
Working interest (b) .......... 34,741 34,959 41,966
Purchased VPP (c) ............. -- 2,458 4,525
--------- --------- ---------
Total ........................ 34,741 37,417 46,491
Dedicated to Production Payment (6,807) (11,196) (15,716)
--------- --------- ---------
Net Production ............... 27,934 26,221 30,775
Average Price:
Natural gas (per Mcf) .............. $ 4.79 $ 3.25 $ 3.90
Oil (per bbl) ...................... 25.34 20.52 20.67
Natural gas liquids (per bbl) ...... 14.58 10.05 13.74
Total (per Mcfe) (d) ......... $ 4.60 $ 3.21 $ 3.75
Revenue ($000's):
Natural gas ........................ $ 134,833 $ 96,531 $ 143,882
Oil ................................ 21,231 20,578 25,428
Natural gas liquids ................ 3,762 2,893 5,124
--------- --------- ---------
Total ........................ $ 159,826 $ 120,002 $ 174,434
========= ========= =========
- --------------------------------
(a) Production includes volumes dedicated to the Production Payment sold
in February 2001. Please read Notes 1 and 2 to our Consolidated
Financial Statements for more information on the Production Payment.
(b) We sold properties in 2002 and 2001 to reduce debt.
(c) We discontinued making new investments in VPPs in 1999 and final
deliveries were received in November 2002.
(d) Excluding the non-cash effects of volumes delivered under the
Production Payment sold in February 2001 and terminated derivative
contracts associated with the acquisition of Medallion California
Properties Company and related entities, our total average realized
price per Mcfe was $5.05, $3.19 and $3.90 in 2003, 2002 and 2001,
respectively.
Natural Gas Revenue. In 2003, natural gas revenue was $134.8 million
compared to $96.5 million in 2002 as a result of a 47% increase in realized
natural gas prices and a 5% decrease in production. The production decrease was
primarily due to the expiration of our VPP program, as new production from the
successful drilling program essentially offset the impact of 2002 property sales
and the natural decline of producing wells.
In 2002, natural gas revenue was $96.5 million compared to $143.9
million in 2001 as a result of a 17% decrease in realized natural gas prices and
a 20% decline in production. The production decline was primarily due to the
sale of oil and gas properties and the expiration of certain volumetric
production payments. Furthermore, the natural decline of producing properties
was not fully offset by new production largely due to our curtailed capital
investment program.
Oil and Liquids Revenue. In 2003, oil and liquids revenue increased
$1.5 million to $25.0 million primarily due to a 25% increase in the weighted
average realized price offset by a 15% decrease in production. The decrease in
production was attributable to the sale of non-core oil and gas properties in
2002 and natural decline of oil properties as the 2003 drilling program focused
almost entirely on natural gas prospects.
In 2002, oil and liquids revenue decreased $7.1 million to $23.5
million primarily due to a 19% decrease in production. The decrease in
production in 2002 was attributable to the sale of oil and gas properties and
the natural declines of producing properties.
29
Other, net. Other, net was $5.0 million in 2003 compared to a net cost
of $1.2 million in 2002. The increase was primarily attributed to the sale of
emission reduction credits. We do not anticipate that there will be any
significant sales of emission credits in 2004.
Other, net decreased from $17.6 million in 2001 to a net cost of $1.2
million in 2002. Of the $17.6 million in 2001, $9.3 million was from the sale of
emission reduction credits and $7.7 million was from non-cash gains on
derivative instruments that were not designated as oil and natural gas hedges
when we adopted SFAS No. 133. The remainder was primarily attributable to
marketing and transportation revenue incidental to our oil and gas operations.
In 2002, the net cost of $1.2 million was primarily attributable to marketing
and transportation activities.
LEASE OPERATING EXPENSES
For the year ended December 31, 2003, lease operating expenses, or LOE,
increased 5% to $26.5 million, compared to $25.2 million in 2002. On a per unit
basis, LOE was $0.76 per Mcfe of working interest production in 2003 compared to
$0.72 per Mcfe in 2002. The increase was primarily attributed to a higher level
of workover activity on oil and gas wells in 2003.
For the year ended December 31, 2002, LOE decreased 17% to $25.2
million ($0.72 per Mcfe of working interest production), compared to $30.5
million ($0.73 per Mcfe of working interest production) in 2001. Increased focus
on cost reductions and operating efficiency along with lower production largely
due to the sale of certain non-core properties contributed to the reductions.
PRODUCTION TAXES
Production taxes increased $2.5 million to $8.1 million in 2003,
compared to $5.6 million in 2002. Production taxes are generally based on a
percentage of revenue, excluding revenue from our now-terminated VPP program.
The increase was primarily attributable to higher oil and natural gas revenue
associated with higher average realized prices and higher production tax rates
in Louisiana where we significantly increased our production in the Elm Grove
Field.
Production taxes decreased $2.6 million to $5.6 million in 2002
compared to $8.2 million in 2001 due to lower oil and natural gas revenue
associated with the decrease in working interest production and lower average
realized prices.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses decreased $0.3 million to $8.0
million in 2003, compared to $8.3 million in 2002. The decrease resulted from
lower labor costs associated with a reduced work force, partially offset by a
higher incentive compensation expense resulting from improved operating results.
General and administrative expenses in 2002 decreased $0.6 million to
$8.3 million compared to $8.9 million in 2001. The decrease in 2002 resulted
from lower labor costs associated with a reduced work force, partially offset by
an increase in insurance premiums and employment severance payments.
STOCK COMPENSATION
Stock compensation reflects the non-cash expense associated with stock
options issued in 2001 that are subject to variable accounting in accordance
with FASB Interpretation No. 44, "Accounting for Certain Transactions Involving
Stock Compensation", or FIN 44, and the non-cash expense associated with the
amortization of restricted stock grants. Under variable accounting for stock
options, the amount of expense recognized during a reporting period is directly
related to the movement in the market price of our common stock during that
period. For 2003, stock compensation was $2.7 million compared to $0.8 million
in 2002 primarily due to the significant increase in the market price of our
common stock during 2003.
Stock compensation was $0.8 million in 2002 compared to $1.4 million in
2001. These amounts reflect the non-cash amortization of restricted stock
grants. No expense was recorded pursuant to FIN 44 as the options subject to
variable accounting discussed above were "out-of-the-money" during 2002 and
2001. The 2001 expense amount includes incremental costs associated with initial
grants made upon our emergence from bankruptcy to compensate for a portion of
stock options previously issued but cancelled in connection with our plan of
reorganization.
30
BAD DEBT EXPENSE
Bad debt expense was $0.3 million in 2003 compared to $0.2 million in
2002. Bad debt expense was $4.1 million in 2001, primarily due to an allowance
against receivables due from various Enron entities that are now in bankruptcy
for oil and natural gas sales and derivative instruments. We ceased all sales to
Enron entities after November 2001.
ACCRETION OF ASSET RETIREMENT OBLIGATION
Effective January 1, 2003, we adopted SFAS No. 143. Accretion of our
asset retirement obligation was $1.1 million in 2003.
DEPRECIATION, DEPLETION AND AMORTIZATION
For the year ended December 31, 2003, depreciation, depletion and
amortization expense was $47.9 million compared to $49.3 for the year ended
December 31, 2002. This $1.4 million decrease was primarily attributable to
reduced production as a result of the expiration of our VPP program and the sale
of certain non-core oil and gas properties in 2002.
Effective January 1, 2002, we began amortizing our oil and gas
properties using the UOP method based on proved reserves. This change resulted
in additional amortization of $6.2 million through December 31, 2001, which is
classified as a cumulative effect of accounting change, net of tax, in 2002. For
the year ended December 31, 2002, depreciation, depletion and amortization
decreased $9.1 million to $49.3 million. The decrease reflects reduced
production and a lower depletable base.
INTEREST AND OTHER INCOME
Interest and other income was $0.1 million in 2003 compared to $0.3
million in 2002 and $1.3 million in 2001. These amounts primarily represent
interest income earned on accumulated cash and cash equivalents.
INTEREST EXPENSE
Interest expense was $21.0 million in 2003 compared to $19.9 million in
2002. The higher interest expense in 2003 reflects the $2.8 million write-off of
deferred financing costs and a $0.5 million early termination fee paid to a
previous lender as a result of amending and restating our bank credit facility
in November 2003 to increase availability and reduce future interest costs.
Interest expense excluding amortization of deferred financing costs was $1.2
million lower in 2003 compared to 2002 primarily due to lower average
outstanding debt in 2003.
In 2004, we anticipate a significant reduction in interest expense as a
result of lower interest rates associated with our amended and restated bank
credit facility and lower average borrowings following our 2003 public common
stock offering. The proceeds of our 2003 public common stock offering were
initially used to repay debt.
Interest expense was $19.9 million in 2002 compared to $21.8 million in
2001. The decrease reflected the trend of lowering outstanding debt and, to a
lesser extent, lower interest rates on the bank credit facility, partially
offset by a $1.1 million write off of deferred financing costs in December 2002.
REORGANIZATION ITEMS
We completed our bankruptcy proceedings in 2001. Accordingly, there
were no reorganization items in 2003 or 2002. For the year ended December 31,
2001, we recorded $2.9 million of reorganization items, primarily for legal and
financial advisory services in connection with our completed bankruptcy
proceedings.
INCOME TAXES
Income tax benefits were $20.2 million in 2003 compared to income tax
expense of $13.8 million in 2002 and income tax benefits of $8.4 million in
2001. These amounts reflect changes in our valuation allowance against net
deferred income tax assets.
31
During the second quarter of 2002, uncertainty resulting from
relatively low commodity prices and the January 2003 maturity date for our
senior notes led management to increase the valuation allowance by $15.9
million. This increase in the valuation allowance reduced the carrying value of
net deferred assets to zero. Since that time, we have generated significant
levels of taxable income thereby utilizing a portion of our deferred tax asset
and the future outlook for taxable income has improved substantially. Oil and
natural gas prices have improved significantly and are expected to remain
relatively high for the foreseeable future based on existing available
information, including current prices quoted on the New York Mercantile
Exchange. Therefore, during 2003, we reversed approximately $19 million of the
valuation allowance related to expected taxes on future years' taxable income,
which is reflected as an income tax benefit in the condensed statements of
consolidated operations.
In connection with the adoption of SFAS No. 133 on January 1, 2001, we
recorded a liability of $43.8 million representing the fair market value of our
derivative instruments upon adoption and an after-tax charge to other
comprehensive income of $28.5 million from the cumulative effect of a change in
accounting principle. During 2001, we reclassified $23.9 million of the
liability as a non-cash reduction to oil and natural gas revenues and reduced
the valuation allowance related primarily to net operating losses, for a related
tax benefit of $8.4 million.
LIQUIDITY AND CAPITAL RESOURCES
Our liquidity and capital resources improved significantly during 2003.
In January 2003, we amended and restated our bank credit facility to increase
our borrowing availability and paid off the maturing senior note obligations. We
also accelerated our drilling program, resulting in increased production and oil
and natural gas reserves. We drilled 78 wells during 2003 with a success rate of
92%. We increased production 24%, from an average of 83.9 MMcfe per day during
the first quarter to an average of 104.1 MMcfe per day during the fourth
quarter. The increase in production coupled with a strong natural gas and oil
price environment resulted in a substantial increase in cash flow as discussed
below.
We took several major steps during 2003 to further strengthen our
financial condition, lower interest costs and provide increased financial
flexibility. The balance of our outstanding Series A Convertible Preferred Stock
was converted into shares of our common stock. This conversion simplified our
overall capital structure and eliminated the 5% dividend obligation associated
with the preferred stock. In the first quarter we paid off our maturing senior
note obligations. In the fourth quarter of 2003, we amended and restated our
bank credit facility, which increased our revolving credit capacity to $100
million and significantly reduced our borrowing costs. We also completed a
public offering of 6.9 million shares of our common stock. We used a portion of
the net proceeds of approximately $52 million to repay borrowings under our bank
credit facility and to accelerate our drilling program in certain core areas.
Our successful drilling program, along with strong oil and natural gas prices
and proceeds from our public common stock offering, allowed us to reduce debt
during 2003 from $186.8 million, or $0.95 per Mcfe of reserves, at the beginning
of the year to $142.0 million, or $0.53 per Mcfe of reserves, at the end of the
year.
With the completion of the steps outlined above, we believe that we are
positioned to capitalize on the current strong natural gas and oil price
environment, to focus on developing our multi-year prospect inventory, to
increase reserves and production in our core areas and to further reduce debt
per Mcfe.
Our primary cash requirements are for exploration, development and
acquisition of oil and gas properties, operating expenses and debt service.
For 2004, we have budgeted $105 million for capital investments in
natural gas and oil properties and anticipate drilling over 100 wells. Of the
$105 million, we anticipate spending approximately $44 million in the Elm Grove
Field, $14 million at the Joaquin Field, $6 million at the Sawyer Canyon Field,
$3 million at the Talihina Field, $13 million at other Mid-Continent properties,
$13 million on the Gulf Coast exploration program and $12 million on the Gulf
Coast development drilling program. We expect to fund our 2004 exploration and
development activities primarily through internally generated cash flows. The
amount and allocation of our capital investment program is subject to change
based on operational developments, commodity prices, service costs, acquisitions
and numerous other factors. Generally, we do not budget for acquisitions.
We believe that cash on hand, net cash generated from operations and
unused committed borrowing capacity under our bank credit facility will be
adequate to fund our capital expenditure program and satisfy our liquidity
needs. In the future, we may also utilize various financing sources, including
the issuance of debt or equity securities under our shelf registration statement
or through private placements. Our ability to complete future debt
32
and equity offerings and the timing of these offerings will depend upon various
factors including prevailing market conditions, interest rates and our financial
condition.
CASH FLOW FROM OPERATING ACTIVITIES
Net cash provided by operating activities for 2003 was $71.0 million
compared to $20.8 million in 2002. The improvement in our cash flow in 2003 was
primarily due to higher realized oil and natural gas prices and substantially
less production dedicated to repayment of the Production Payment. The net
increase in trade accounts receivable reflects the higher natural gas and oil
price environment in 2003 and the timing of cash receipts. The net change in
accounts payable and accrued liabilities is primarily attributable to increased
drilling well pre-payments received from non-operating working interest owners
and higher incentive compensation accruals.
Net cash provided by operating activities for 2002 was $20.8 million
compared to $183.4 million in 2001. Cash provided by operating activities in
2001 was significantly impacted by the execution of our plan of reorganization,
which included net proceeds of $175.0 million from the Production Payment sold
in February 2001, the payment of $71.5 million of interest expense (including
$49.1 million that pertained to prior years) and the $28.0 million cost of
terminating certain derivative instruments in connection with our emergence from
bankruptcy. Cash provided by operating activities during 2002 was negatively
impacted by lower realized natural gas prices and lower production.
INVESTING ACTIVITIES
Net cash used in investing activities in 2003 was $79.0 million,
including $78.1 million invested in oil and gas properties, compared to net cash
used in investing activities of $18.1 million in 2002. In 2002, we invested
$48.6 million in oil and gas properties and realized $30.5 million from the sale
of non-core properties.
Capital expenditures for the year ended December 31, 2003 were $88.8
million, including $78.2 million used for development activities, $9.9 million
used for lease acquisitions, seismic surveys and exploratory drilling and $0.7
million used for other assets. These amounts include costs that were incurred
and accrued as of December 31, 2003 but are not reflected in the net cash used
in investing activities above until payment is made in 2004.
Capital expenditures for the year ended December 31, 2002 were $47.5
million, including $30.3 million used for development activities, $4.8 million
used for the acquisition of proved reserves and $12.4 million used for lease
acquisitions, seismic surveys and exploratory drilling.
Capital expenditures for the year ended December 31, 2001 were $87.2
million, including $42.9 million used for development activities, $26.8 million
used for the acquisition of proved reserves, $15.3 million used for lease
acquisitions, seismic surveys and exploratory drilling and $2.2 million used for
other assets.
FINANCING ACTIVITIES
Net cash provided by financing activities in 2003 was $3.2 million
compared to net cash used in financing activities of $18.8 million in 2002. In
2003, net proceeds from the common stock offering were $52.0 million, proceeds
from borrowings under the bank credit facility were $69.3 million, repayments of
debt were $114.1 million and net payments of deferred financing costs and other
were $4.0 million. In 2002, proceeds from borrowings were $0.5 million,
repayments of debt were $18.5 million and payments for deferred financing costs
and other were $0.7 million.
SHELF REGISTRATION STATEMENT / COMMON STOCK OFFERING
On September 16, 2003, we, along with two of our operating
subsidiaries, KCS Resources, Inc. and Medallion California Properties Company,
filed a $200 million universal shelf registration statement with the Securities
and Exchange Commission. The shelf registration statement covers the issuance of
an unspecified amount of senior unsecured debt securities, senior subordinated
debt securities, common stock, preferred stock, warrants, units or guarantees,
or a combination of those securities. We may, in one or more offerings, offer
and sell common stock, preferred stock, warrants and units. We may also, in one
or more offerings, offer and sell senior unsecured and senior subordinated debt
securities. Under our shelf registration statement, our senior unsecured and
senior subordinated debt securities may be fully and unconditionally guaranteed
by KCS Resources, Inc. and Medallion California Properties Company.
33
On November 26, 2003, in a public offering under our shelf registration
statement, we sold 6.0 million shares of our common stock at $8.00 per share. On
December 11, 2003, the underwriters exercised their over-allotment option and we
sold an additional 0.9 million shares of common stock at $8.00 per share. We
used a portion of the net proceeds of approximately $52.0 million from the
public offering and the exercise of the over-allotment option to repay
borrowings under our bank credit facility and to accelerate our drilling program
in certain core areas, including the Elm Grove, Joaquin and Talihina fields,
where we have accumulated a substantial drilling prospect inventory.
As of December 31, 2003, there were $144.8 million remaining under our
shelf registration statement.
BANK CREDIT FACILITY
On November 18, 2003, we amended and restated our bank credit facility
with a group of commercial bank lenders. The bank credit facility is used for
general corporate purposes, including working capital, and to support our
capital expenditure program. The bank credit facility provides up to $100
million of revolving borrowing capacity and matures on November 20, 2006. The
maturity date will be October 17, 2005 if our 8-7/8% Senior Subordinated Notes
are not fully refinanced or repaid by October 14, 2005. Borrowing capacity under
the bank credit facility is subject to a borrowing base initially set at $100
million and is reviewed at least semi-annually and may be adjusted based on the
lenders' valuation of our oil and natural gas reserves and other factors.
Substantially all of our assets, including the stock of all of our subsidiaries,
are pledged to secure the bank credit facility. Further, each of our
subsidiaries has guaranteed our obligations under the bank credit facility.
Borrowings under the bank credit facility bear interest, at our option,
at an interest rate of LIBOR plus 2.25% to 3.0% or the greater of (1) the
Federal Funds Rate plus 0.5% or (2) the Base Rate, plus 0.5% to 1.25%, depending
on utilization. These rates will decrease by 0.5% after the final deliveries are
made in connection with the Production Payment discussed in Note 2 to our
Consolidated Financial Statements and the lien on the subject property is
released. A commitment fee of 0.5% per year is paid on the unused availability
under the bank credit facility. Financing fees pertaining to the bank credit
facility are being amortized over the life of the facility. Deferred financing
fees of $2.8 million associated with the bank credit facility prior to it being
amended and restated in November 2003 and an early termination fee of $0.5
million paid to a previous lender were charged to interest expense during the
fourth quarter of 2003.
The bank credit facility contains various restrictive covenants,
including minimum levels of liquidity and interest coverage. The bank credit
facility also contains other usual and customary terms and conditions of a
conventional borrowing base facility, including requirements for hedging a
portion of our 2004 oil and natural gas production, prohibitions on a change of
control, prohibitions on the payment of cash dividends, restrictions on certain
other distributions and restricted payments, and limitations on the incurrence
of additional debt and the sale of assets. Financial covenants require us to,
among other things: (1) maintain a ratio of Adjusted EBITDA (earnings before
interest, taxes, depreciation, depletion, amortization, other non-cash charges
and exploration expenses minus amortization of deferred revenue attributable to
Production Payment sold in February 2001) to cash interest payments of at least
2.50 to 1.00; (2) maintain a ratio of consolidated current assets to
consolidated current liabilities (excluding the current portion of indebtedness
for borrowed money and the face amount of letters of credit) of not less than
(1)0.80 to 1.00 until March 31, 2004, (2)0.90 to 1.00 from April 2004 until
September 30, 2004 and (3) 1.00 to 1.00 at all times after September 30, 2004
(any unused portion of the commitment amount of the bank credit facility is
deemed to be a current asset of ours for purposes of this calculation); and (3)
not enter into hedging transactions covering more than 80% of projected
production from our proved developed producing reserves for the period of such
transactions.
The bank credit facility also contains customary events of default,
including any defaults by us in the payment or performance of any other
indebtedness equal to or exceeding $5.0 million.
As of December 31, 2003, $17.0 million was outstanding under the bank
credit facility, the weighted average interest rate was 3.6% and $82.0 million
was available for additional borrowings We were also in compliance with all
covenants under the bank credit facility as of that date.
34
CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our future contractual cash obligations
as of December 31, 2003 (in thousands).
PAYMENTS DUE BY PERIOD
LESS THAN 1-3 3-5 MORE THAN
(In thousands of dollars) TOTAL 1 YEAR YEARS YEARS 5 YEARS
- ---------------------------------------------------------------------------------------
Long-term debt 142,000 - 142,000 - -
Operating leases 2,739 1,561 1,141 37 -
Unconditional
purchase obligations 6,986 3,331 3,655 - -
--------------------------------------------------------
151,725 4,892 146,796 37 -
========================================================
The above table does not include the liability for dismantlement, abandonment
and restoration cost of oil and gas properties. See Note 1 to our Consolidated
Financial Statements for further discussion.
OTHER COMMERCIAL COMMITMENTS
In connection with the Production Payment, we have obligations to
deliver 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006. As of December
31, 2003, we had $2.4 million of surety bonds that remain outstanding until
specific events or projects are completed and any claims that may be made are
settled. As of December 31, 2003, we had outstanding a $1.0 million standby
letter of credit supporting hedge transactions with one counterparty. This
letter of credit was cancelled upon the settlement of the related hedges in the
first quarter of 2004.
OFF-BALANCE SHEET ARRANGEMENTS
We do not utilize and are not currently contemplating using any
off-balance sheet arrangements with unconsolidated entities to enhance liquidity
and capital resource positions or for any other purpose. Any future transactions
involving off-balance sheet arrangements will be scrutinized and disclosed by
our management.
NEW ACCOUNTING PRINCIPLES
Effective January 1, 2003, we adopted SFAS No. 143. SFAS No. 143
requires entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in the
period in which it is incurred. When the liability is initially recorded, the
entity increases the carrying amount of the related long-lived asset. The
liability is accreted to the fair value at the time of settlement over the
useful life of the asset, and the capitalized cost is depreciated over the
useful life of the related asset. Upon adoption of SFAS No. 143, our net
property, plant and equipment was increased by $10.2 million, an additional
asset retirement obligation of $11.1 million (primarily for plugging and
abandonment costs of oil and gas wells) was recorded and a $0.9 million charge,
net of tax against net income (or a $0.02 loss per basic and diluted share) was
reported in the first quarter of 2003 as a cumulative effect of a change in
accounting principle. Subsequent to adoption, the effect of the change in
accounting principle was a $0.4 million additional non-cash charge against
income.
Effective January 1, 2002, we began amortizing the capitalized costs
related to oil and gas properties on the unit-of-production, or UOP, method
using proved oil and natural gas reserves. Previously, we had computed
amortization on the basis of future gross revenue. We determined that the change
to the UOP method was preferable under GAAP as, among other reasons, it provides
a more rational basis for amortization during periods of volatile commodity
prices and also increases consistency with others in the industry. As a result
of this change, we recorded a non-cash cumulative effect charge of $6.2 million,
net of tax, (or $0.17 per basic and diluted common share) in the first quarter
of 2002.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51," or FIN 46. FIN 46 requires a company to consolidate a variable interest
entity, or VIE, if it has a variable interest or combination of variable
interests that is exposed to a majority of the entity's expected losses if they
occur, receives a majority of the entity's expected residual returns if they
occur, or both. In addition, more extensive disclosure requirements apply to the
primary and other significant
35
variable interest owners of the VIE. This interpretation applies immediately to
VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains
an interest after that date. FIN 46 is also generally effective for the first
fiscal year or interim period ending after December 15, 2003, to VIEs in which a
company holds a variable interest that is acquired before February 1, 2003. We
have concluded that we do not have any interest in VIEs and that this
interpretation has no impact on our consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity".
SFAS No. 150 establishes standards on how we classify and measure certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that we classify as liabilities the fair value of all
mandatorily redeemable financial instruments that had previously been recorded
as equity or elsewhere in the consolidated financial statements. This statement
is effective for financial instruments entered into or modified after May 31,
2003, and is otherwise effective for all existing financial instruments
beginning in the third quarter of fiscal 2003. SFAS No. 150 did not impact our
classification of our previously outstanding convertible preferred stock because
the convertible preferred stock was not mandatorily redeemable as defined by
SFAS No. 150.
SFAS No. 141, "Business Combinations," and SFAS No.142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized, but rather are reviewed annually for impairment.
Depending on how the accounting and disclosure literature is applied, oil and
gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds may be classified separately from oil and gas properties,
as intangible assets on our balance sheets. In addition, the disclosures
required by SFAS No. 141 and SFAS No. 142 relative to intangibles would be
included in the notes to financial statements. Historically, we, like most other
oil and gas companies, have included these oil and natural gas mineral rights
held under lease and other contractual arrangements representing the right to
extract such reserves as part of the oil and gas properties, even after SFAS No.
141 and SFAS No. 142 became effective.
Our results of operations and cash flows would not be affected, as
these oil and natural gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves would continue to
be accounted for in accordance with full cost accounting rules.
At December 31, 2003 and December 31, 2002, we had leaseholds of
approximately $14.9 million and $12.7 million, respectively that would be
reclassified from "oil and gas properties" to "intangible leaseholds" on our
consolidated balance sheets if we applied the interpretations. These figures
represent the costs incurred, net of amortization, since June 30, 2001, the
effective date of SFAS No. 141. Amounts prior to June 30, 2001 were not
identified since our accounting procedures were not designed to account for
leaseholds separately. These classifications would require us to make
disclosures set forth under SFAS No. 142 related to these interests.
We will continue to classify our oil and natural gas mineral rights
held under lease and other contractual rights representing the right to extract
such reserves as tangible oil and gas properties until further guidance is
provided.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
All information and statements included in this section, other than
historical information and statements, are "forward-looking statements."
COMMODITY PRICE RISK
Our major market risk exposure is to oil and natural gas prices, which
have historically been volatile. Realized prices are primarily driven by the
prevailing worldwide price for crude oil and regional spot prices for natural
gas production. We have utilized, and may continue to utilize, derivative
contracts, including swaps, futures contracts, options and collars to manage
this price risk. We do not enter into derivative or other financial instruments
for trading or speculative purposes. Effective January 1, 2001, we adopted SFAS
No. 133. While these derivative contracts are structured to reduce our exposure
to decreases in the price associated with the underlying commodity, they also
36
limit the benefit we might otherwise receive from price increases. We maintain a
system of controls that includes a policy covering authorization, reporting, and
monitoring of derivative activity.
As of December 31, 2002, we had no outstanding derivative financial
instruments.
As of December 31, 2003, we had derivative instruments outstanding
covering 8.8 MMBtu of 2004 natural gas production and 0.1 million barrels of
2004 oil production, with a fair market value of $0.7 million. The following
table sets forth information with respect to our oil and natural gas hedged
position as of December 31, 2003.
Expected Maturity, 2004
----------------------------------------------------------- Fair Value at
1st 2nd 3rd 4th December 31,
Quarter Quarter Quarter Quarter Total 2003
------- ------- ------- --------- ----- --------------
(In thousands)
Swaps:
Oil
Volumes (bbl)...................... 83,250 45,500 9,200 9,200 147,150 $ (201)
Weighted average price ($/bbl)..... $ 30.59 $ 29.64 $ 28.50 $ 28.50 $ 30.03
Natural Gas
Volumes (MMbtu).................... 2,420,000 910,000 920,000 -- 4,250,000 $ 1,067
Weighted average price ($/MMbtu)... $ 6.71 $ 5.00 $ 4.93 -- $ 5.96
Collars:
Natural Gas
Volumes (MMbtu).................... -- 910,000 920,000 1,840,000 3,670,000 $ (208)
Weighted average price ($/MMbtu)
Floor.......................... $ - $ 4.00 $ 4.34 $ 4.00 $ 4.09
Cap............................ $ - $ 6.81 $ 6.00 $ 7.52 $ 6.96
3-way collars:
Natural Gas
Volumes (MMbtu).................... 910,000 -- -- -- 910,000 $ 31
Weighted average price ($/MMbtu)...
Floor (purchased put option).. $ 4.50 $ -- $ -- $ -- $ 4.50
Cap 1 (sold call option)...... $ 8.50 $ -- $ -- $ -- $ 8.50
Cap 2 (purchased call option). $ 9.00 $ -- $ -- $ -- $ 9.00
The fair value of our derivative instruments was $0.7 million as of
December 31, 2003 as compared to none as of December 31, 2002.
In addition to the information set forth in the table above, we will
deliver 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.2 Bcfe in 2006 under the
Production Payment sold in February 2001 and amortize deferred revenue at a
weighted average price of $4.05 per Mcfe.
During 2003, we delivered approximately 20% of our production under the
Production Payment and amortized deferred revenue at the weighted average
realized price of $4.05 per Mcfe and also entered into derivative arrangements
designed to reduce price downside risk for approximately 20% of the balance of
our production. During 2002, we delivered approximately 30% of our production
under the Production Payment sold in February 2001 at a weighted average
discounted price of $4.05 per Mcfe and also entered into derivative contracts
that covered approximately 17% of the balance of our production.
Commodity Price Swaps. Commodity price swap agreements require us to
make or receive payments from the counter parties based upon the differential
between a specified fixed price and a price related to those quoted on the New
York Mercantile Exchange for the period involved.
Futures Contracts: Oil or natural gas futures contracts require us to
sell and the counter party to buy oil or natural gas at a future time at a
fixed price.
Option Contracts. Option contracts provide the right, not the
obligation, to buy or sell a commodity at a fixed price. By buying a "put"
option, we are able to set a floor price for a specified quantity of our oil or
natural gas production. By selling a "call" option, we receive an upfront
premium from selling the right for a counter party to buy a specified quantity
of oil or natural gas production at a fixed price.
Price Collars. Selling a call option and buying a put option creates a
"collar" whereby we establish a floor and ceiling price for a specified
quantity of future production. Buying a call option with a strike price above
the sold call strike establishes a "3-way collar" that entitles us to capture
the benefit of price increases above that call price.
37
INTEREST RATE RISK
We use fixed and variable rate long-term debt to finance our capital
spending program and for general corporate purposes. The variable rate debt
instruments expose us to market risk related to changes in interest rates. Our
fixed rate debt and the associated weighted average interest rate was $125.0
million at 8.9% as of December 31, 2003 and $186.3 million at 9.6% as of
December 31, 2002. Our variable rate debt and weighted average interest rate was
$17.0 million at 3.6% as of December 31, 2003 and $0.5 million at 5.3% as of
December 31, 2002.
The tables below present principal cash flows and related average
interest rates by expected maturity date for our debt obligations as of December
31, 2003 and 2002 (dollars in millions).
AS OF DECEMBER 31, 2003
------------------------------------------------------------
EXPECTED MATURITY DATE
------------------------------------------
2004 2005 2006 TOTAL FAIR VALUE
---- ------- ------ ------ -------
Long-term debt
Fixed rate ......................... - - $125.0 $125.0 $ 130.0
Average interest rate .............. - - 8.875%
Variable rate ...................... - - $ 17.0 $ 17.0 $ 17.0
Average interest rate .............. - - 3.605%
AS OF DECEMBER 31, 2002
-----------------------------------------------------------------------
EXPECTED MATURITY DATE
------------------------------------------ -------
2003 2004 2005 2006 TOTAL FAIR VALUE
------ ---- ------- ------- ------- -------
Long-term debt
Fixed rate .............. $ 61.3 - - $ 125.0 $ 186.3 $ 155.7
Average interest rate ... 11.00% - - 8.875%
Variable rate ........... $ 0.5 - - - $ 0.5 $ 0.5
Average interest rate ... 5.250% - - -
38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholders of KCS Energy, Inc.:
We have audited the accompanying consolidated balance sheets of KCS Energy, Inc.
and subsidiaries as of December 31, 2003 and 2002 and the related consolidated
statements of operations, stockholders' equity (deficit), and cash flows for
each of the two years in the period ended December 31, 2003. These consolidated
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. The consolidated financial statements of KCS Energy, Inc. and
subsidiaries as of December 31, 2001, and for the year then ended, were audited
by other auditors who have ceased operations. Those auditors expressed an
unqualified opinion on those financial statements in their report dated March
13, 2002. Their report, however, had an explanatory paragraph indicating that
the Company changed its method of accounting for derivative instruments and
hedging activities, effective January 1, 2001, to conform with Statement of
Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging Activities."
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 KCS Energy, Inc.
and subsidiaries as of December 31, 2003 and 2002 and the consolidated results
of their operations and their cash flows for each of the two years ended
December 31, 2003 in conformity with accounting principles generally accepted in
the United States.
As discussed above, the consolidated financial statements of KCS Energy, Inc.
and subsidiaries as of December 31, 2001, and for the year then ended, were
audited by other auditors who have ceased operations. As described in Note 1,
effective January 1, 2002, the Company changed its method of accounting for the
amortization of its oil and gas properties. In addition, as described in Note 1,
effective January 1, 2003, the Company changed its method of accounting for
asset retirement obligations in accordance with Statement of Financial
Accounting Standards No. 143 (SFAS No. 143). These financial statements have
been revised to disclose the pro forma effect on income available to common
stockholders and earnings per share as if the Company had applied the new
amortization method to its oil and gas properties and as if the Company had
adopted SFAS No. 143 on January 1, 2001. Our audit procedures with respect to
these adjustments in Note 1 for 2001 included (a) agreeing the previously
reported income available to common stockholders and basic and diluted earnings
per share to the previously issued financial statements, (b) agreeing the
adjustments to reported income available to common stockholders, representing
changes in the amortization method and changes mandated by SFAS No. 143, to the
Company's underlying records obtained from management, and (c) testing the
mathematical accuracy of the reconciliation of adjusted income available to
common stockholders and the related per-share amounts. With respect to the
disclosure of the pro forma liability for asset retirement obligations as of
January 1, 2001, included in Note 1, our audit procedures included reviewing the
calculation and assumptions used in determining this amount. In our opinion,
such adjustments are appropriate and have been properly applied. However, we
were not engaged to audit, review, or apply any procedures to the 2001
consolidated financial statements of KCS Energy, Inc. and subsidiaries other
than with respect to such adjustments and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 consolidated financial
statements taken as a whole.
/S/ ERNST & YOUNG LLP
Houston, Texas
March 11, 2004
39
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To KCS Energy, Inc.:
We have audited the accompanying consolidated balance sheets of KCS Energy, Inc.
(a Delaware Corporation) and subsidiaries as of December 31, 2001 and 2000, and
the related statements of consolidated operations, stockholders' (deficit)
equity and cash flows for each of the three years in the period ended December
31, 2001. 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 auditing standards generally accepted
in the United States. 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of KCS Energy, Inc. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States.
As explained in Note 10 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities to conform with Statement of Financial
Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
/S/ ARTHUR ANDERSEN LLP
Houston, Texas
March 13, 2002
THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP, THE COMPANY'S FORMER INDEPENDENT PUBLIC ACCOUNTANTS, IN CONNECTION
WITH THE COMPANY'S FORM 10-K FILED APRIL 1, 2002, AND HAS NOT BEEN REISSUED BY
ARTHUR ANDERSEN SINCE THAT DATE. PLEASE READ EXHIBIT 23.2 FOR FURTHER
INFORMATION. THE COMPANY IS INCLUDING THIS COPY OF THE ARTHUR ANDERSEN LLP AUDIT
REPORT PURSUANT TO RULE 2-02(e) OF REGULATION S-X UNDER THE SECURITIES ACT OF
1933, AS AMENDED.
40
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
(Amounts in thousands, except per share data)
For the Year Ended December 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Oil and natural gas revenue $ 159,826 $ 120,002 $ 174,434
Other, net 5,001 (1,183) 17,557
--------- --------- ---------
Total revenue and other 164,827 118,819 191,991
--------- --------- ---------
Operating costs and expenses
Lease operating expenses 26,461 25,246 30,456
Production taxes 8,145 5,589 8,195
General and administrative expenses 8,011 8,255 8,885
Stock compensation 2,715 782 1,419
Bad debt expense 339 215 4,074
Asset retirement obligation accretion 1,116 -- --
Depreciation, depletion and amortization 47,885 49,251 58,314
--------- --------- ---------
Total operating costs and expenses 94,672 89,338 111,343
--------- --------- ---------
Operating income 70,155 29,481 80,648
Interest and other income 112 279 1,319
Interest expense (20,970) (19,945) (21,799)
--------- --------- ---------
Income before reorganization items and income taxes 49,297 9,815 60,168
Reorganization items
Financial restructuring costs -- -- (3,175)
Interest income -- -- 227
--------- --------- ---------
Reorganization items, net -- -- (2,948)
--------- --------- ---------
Income before income taxes and
cumulative effect of accounting change 49,297 9,815 57,220
Federal and state income tax expense (benefit) (20,229) 13,763 (8,359)
--------- --------- ---------
Net income (loss) before cumulative effect of
of accounting change 69,526 (3,948) 65,579
Cumulative effect of accounting change, net of tax (934) (6,166) --
--------- --------- ---------
Net income (loss) 68,592 (10,114) 65,579
Dividends and accretion of issuance costs
on preferred stock (909) (1,028) (1,761)
--------- --------- ---------
Income (loss) available to common stockholders $ 67,683 $ (11,142) $ 63,818
========= ========= =========
Earnings (loss) per share of common stock - basic
Before cumulative effect of accounting change $ 1.73 $ (0.14) $ 2.02
Cumulative effect of accounting change (0.02) (0.17) --
--------- --------- ---------
Earnings (loss) per share of common stock - basic $ 1.71 $ (0.31) $ 2.02
========= ========= =========
Earnings (loss) per share of common stock- diluted
Before cumulative effect of accounting change $ 1.63 $ (0.14) $ 1.69
Cumulative effect of accounting change (0.02) (0.17) --
--------- --------- ---------
Earnings (loss) per share of common stock - diluted $ 1.61 $ (0.31) $ 1.69
========= ========= =========
Average shares outstanding for computation
of earnings (loss) per share
Basic 39,579 35,834 31,668
========= ========= =========
Diluted 42,659 35,834 38,828
========= ========= =========
The accompanying notes are an integral part of these financial statements.
41
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share and per share data)
December 31,
----------------------
2003 2002
--------- ---------
ASSETS
Current assets
Cash and cash equivalents $ 2,178 $ 6,935
Trade accounts receivable, less allowance for doubtful 23,911 16,863
accounts of $4,896 in 2003 and $4,678 in 2002
Prepaid drilling 1,014 1,362
Other current assets 3,706 2,034
--------- ---------
Current assets 30,809 27,194
--------- ---------
Property, plant and equipment
Oil and gas properties, full cost method, less
accumulated DD&A - 2003 $933,572; 2002 $891,124 283,791 231,579
Other property, plant and equipment, at cost less
accumulated depreciation - 2003 $11,598; 2002 $10,415 8,214 8,715
--------- ---------
Property, plant and equipment, net 292,005 240,294
--------- ---------
Deferred charges and other assets 1,334 645
--------- ---------
Deferred taxes 18,818 --
--------- ---------
$ 342,966 $ 268,133
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities
Accounts payable $ 27,834 $ 23,854
Accrued interest 5,100 8,174
Accrued drilling cost 9,596 2,861
Other accrued liabilities 9,071 8,784
--------- ---------
Current liabilities 51,601 43,673
--------- ---------
Deferred credits and other liabilities
Deferred revenue 38,696 66,582
Asset retirement obligation 11,918 --
Other 720 961
--------- ---------
Deferred credits and other liabilities 51,334 67,543
--------- ---------
Long-term debt
Senior notes -- 61,274
Senior subordinated notes 125,000 125,000
Bank credit facility 17,000 500
--------- ---------
Long-term debt 142,000 186,774
--------- ---------
Commitments and contingencies
Preferred stock, authorized 5,000,000 shares,
issued 30,000 shares redeemable convertible preferred stock, par value $.01
per share liquidation preference $1,000 per share - 13,288 shares
outstanding in 2002
-- 12,859
--------- ---------
Stockholders' equity (deficit)
Common stock, par value $0.01 per share, authorized
75,000,000 shares; issued 50,532,373 and 38,611,816, respectively 505 386
Additional paid-in capital 236,204 167,335
Accumulated deficit (128,632) (196,315)
Unearned compensation (725) (880)
Accumulated other comprehensive income (4,580) (8,501)
Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741)
--------- ---------
Stockholders' equity (deficit) 98,031 (42,716)
--------- ---------
$ 342,966 $ 268,133
========= =========
The accompanying notes are an integral part of these financial statements.
42
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (DEFICIT)
(Dollars in thousands)
Additional
Common Paid-in Accumulated Unearned
Stock Capital Deficit Compensation
--------- -------------------------------------
Balance at December 31, 2000 $ 314 $ 145,098 $(248,991) $ --
Comprehensive income
Net Income -- -- 65,579 --
Commodity hedges, net of tax -- -- -- --
Comprehensive income
Conversion of redeemable preferred stock 46 13,724 -- --
Stock issuances - option and benefit plans 6 2,906 -- (2,711)
Stock compensation expense -- -- -- 1,419
Dividends and accretion of issuance
costs on preferred stock 2 812 (1,761) --
--------- --------- --------- ---------
Balance at December 31, 2001 $ 368 $ 162,540 $(185,173) $ (1,292)
Comprehensive income
Net loss -- -- (10,114) --
Commodity hedges, net of tax -- -- -- --
Comprehensive income
Conversion of redeemable preferred stock 10 2,932 -- --
Stock issuances - benefit plans and
awards of restricted stock 4 1,049 -- (370)
Stock compensation expense -- -- -- 782
Dividends and accretion of issuance
costs on preferred stock 4 814 (1,028) --
--------- --------- --------- ---------
Balance at December 31, 2002 $ 386 $ 167,335 $(196,315) $ (880)
Comprehensive income
Net income -- -- 68,592 --
Commodity hedges, net of tax -- -- -- --
Comprehensive income
Stock issuances - common stock offering 69 51,926
Conversion of redeemable preferred stock 44 13,244 -- --
Stock issuances - benefit plans and
awards of restricted stock 5 1,629 -- (655)
Stock compensation expense -- 1,905 -- 810
Dividends and accretion of issuance
costs on preferred stock 1 165 (909) --
--------- --------- --------- ---------
Balance at December 31, 2003 $ 505 $ 236,204 $(128,632) $ (725)
========= ========= ========= =========
Accumulated
Other
Comprehensive Treasury Comprehensive (Deficit)
Income Stock Income Equity
---------------------------------------------------------
Balance at December 31, 2000 $ -- $ (4,741) $ (108,320)
Comprehensive income
Net Income -- -- $ 65,579 65,579
Commodity hedges, net of tax (11,162) -- (11,162) (11,162)
---------
Comprehensive income $ 54,417
=========
Conversion of redeemable preferred stock -- -- 13,770
Stock issuances - option and benefit plans -- -- 201
Stock compensation expense -- -- 1,419
Dividends and accretion of issuance
costs on preferred stock -- -- (947)
--------- --------- -----------
Balance at December 31, 2001 $ (11,162) $ (4,741) $ (39,460)
Comprehensive income
Net loss -- -- $ (10,114) (10,114)
Commodity hedges, net of tax 2,661 -- 2,661 2,661
---------
Comprehensive income $ (7,453)
=========
Conversion of redeemable preferred stock -- -- 2,942
Stock issuances - benefit plans and
awards of restricted stock -- -- 683
Stock compensation expense -- -- 782
Dividends and accretion of issuance
costs on preferred stock -- -- (210)
--------- --------- -----------
Balance at December 31, 2002 $ (8,501) $ (4,741) $ (42,716)
Comprehensive income
Net income -- -- $ 68,592 68,592
Commodity hedges, net of tax 3,921 -- 3,921 3,921
---------
Comprehensive income $ 72,513
=========
Stock isuances - common stock offering 51,995
Conversion of redeemable preferred stock -- -- 13,288
Stock issuances - benefit plans and
awards of restricted stock -- -- 979
Stock compensation expense -- -- 2,715
Dividends and accretion of issuance
costs on preferred stock -- -- (743)
--------- --------- -----------
Balance at December 31, 2003 $ (4,580) $ (4,741) $ 98,031
========= ========= ===========
The accompanying notes are an integral part of these financial statements.
43
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
For the Year Ended December 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Cash flows from operating activities:
Net income (loss) $ 68,592 $ (10,114) $ 65,579
Non-cash charges (credits):
Depreciation, depletion and amortization 47,885 49,251 58,314
Amortization of deferred revenue (27,886) (45,182) (63,089)
Deferred tax expense (benefit) (20,929) 13,763 (8,359)
Cumulative effect of accounting change, net of tax 934 6,166 --
Asset retirement obligation accretion 1,116 -- --
Non-cash losses on derivative instruments, net 5,512 5,041 8,085
Bad debt expense 339 215 4,074
Stock compensation 2,715 782 1,419
Other non-cash charges and credits, net 3,703 1,650 (233)
Reorganization items -- -- 2,948
Net changes in assets and liabilities:
Proceeds from Production Payment, net -- -- 174,969
Realized losses on derivative instruments terminated
in connection with Plan of reorganization -- -- (27,995)
Trade accounts receivable (7,387) 3,264 21,872
Other current assets (1,672) 562 (1,021)
Accounts payable and accrued liabilities 1,756 (4,122) (1,042)
Accrued interest (3,074) (915) (49,109)
Other, net (582) 464 (45)
--------- --------- ---------
Net cash provided by operating activities
before reorganization items 71,022 20,825 186,367
Reorganization items (excluding non-cash
write-off of deferred debt issuance costs) -- -- (2,948)
--------- --------- ---------
Net cash provided by operating activities 71,022 20,825 183,419
--------- --------- ---------
Cash flows from investing activities:
Investment in oil and gas properties (78,126) (48,596) (85,033)
Proceeds from the sale of oil and gas properties (153) 30,474 5,100
Investment in other property, plant and equipment (682) 56 (2,159)
--------- --------- ---------
Net cash used in investing activities (78,961) (18,066) (82,092)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings 69,295 500 --
Repayments of debt (114,069) (18,526) (146,905)
Issuance of redeemable convertible preferred stock -- -- 28,412
Proceeds from common stock offering 51,995 -- --
Deferred financing costs and other, net (4,039) (725) 99
--------- --------- ---------
Net cash proved by (used in) financing activities 3,182 (18,751) (118,394)
--------- --------- ---------
Increase (decrease) in cash and cash equivalents (4,757) (15,992) (17,067)
Cash and cash equivalents at beginning of year 6,935 22,927 39,994
--------- --------- ---------
Cash and cash equivalents at end of year $ 2,178 $ 6,935 $ 22,927
========= ========= =========
The accompanying notes are an integral part of these financial statements.
44
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
KCS Energy, Inc. is an independent oil and gas company engaged in the
acquisition, exploration, development and production of natural gas and crude
oil with operations predominately in the Mid-Continent and Gulf Coast regions of
the United States.
Principles of Consolidation
The consolidated financial statements include the accounts of KCS
Energy, Inc. and its wholly-owned subsidiaries ("KCS" or "Company"). The Company
consolidates all investments in which it, either through direct or indirect
ownership, has more than a fifty percent voting interest and /or control. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
Reclassifications
Certain previously reported amounts have been reclassified to conform
to current year presentation.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
The Company considers as cash equivalents all highly liquid investments
with a maturity of three months or less from the date of purchase.
Derivative Instruments
Oil and natural gas prices have historically been volatile. The Company
has entered, and may continue to enter, into derivative contracts to manage the
risk associated with the price fluctuations affecting it by effectively fixing
the price or range of prices of certain sales volumes for certain time periods.
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 133, as amended, establishes accounting and disclosure
standards requiring that all derivative instruments be recorded in the balance
sheet as an asset or liability, measured at fair value. SFAS No. 133, as
amended, further requires that changes in a derivative instrument's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. To qualify as a hedge, these transactions must be formally documented
and designated as a hedge and the changes in their fair value must correlate
with changes in the expected cash flow from anticipated future sales of
production. Changes in the market value of these cash flow hedges are deferred
through other comprehensive income, or OCI, until such time as the hedged
volumes are produced and sold. Hedge effectiveness is measured at least
quarterly based on relative changes in fair value between the derivative
contract and the hedged item over time. Any ineffectiveness is immediately
reported in other revenue in the Statements of Consolidated Operations. If the
likelihood of occurrence of a hedged transaction ceases to be "probable", hedge
accounting will cease on a prospective basis and all future changes in
derivative fair value will be recognized currently in earnings. The net gain or
loss from hedges terminated prior to maturity continues to be deferred until the
hedged production is
45
recognized in income. If it becomes probable that the hedged transaction will
not occur, the derivative gain or loss associated with a terminated derivative
will immediately be reclassified from OCI into earnings. If the contract is not
designated as a hedge, changes in fair value are recorded currently in income.
During each period presented, the contracts that were designated as hedges
qualified for hedge accounting and continue to qualify for hedge accounting in
accordance with SFAS No. 133, as amended.
Fair Value of Financial Instruments
The carrying value of certain financial instruments, including cash,
cash equivalents and revolving credit debt approximates estimated fair value due
to their short-term maturities and variable interest rates. The estimated fair
value of public debt is based upon quoted market values. Derivative financial
instruments are carried at fair value.
Property, Plant and Equipment
The Company follows the full cost method of accounting under which all
costs incurred in acquisition, exploration and development activities are
capitalized in a country-wide cost center. Such costs include lease
acquisitions, geological and geophysical services, drilling, completion,
equipment and certain salaries, and other internal costs directly associated
with acquisition, exploration and development activities. Historically, total
capitalized internal costs in any given year have not been material to the total
oil and gas costs capitalized in that year. Interest costs related to unproved
properties are also capitalized. Salaries, benefits and other internal costs
related to production and general overhead are expensed as incurred. Prior to
January 1, 2002, the Company utilized the future gross revenue method for
providing depreciation, depletion and amortization. Effective January 1, 2002,
the Company began providing for depreciation, depletion and amortization of
evaluated costs using the unit-of-production method based on proved reserves,
including reserves associated with the Production Payment. Prior to 2003, future
development costs and asset retirement obligations were added to the amortizable
base. Beginning in 2003, KCS changed its accounting for dismantlement,
restoration and abandonment costs. Please read "New Accounting Principles."
Costs directly associated with the acquisition and evaluation of unproved
properties are excluded from the depreciation, depletion and amortization
calculation until a complete evaluation is made and it is determined whether
proved reserves can be assigned to the properties or if impairment has occurred.
The costs of drilling exploratory dry holes are included in the amortization
base immediately upon determination that such wells are dry. Geological and
geophysical costs not associated with specific unevaluated properties are
included in the amortization base as incurred. Costs of unevaluated properties
excluded from amortization were $6.8 million and $3.4 million as of December 31,
2003 and 2002, respectively. The Company will begin to amortize these costs when
proved reserves are established or impairment (assessed quarterly) is
determined.
The Company performs quarterly "ceiling test" calculations as
capitalized costs of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred taxes, are limited to the sum of
the present value of estimated future net revenues from proved oil and natural
gas reserves at current prices discounted at 10%, plus the lower of cost or fair
value of unproved properties, net of related tax effects. To the extent that the
capitalized costs exceed this "ceiling" limitation at the end of any quarter,
the excess is expensed. Beginning in 2003, the Company had to determine how to
incorporate the asset retirement obligations into the quarterly full-cost
ceiling test calculations. SFAS No. 143 is silent with respect to this issue and
although there are various views, the Company elected to continue to include the
capitalized cost of its asset retirement obligations in the oil and gas property
balance and exclude the cash outflow associated with future abandonment cost
from future development cost when calculating the pre-tax present value of
future net revenues. This results in both a higher ceiling test threshold and a
higher net oil and gas property balance. Another widely contemplated view is to
include the undiscounted asset retirement obligation as part of future
development cost, essentially reducing the pre-tax present value of future net
revenues and to net the asset retirement obligation recorded on the balance
sheet against the oil and gas property balance. The Company believes that its
approach is more conservative although at the present time there is no material
difference in the ceiling test calculation using either of these methods.
Proceeds from dispositions of oil and gas properties are credited to
the cost center with no recognition of gains or losses unless a significant
portion (generally more than 25%) of the Company's proved reserves are sold.
46
Depreciation of other property, plant and equipment is provided on a
straight-line basis over the estimated useful lives of the assets ranging from 3
to 20 years. Repairs of all property, plant and equipment and replacements and
renewals of minor items of property are charged to expense as incurred.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to
a purchaser at fixed or determinable prices, when delivery has occurred and
title has transferred and collectibility of the revenue is probable. The Company
follows the sales method of accounting for natural gas revenues. Under this
method of accounting, revenues are recognized based on volume sold. The volume
of natural gas sold may differ from the volume to which the Company is entitled
based on its working interest. An imbalance is recognized as a liability only
when the estimated remaining reserves will not be sufficient to enable the
under-produced owner(s) to recoup its entitled share through future production.
The Company has a liability of $0.7 million for imbalances as of December 31,
2003 and 2002. Under the sales method, no receivables are recorded where the
Company has taken less than its share of production. Natural gas imbalances are
reflected as adjustments to proved natural gas reserves and future cash flows in
the unaudited supplemental oil and gas disclosures. Cash received relating to
future revenue is deferred and recognized when all revenue recognition criteria
have been met.
Pursuant to the Production Payment discussed in Note 2, the Company
recorded the net proceeds from the sale of the Production Payment of
approximately $175.0 million as deferred revenue on the balance sheet. In
accordance with SFAS No. 19 "Financial Accounting and Reporting by Oil and Gas
Producing Companies," deliveries under this Production Payment are recorded as
non-cash oil and natural gas revenue with a corresponding reduction of deferred
revenue at the average price per Mcf of natural gas and per barrel of oil
received when the Production Payment was sold. The Company also reflects the
production volumes and depletion expense as deliveries are made. However, the
associated oil and natural gas reserves are excluded from the Company's reserve
data. During 2003, the Company delivered 6.8 Bcfe under this Production Payment
and recorded $27.9 million of oil and natural gas revenue. Since the sale of the
Production Payment in February 2001 through December 31, 2003, the Company has
delivered 33.7 Bcfe, or 78% of the total quantity to be delivered. For 2004,
scheduled deliveries under the Production Payment are 5.2 Bcfe.
Stock Compensation
The cost of awards of restricted stock, determined as the market value
of the shares as of the date of grant, is expensed ratably over the restricted
period. Stock options issued under the 2001 Stock Plan within six months of the
cancellation of options in connection with our plan of reorganization are
subject to variable accounting in accordance with Financial Accounting Standards
Board Interpretation No. 44, "Accounting for Certain Transaction Involving Stock
Compensation." Under variable accounting for stock options, the amount of
expense recognized during a reporting period is directly related to the movement
in the market price of our common stock during that period. Please read Note 4
for more information on the Company's stock option and incentive plans.
47
As permitted under SFAS No. 123 "Accounting for Stock-Based
Compensation," or SFAS No. 123, as amended, the Company has elected to continue
to account for stock options under the provisions of Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees." Under this method,
the Company does not record any compensation expense for stock options granted
if the exercise price of those options is equal to or greater than the market
price of the Company's common stock on the date of grant, unless the awards are
subsequently modified. The following table illustrates the effect on income
(loss) available to common stockholders and earnings (loss) per share if the
Company had applied the fair value recognition provision of SFAS No. 123, as
amended.
(amounts in thousands except
per share data) 2003 2002 2001
------- -------- --------
Basic earnings (loss) per share
Income (loss) available to common
stockholders as reported $ 67,683 $(11,142) $ 63,818
Add: Stock-based compensation expense
included in reported net income 2,715 782 1,419
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards (1,927) (1,569) 1,316
-------- -------- --------
Pro forma income (loss) available to
common stockholders $ 68,471 $(11,929) $ 66,553
-------- -------- --------
Average shares outstanding 39,579 35,834 31,668
-------- -------- --------
Earnings (loss) per share:
Basic - as reported $ 1.71 $ (0.31) $ 2.02
Basic - pro forma $ 1.73 $ (0.33) $ 2.10
Diluted earnings (loss) per share
Income (loss) available to common
stockholders as reported $ 67,683 $(11,142) $ 63,818
Dividends and accretion of issuance
costs on preferred stock 909 n/a 1,761
-------- -------- --------
Numerator as reported 68,592 (11,142) 65,579
Add: Stock-based compensation expense
included in reported net income 2,715 782 1,419
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards (1,927) (1,569) 1,316
-------- -------- --------
Pro forma numerator $ 69,380 $(11,929) $ 68,314
-------- -------- --------
Average diluted shares outstanding 42,659 35,834 38,828
-------- -------- --------
Earnings (loss) per share:
Diluted - as reported $ 1.61 $ (0.31) $ 1.69
Diluted - pro forma $ 1.63 $ (0.33) $ 1.76
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts receivable
based upon the expected collectibility of all trade receivables. The allowance
is reviewed continually and adjusted for accounts deemed uncollectible. The
allowance was $4.9 million and $4.7 million as of December 31, 2003 and 2002,
respectively. Included in the allowance is $3.7 million that represents a 79%
reserve against receivables from various Enron
48
entities currently in bankruptcy. The Company currently believes that the
remaining $1.0 million receivable from such entities will ultimately be
recovered based on several factors, including the Company's assessment that a
large percentage of its Enron-related receivables should qualify as priority
claims in the bankruptcy process.
The Company extends credit, primarily in the form of monthly oil and
natural gas sales and joint interest owner receivables, to various companies in
the oil and gas industry. These extensions of credit may result in a
concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other conditions and may, accordingly, impact the
Company's overall credit risk. However, the Company believes that the risk
associated with these receivables is mitigated by the size and reputation of the
companies to which the Company extends credit and by dispersion of credit risk
among numerous parties.
Income Taxes
The Company accounts for income taxes in accordance with SFAS No. 109
"Accounting for Income Taxes." Deferred income taxes are recorded to reflect the
future tax consequences of differences between the tax bases of assets and
liabilities and their financial reporting amounts as of the end of each year. A
valuation allowance is recognized as a charge against earnings if, at the time,
it is anticipated that some or all of a deferred tax asset may not be realized.
Earnings (Loss) Per Share
Basic earnings (loss) per share of common stock is computed by dividing
income (loss) available to common stockholders by the weighted average number of
common shares outstanding during the period. Diluted earnings (loss) per share
of common stock reflects the potential dilution that could occur if the
Company's dilutive outstanding stock options and warrants were exercised using
the average common stock price for the period and if the Company's convertible
preferred stock was converted to common stock.
The following table sets forth information related to the computation
of basic and diluted earnings per share:
(amounts in thousands
except per share data) 2003 2002 2001
---- ---- ----
Basic earnings (loss) per share:
Income (loss) available to common stockholders $ 67,683 $(11,142) $ 63,818
-------- -------- --------
Average shares of common stock outstanding 39,579 35,834 31,668
-------- -------- --------
Basic earnings (loss) per share $ 1.71 $ (0.31) $ 2.02
======== ======== ========
Diluted earnings (loss) per share:
Income (loss) available to common stockholders $ 67,683 $(11,142) $ 63,818
Dividends and accretion of issuance costs
on preferred stock 909 n/a 1,761
-------- -------- --------
Diluted earnings (loss) $ 68,592 $(11,142) $ 65,579
-------- -------- --------
Average shares of common stock outstanding 39,579 35,834 31,668
Assumed conversion of convertible
preferred stock 2,832 n/a 6,808
Dividends on convertible preferred stock n/a n/a 232
Stock options and warrants 248 n/a 120
-------- -------- --------
Average diluted shares of common stock outstanding 42,659 35,834 38,828
-------- -------- --------
Diluted earnings (loss) per share $ 1.61 $ (0.31) $ 1.69
======== ======== ========
49
Shares of common stock issuable upon the assumed conversion of the
Company's convertible preferred stock amounting to 4.8 million shares in 2002
were not included in the computation of diluted loss per share nor were accrued
dividends on the Company's convertible preferred stock or stock options and
warrants as they would be anti-dilutive.
Common Stock Outstanding
2003 2002 2001
---------- ---------- ----------
Balance, beginning of the year 36,444,720 34,677,399 29,265,910
Shares issued for:
Option and benefit plan, net of forfeited shares 517,272 413,401 660,657
Sale of common shares 6,900,000 -- --
Conversion of redeemable preferred stock 4,429,317 980,664 4,589,990
Dividends on preferred stock paid in common stock 73,968 373,256 160,842
---------- ---------- ----------
Balance, end of year 48,365,277 36,444,720 34,677,399
========== ========== ==========
Segment Reporting
The Company operates in one reportable segment as an independent oil
and gas company engaged in the acquisition, exploration, development and
production of oil and gas properties. The Company's operations are conducted
entirely in the United States.
New Accounting Principles
Effective January 1, 2003, the Company adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities to
record the fair value of a liability for legal obligations associated with the
retirement obligations of tangible long-lived assets in the periods in which it
is incurred. When the liability is initially recorded, the entity increases the
carrying amount of the related long-lived asset. The liability is accreted to
the fair value at the time of settlement over the useful life of the asset, and
the capitalized cost is depreciated over the useful life of the related asset.
Upon adoption of SFAS No. 143, the Company's net property, plant and equipment
was increased by $10.2 million, an additional asset retirement obligation of
$11.1 million (primarily for plugging and abandonment costs of oil and gas
wells) was recorded and a $0.9 million charge, net of tax against net income (or
a $0.02 loss per basic and diluted share) was reported in the first quarter of
2003 as a cumulative effect of a change in accounting principle. Subsequent to
adoption, the effect of the change in accounting principle was a $0.4 million
additional non-cash charge against income (or a $0.01 loss per share).
The cumulative effect of change in accounting principle did not take
into consideration the potential impacts of adopting SFAS No. 143 on previous
full-cost ceiling tests. Management chose not to recalculate historical
full-cost ceiling tests upon adoption even though historical oil and gas
property balances would have been higher had the Company applied the provisions
of this statement. Management believes this approach is appropriate because SFAS
No. 143 is silent on this issue and was not effective during previous ceiling
test periods. If the Company re-calculated the historical ceiling tests and
included the impact as a component of the cumulative effect of adoption, the
cumulative loss would have potentially been larger. A ceiling test calculation,
however, was performed upon adoption and at the end of each subsequent quarterly
reporting period and no ceiling test impairment (writedown) was encountered.
The following table illustrates the pro forma effects on income
attributable to common stock, earnings per share and asset retirement obligation
if the Company had adopted SFAS No. 143 as of January 1, 2001.
50
2002 2001
---- ----
(Amounts in thousands
except per share data)
Income (loss) attributed to common stock:
As reported $(11,142) $ 63,818
Pro forma (11,659) 62,122
Earnings (loss) per share
Basic - as reported $ (0.31) $ 2.02
Basic - pro forma $ (0.33) $ 1.96
Diluted - as reported $ (0.31) $ 1.69
Diluted - pro forma $ (0.33) $ 1.65
Pro Forma liability for asset retirement obligation:
Beginning of year $ 10,052 $ 8,866
End of year $ 11,142 $ 10,052
The following table summarizes the changes in the Company's total
estimated liability from the amount recorded upon adoption of SFAS No. 143 on
January 1, 2003 through December 31, 2003:
(In thousands)
Asset retirement obligation on January 1, 2003 $ 11,142
Liabilities incurred 376
Accretion expense 1,116
Asset retirement obligation liabilities settled (785)
Revisions in estimated liabilities 69
--------
Asset retirement obligation on December 31, 2003 $ 11,918
========
Effective January 1, 2002, the Company began amortizing the capitalized
costs related to oil and gas properties on the unit-of-production, or UOP,
method using proved oil and natural gas reserves. Previously, the Company had
computed amortization on the basis of future gross revenues, or FGR. The Company
determined that the change to UOP was preferable under accounting principles
generally accepted in the United States, since among other reasons, it provides
a more rational basis for amortization during periods of volatile commodity
prices and also increases consistency with others in the industry. As a result
of this change, the Company recorded a non-cash cumulative effect charge of $6.2
million, net of tax, (or $0.17 per basic and diluted common share) in the first
quarter of 2002. The effect of the change in accounting principle in 2002 was to
decrease the net loss by approximately $3.2 million, or $0.09 per basic and
diluted share. The following table illustrates the effect on income attributable
to common stockholders and earnings per share if the Company had applied UOP to
amortize its oil and gas properties during 2001.
51
(Amounts in thousands except for per share data) 2001
----------------------------------------------- ----------
Income attributed to common stock:
As reported $ 63,818
Pro forma 64,655
Earnings per share
Basic - as reported $ 2.02
Basic - pro forma $ 2.04
Diluted - as reported $ 1.69
Diluted - pro forma $ 1.71
The proforma effect on our 2001 results, had both SFAS No. 143 and UOP
been adopted, would have been a decrease of $0.9 million to $62.9 million in
income attributed to common stock or $0.03 per basic and diluted share.
In January 2003, the Financial Accounting Standards Board, or FASB,
issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51," or FIN 46. FIN 46
requires a company to consolidate a variable interest entity, or VIE, if the
company has a variable interest (or combination of variable interests) that is
exposed to a majority of the entity's expected losses if they occur, receives a
majority of the entity's expected residual returns if they occur, or both. In
addition, more extensive disclosure requirements apply to the primary and other
significant variable interest owners of the VIE. This interpretation applies
immediately to VIEs created after January 31, 2003, and to VIEs in which an
enterprise obtains an interest after that date. It is also generally effective
for the first fiscal year or interim period ending after December 15, 2003, to
VIEs in which a company holds a variable interest that is acquired before
February 1, 2003. The Company has concluded it does not have any interests in
VIEs and that this interpretation has no impact on its consolidated financial
statements.
In May 2003, the FASB issued Statement of Financial Accounting
Standards No. 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity," or SFAS No. 150. SFAS No. 150
establishes standards on how a company classifies and measures certain financial
instruments with characteristics of both liabilities and equity. The statement
requires that the Company classify as liabilities the fair value of all
mandatorily redeemable financial instruments that had previously been recorded
as equity or elsewhere in the consolidated financial statements. This statement
is effective for financial instruments entered into or modified after May 31,
2003, and is otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. SFAS No. 150 did not impact the
Company's classification of its convertible preferred stock because the
convertible preferred stock was not mandatorily redeemable as defined by SFAS
No. 150.
Statement of Financial Accounting Standards No. 141, "Business
Combinations," or SFAS No. 141, and Statement of Financial Accounting Standards
No.142, "Goodwill and Intangible Assets," or SFAS No. 142, were issued by the
FASB in June 2001 and became effective for us on July 1, 2001 and January 1,
2002, respectively. SFAS No. 141 requires all business combinations initiated
after June 30, 2001 to be accounted for using the purchase method. Additionally,
SFAS No. 141 requires companies to disaggregate and report separately from
goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. Depending on how the accounting and disclosure
literature is applied, oil and natural gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
for both undeveloped and developed leaseholds may be classified separately from
oil and gas properties, as intangible assets on our balance sheets. In addition,
the disclosures required by SFAS No. 141 and SFAS No. 142 relative to
intangibles would be included in the notes to financial statements.
Historically, KCS, like most other oil and gas companies, has included these oil
and natural gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves as part of the oil
and gas properties, even after SFAS No. 141 and SFAS No. 142 became effective.
Disaggregating these costs would not affect the Company's results of operations
and cash flows as these oil and natural gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
would continue to be accounted for in accordance with full cost accounting
rules.
52
At December 31, 2003 and December 31, 2002, we had leaseholds of
approximately $14.9 million and $12.7 million, respectively that would be
reclassified from "oil and gas properties" to "intangible leaseholds" on our
consolidated balance sheets if we applied the interpretations. These figures
represent the costs incurred, net of amortization, since June 30, 2001, the
effective date of SFAS No. 141. Amounts prior to June 30, 2001 were not
identified since the Company's accounting systems were not designed to account
for leaseholds separately. These classifications would require us to make
disclosures set forth under SFAS No. 142 related to these interests.
We will continue to classify our oil and natural gas mineral rights
held under lease and other contractual rights representing the right to extract
such reserves as tangible oil and gas properties until further guidance is
provided.
2. REORGANIZATION
On January 30, 2001, the United States Bankruptcy Court for the
District of Delaware confirmed the Company's plan of reorganization, or the
Plan, under Chapter 11 of Title 11 of the United States Bankruptcy Code after
the Company's creditors and stockholders voted to approve the Plan. On February
20, 2001, the Company completed the necessary steps for the Plan to go effective
and emerged from bankruptcy having reduced its debt from a peak of $425.0
million in early 1999 to $215.0 million. The Company also had cash in excess of
$30.0 million.
Under the terms of the Plan, the Company: (1) sold a 43.1 Bcfe (38.3
Bcf of natural gas and 797,000 barrels of oil) production payment, or Production
Payment, to be delivered in accordance with an agreed schedule over a five-year
period for net proceeds of approximately $175.0 million and repaid all amounts
outstanding under its existing bank credit facilities; (2) sold $30.0 million of
convertible preferred stock; (3) paid to the holders of the Company's 11% Senior
Notes, on a pro rata basis, cash equal to the sum of (a) $60.0 million plus the
amount of past due accrued and unpaid interest of $15.1 million on $60.0 million
of the Senior Notes as of the effective date, compounded semi-annually at 11%
per year, and (b) the amount of past due accrued and unpaid interest of $21.5
million on $90.0 million of the Senior Notes as of January 15, 2001, compounded
semi-annually at 11% per year; (4) paid to the holders of the Company's 8-7/8%
Senior Subordinated Notes, cash in the amount of past due accrued and unpaid
interest of $23.7 million as of January 15, 2001, compounded semi-annually at
8-7/8% per year; (5) renewed the remaining outstanding $90.0 million principal
amount of Senior Notes and $125.0 million principal amount of Senior
Subordinated Notes under amended indentures without a change in interest rates;
and (6) paid pre-petition trade creditors in full. Stockholders retained 100% of
their common stock, subject to dilution from conversion of the newly issued
convertible preferred stock.
3. RETIREMENT BENEFIT PLAN
The Company sponsors a Savings and Investment Plan, or Savings Plan,
under Section 401(k) of the Internal Revenue Code. Eligible employees may
contribute a portion of their compensation, as defined under the Savings Plan,
to the Savings Plan, subject to certain Internal Revenue Service limitations.
The Company may make matching contributions, which have been set by the
Company's board of directors at 50% of the employee's contribution (up to 6% of
the employee's compensation, subject to certain regulatory limitations). The
Savings Plan also contains a profit-sharing component whereby the Company's
board of directors may declare annual discretionary profit-sharing
contributions. Profit-sharing contributions are allocated to eligible employees
based upon their pro-rata share of total eligible compensation and may be made
in cash or in shares of the Company's common stock. Contributions to the Savings
Plan are invested at the direction of the employee in one or more funds or can
be directed to purchase common stock of the Company at market value. The
Company's matching contributions and discretionary profit-sharing contributions
vest over a four-year employment period. Once the four-year employment period
has been satisfied, all Company matching contributions and discretionary
profit-sharing contributions immediately vest. Company contributions to the
Savings Plan were $524,419 in 2003, $531,103 in 2002 and $510,702 in 2001.
53
4. STOCK OPTION AND INCENTIVE PLANS
The KCS Energy, Inc. 2001 Employees and Directors Stock Plan, or 2001
Stock Plan, provides that stock options, stock appreciation rights, restricted
stock and bonus stock may be granted to employees of the Company. The 2001 Stock
Plan also provides that annually, each non-employee director receive shares of
the Company's common stock with a fair market value equal to 50% of their annual
retainer in lieu of cash and grants of stock options for 1,000 shares. The 2001
Stock Plan provides that the option price of shares issued be equal to the
market price on the date of grant. Options granted to directors as part of their
annual compensation vest immediately. All other options vest ratably on the
anniversary of the date of grant over a period of time, typically three years.
All options expire 10 years after the date of grant. On February 20, 2001, in
connection with the Plan, the Company's 1992 Stock Plan and the 1994 Directors'
Stock Plan and all outstanding options thereunder were cancelled. Options issued
under the 2001 Stock Plan within six months of this cancellation are subject to
variable accounting in accordance with Financial Accounting Standards Board
Interpretation No. 44, "Accounting for Certain Transaction Involving Stock
Compensation." Under variable accounting for stock options, the amount of
expense recognized during a reporting period is directly related to the movement
in the market price of the Company's common stock during that period. During
2003, the Company recorded $1.9 million as stock compensation in the Statements
of Consolidated Operations related to the options subject to variable
accounting. The Company did not record any stock compensation expense related to
stock options in 2002 or 2001 since the stock options were "out of the money".
Restricted shares awarded under the 2001 Stock Plan have a restriction
period of three years. During the restriction period, ownership of the shares
cannot be transferred and the shares are subject to forfeiture if employment
terminates before the end of the restriction period. Certain restricted stock
awards provide for the restriction period to accelerate to one year if certain
performance criteria are met. Restricted stock is considered to be currently
issued and outstanding and has the same rights as other common stock. The cost
of the awards of restricted stock, determined as the market value of the shares
at the date of grant, is expensed ratably over the restricted period. As of
December 31, 2003, there were 681,404 outstanding shares of restricted stock.
As of December 31, 2003, a total of 1,289,493 shares were available for
future grants under the 2001 Stock Plan.
A summary of the status of the stock options under the 2001 Stock Plan,
the cancelled 1992 Stock Plan and the cancelled 1994 Directors' Stock Plan as of
December 31, 2003, 2002 and 2001 and changes during the years then ended is
presented in the table below. The fair value of each option grant is estimated
on the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used for grants in 2003: (1) risk-free
interest rate of 3.67%; (2) expected dividend yield of 0.00%; (3) expected life
of 10 years; and (4) expected stock price volatility of 88.6%. The weighted
average assumptions used for grants in 2002 were: (1) risk-free interest rate of
5.3%; (2) expected dividend yield of 0.00%; (3) expected life of 10 years; and
(4) expected stock price volatility of 86.7%. The weighted average assumptions
used for grants in 2001 were: (1) risk-free interest rate of 5.4%; (2) expected
dividend yield of 0.00%; (3) expected life of 10 years; and (4) expected stock
price volatility of 85.3%.
54
2003 2002 2001
------------------------- ------------------------ -----------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
---------- -------- --------- -------- --------- --------
Outstanding at beginning of year 1,564,761 $ 4.73 1,229,043 $ 5.49 1,378,430 $ 10.66
Cancelled (a) - - - - (1,225,930) 11.75
Granted 527,500 3.54 501,000 2.75 1,237,259 5.49
Exercised (96,057) 5.17 - - (152,500) 1.86
Forfeited (110,482) 5.02 (165,282) 4.42 (8,216) 5.51
---------- ------ --------- ------ --------- -------
Outstanding at end of year 1,885,722 4.36 1,564,761 4.73 1,229,043 5.49
========== ====== ========= ====== ========= =======
Exercisable at end of year 868,723 $ 5.13 494,522 $ 5.56 6,000 $ 9.61
========== ====== ========= ====== ========= =======
Weighted average fair value of
options granted $ 3.07 $ 2.39 $ 4.52
====== ====== =======
- --------------
(a) Cancelled in connection with the Company's plan of reorganization.
The following table summarizes information about stock options
outstanding as of December 31, 2003.
Options Outstanding Options Exercisable
------------------------------------------------- ------------------------------
Number Weighted Number
Outstanding at Average Weighted Exercisable at Weighted
Range of December 31, Remaining Average December 31, Average
Eercise Prices 2003 Contractual Life Exercise Price 2003 Exercise Price
- -------------- -------------- ---------------- -------------- -------------- --------------
$1.71 - $5.20 679,866 8.53 $ 2.42 139,134 $ 2.82
5.21 - 6.00 1,200,856 7.62 5.43 724,589 5.55
6.01 - 9.61 5,000 7.40 9.61 5,000 9.61
- ------------- --------- ---- --------- ------- ------
$2.75 - $9.61 1,885,722 7.94 $ 4.36 868,723 $ 5.13
============= ========= ==== ========= ======= ======
The Company has an employee stock purchase program, or Program. Under
the Program, all eligible employees and directors may purchase full shares from
the Company at a price per share equal to 90% of the market value determined by
the closing price on the date of purchase. The minimum purchase is 25 shares.
The maximum annual purchase is the number of shares costing no more than 10% of
the eligible employee's annual base salary. The maximum annual purchase for
directors is 6,000 shares. The number of shares issued in connection with the
Program was 19,394 shares, 8,209 shares and 9,160 shares during 2003, 2002 and
2001, respectively. As of December 31, 2003, there were 756,595 shares available
for issuance under the Program.
55
5. DEBT
The following table sets forth information regarding the Company's
outstanding debt.
(Amounts in thousands) 2003 2002
- -------------------------------- -------- --------
Bank Credit Facility $ 17,000 $ 500
11% Senior Notes -- 61,274
8 7/8% Senior Subordinated Notes 125,000 125,000
-------- --------
142,000 186,774
Classified as short-term debt -- --
-------- --------
Long-term debt $142,000 $186,774
======== ========
BANK CREDIT FACILITY
On November 18, 2003, the Company amended and restated its bank credit
facility with a group of commercial bank lenders. The bank credit facility,
which is used for general corporate purposes, including working capital, and to
support the Company's capital expenditure program, provides up to $100 million
of revolving borrowing capacity and matures on November 20, 2006, provided that
the maturity date will be October 17, 2005 if the Company's 8-7/8% Senior
Subordinated Notes are not fully refinanced or repaid by October 14, 2005.
Borrowing capacity under the bank credit facility is subject to a borrowing
base, initially set at $100 million, which is reviewed at least semi-annually
and may be adjusted based on the lenders' valuation of the Company's oil and
natural gas reserves and other factors. Substantially all of the Company's
assets, including the stock of all of the Company's subsidiaries, are pledged to
secure the bank credit facility, and each of the Company's subsidiaries have
guaranteed the Company's obligations under the bank credit facility.
Borrowings under the bank credit facility bear interest, at the
Company's option, at an interest rate of LIBOR plus 2.25% to 3.0% or the greater
of (1) the Federal Funds Rate plus 0.5% or (2) the Base Rate, plus 0.5% to
1.25%, depending on utilization. These rates will decrease by 0.5% after the
final deliveries are made in connection with the Production Payment discussed in
Note 2 to our Consolidated Financial Statements and the lien on the subject
properties is released. A commitment fee of 0.5% per year is paid on the unused
availability under the bank credit facility. Financing fees pertaining to the
bank credit facility as amended in November 2003 are being amortized over the
life of the agreement. Deferred financing fees of $2.8 million associated with
the facility prior to it being amended and restated in November 2003 and an
early termination fee of $0.5 million paid to a previous lender were charged to
interest expense during the fourth quarter of 2003.
The bank credit facility contains various restrictive covenants,
including minimum levels of liquidity and interest coverage. The bank credit
facility also contains other usual and customary terms and conditions of a
conventional borrowing base facility, including requirements for hedging a
portion of the Company's 2004 oil and natural gas production, prohibitions on a
change of control, prohibitions on the payment of cash dividends, restrictions
on certain other distributions and restricted payments, and limitations on the
incurrence of additional debt and the sale of assets. Financial covenants
require us to, among other things: (1) maintain a ratio of Adjusted EBITDA
(earnings before interest, taxes, depreciation, depletion, amortization, other
non-cash charges and exploration expenses minus amortization of deferred revenue
attributable to Production Payment sold in February 2001) to cash interest
payments of at least 2.50 to 1.00; (2) maintain a ratio of consolidated current
assets to consolidated current liabilities (excluding the current portion of
indebtedness for borrowed money and the face amount of letters of credit) of not
less than (1)0.80 to 1.00 until March 31, 2004, (2)0.90 to 1.00 from April 2004
until September 30, 2004 and (3) 1.00 to 1.00 at all times after September 30,
2004 (any unused portion of the commitment amount of the bank credit facility is
deemed to be a current asset of KCS for purposes of this calculation); and (3)
not enter into hedging transactions covering more than 80% of projected
production from our proved developed producing reserves for the period of such
transactions.
The bank credit facility also contains customary events of default,
including any defaults by the Company in payment or performance of any other
indebtedness equal to or exceeding $5.0 million.
As of December 31, 2003, $17.0 million was outstanding under the bank
credit facility, the weighted average interest rate was 3.6% and $82.0 million
was available for additional borrowings. We were also in compliance with all
covenants under the bank credit facility as of that date.
On January 14, 2003, the Company amended and restated its bank credit
facility with a group of institutional lenders which provided up to $90 million
of borrowing capacity. Initial proceeds of $69.3 million were used primarily to
pay off the Company's maturing Senior Note obligations. This facility was
subsequently amended on November 18, 2003 as discussed above.
Senior Notes
On January 25, 1996, the Company issued $150.0 million principal amount
of 11% Senior Notes due 2003, or the Senior Notes. The Company redeemed $70.2
million of the Senior Notes during 2001, $18.5 million during
56
2002 and redeemed the remaining $61.3 million upon maturity on January 15, 2003.
The balance as of December 31, 2002 was classified as long-term because of the
Company's intent and ability to refinance the outstanding amounts on a long-term
basis through the credit facility amended on January 14, 2003.
Senior Subordinated Notes
On January 15, 1998, the Company completed a public offering of $125.0
million of Senior Subordinated Notes at an interest rate of 8-7/8%. The Senior
Subordinated Notes were non-callable for five years and are unsecured
subordinated obligations of the Company. As of January 15, 2004, the Senior
Subordinated Notes were callable at 102.96% of the par value and are callable at
101.48% of the par value on January 15, 2005. The Company's subsidiaries have
guaranteed the Senior Subordinated Notes on an unsecured subordinated basis. The
guarantees by the subsidiaries are full and unconditional and joint and several.
On February 20, 2001, in connection with the Plan, the indenture
governing the Senior Subordinated Notes was amended to, among other things,
accelerate the maturity date of the Senior Subordinated Notes from January 15,
2008 to January 15, 2006.
The Senior Subordinated Notes, as amended, contain certain restrictive
covenants which, among other things, limit the Company's ability to incur
additional indebtedness, [require the repurchase] of the Senior Subordinated
Notes upon a change of control and that limit the aggregate cash dividends paid
on capital stock, collectively, to 50% of the Company's cumulative net income,
as defined in the indenture, during the period beginning after December 31,
2000. The Senior Subordinated Notes also contain cross-default provisions that
would result in the acceleration of payments if the Company defaults on its
other debt instruments.
Other Information
The estimated fair value of the Company's Senior Subordinated Notes was
$130.0 million based on quoted market values at December 31, 2003. The estimated
fair value of the Company's Senior Notes and Senior Subordinated Notes at
December 31, 2002 were $61.3 million and $94.4 million, respectively.
The scheduled maturities of the Company's outstanding debt during the
next five years are as follows: (1) $0 in 2004; (2) $0 in 2005; and (3) $142.0
million in 2006.
Total interest payments were $18.6 million in 2003, $19.2 million in
2002 and $71.5 million in 2001. Interest payments in 2001 included approximately
$60.7 million made in connection with the Plan, $60.3 million of which was paid
to holders of the Senior Notes and the Senior Subordinated Notes for interest
accrued but not paid during the reorganization period, including interest on
interest. Capitalized interest was $0.4 million in 2003, $0.7 million in 2002
and $0.6 million in 2001.
6. SHELF REGISTRATION STATEMENT / COMMON STOCK OFFERING
On September 16, 2003, we, along with two of our operating
subsidiaries, KCS Resources, Inc. and Medallion California Properties Company,
filed a $200 million universal shelf registration statement with the Securities
and Exchange Commission. The shelf registration statement covers the issuance of
an unspecified amount of senior unsecured debt securities, senior subordinated
debt securities, common stock, preferred stock, warrants, units or guarantees,
or a combination of those securities. We may, in one or more offerings, offer
and sell common stock, preferred stock, warrants and units. We may also, in one
or more offerings, offer and sell senior unsecured and senior subordinated debt
securities. Under our shelf registration statement, our senior unsecured and
senior subordinated debt securities may be fully and unconditionally guaranteed
by KCS Resources, Inc. and Medallion California Properties Company.
57
On November 26, 2003, in a public offering under our shelf registration
statement, we sold 6.0 million shares of our common stock at $8.00 per share. On
December 11, 2003, the underwriters exercised their over-allotment option and we
sold an additional 0.9 million shares of common stock at $8.00 per share. As of
December 31, 2003, there were $144.8 million remaining under our shelf
registration statement.
7. REDEEMABLE CONVERTIBLE PREFERRED STOCK
On September 15, 2003, the Company issued a redemption notice to
holders of its Series A Convertible Preferred Stock in accordance with the
provisions in the Certificate of Designation, Preferences, Rights and
Limitations of the Preferred Stock, or Certificate of Designation. Under the
Certificate of Designation, the Company had the option to redeem the Preferred
Stock if the closing price of the Company's common stock exceeded $6.00 per
share for 25 out of 30 consecutive trading days. The redemption date was set as
October 15, 2003. Prior to the redemption date, holders of 100% of the
outstanding Preferred Stock exercised their conversion rights.
Background. In connection with the Plan, the Company issued 30,000
shares of Series A Convertible Preferred Stock, $0.01 par value, or Preferred
Stock, at a price of $1,000 per share. The Preferred Stock was convertible at
any time into a total of 10,000,000 shares of the Company's common stock at a
conversion price of $3.00 per share. Net proceeds from the issuance of the
Preferred Stock were $28.4 million. The excess of the redemption value of the
Preferred Stock over the original net issuance proceeds is reflected as
accretion of issuance costs on preferred stock in the Statements of Consolidated
Operations. A dividend of 5% per year was paid quarterly in cash or, during the
first two years following issuance, in shares of the Company's common stock
valued at the average of the high and the low trading price for the twenty
trading days prior to the dividend payment date. While outstanding, the
Preferred Stock had no voting rights except upon certain defaults or failure to
pay dividends and as otherwise required by law. The Preferred Stock had a
liquidation preference of $1,000 per share plus accrued and unpaid dividends and
ranked senior to common stock or any subsequent issue of preferred stock.
In connection with the issuance of the Preferred Stock, the Company
also issued warrants to the placement agent to purchase 400,000 shares of the
Company's common stock at $4.00 per share. The warrants expire on February 29,
2006. In January 2004, one half of the warrants were exercised.
As a result of conversions of the Preferred Stock, 4.4 million, 1.0
million and 4.6 million shares of common stock were issued in 2003, 2002 and
2001, respectively. In addition 0.4 million and 0.2 million shares of common
stock were issued as dividends on the preferred stock in 2002 and 2001,
respectively.
8. LEASES AND UNCONDITIONAL PURCHASE OBLIGATIONS
Future minimum lease payments under operating leases having initial or
remaining non-cancelable lease terms in excess of one year are as follows: (1)
$1.6 million in 2004; (2) $0.8 million in 2005; (3) $0.3 million in 2006; and
(4) less than $0.1 million after 2006. Lease payments charged to operating
expenses amounted to $1.7 million, $1.3 million and $0.8 million during 2003,
2002 and 2001, respectively. In addition, the Company has unconditional purchase
obligations, primarily related to natural gas transportation contracts, of $3.3
million in 2004, $3.0 million in 2005 and $0.7 million in 2006.
58
9. INCOME TAXES
Federal and state income tax provision (benefit) includes the following
components:
For the Year Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(Dollars in thousands)
Current provision (benefit) $ 700 $ -- $ --
Deferred provision (benefit), net (20,929) 12,937 (8,359)
-------- -------- --------
Federal income tax provision (benefit) (20,229) 12,937 (8,359)
State income tax provision (deferred provision $0 in
2003, $826 in 2002, deferred benefit $600 in 2001) -- 826 --
-------- -------- --------
$(20,229) $ 13,763 $ (8,359)
======== ======== ========
Reconciliation of federal income tax expense (benefit) at statutory rate to
provision for income taxes:
Income before income taxes $ 49,297 $ 9,815 $ 57,220
-------- -------- --------
Tax provision at 35% statutory rate 17,254 3,435 20,027
Change in valuation allowance (37,560) 9,776 (28,401)
State income taxes, net of federal benefit -- 537 --
Other, net 77 15 15
-------- -------- --------
$(20,229) $ 13,763 $ (8,359)
======== ======== ========
The primary differences giving rise to the Company's net deferred tax
assets are as follows:
December 31,
2003 2002
-------- --------
(Dollars in thousands)
Income tax effects of:
Deferred tax assets
Alternative minimum tax credit carry forwards $ 3,476 $ 2,776
Net operating loss carry forward 60,671 75,377
Statutory depletion carryforward 400 400
Bad debts 1,714 1,637
Deferred revenue 1,633 --
Other 2,924 1,709
-------- --------
Gross deferred tax asset 70,818 81,899
Valuation allowance (37,206) (74,439)
-------- --------
Deferred tax assets 33,612 7,460
-------- --------
Deferred tax liabilities
Property related items (14,794) (5,565)
Deferred revenue -- (1,895)
-------- --------
Deferred tax liabilities (14,794) (7,460)
-------- --------
Net deferred tax asset $ 18,818 $ --
======== ========
Federal alternative minimum tax payments, or AMT, of $0.7 million were
made during 2003. No federal income tax payments were made during 2002 or 2001.
There were no state income tax payments in 2003. State income tax payments were
$0.5 million in 2002 and $0.1 million in 2001.
59
The Company records deferred tax assets and liabilities to account for
temporary differences arising from events that have been recognized in its
financial statements and will result in future taxable or deductible items in
its tax returns. To the extent deferred tax assets exceed deferred tax
liabilities, at least annually and more frequently if events or circumstances
change materially, the Company assesses the realizability of its net deferred
tax assets. A valuation allowance is recognized if, at the time, it is
anticipated that some or all of the net deferred tax assets may not be realized.
In making this assessment, management performs an extensive analysis of
the operations of the Company to determine the sources of future taxable income.
Such an analysis consists of a detailed review of all available data, including
the Company's budget for the ensuing year, forecasts based on current as well as
historical prices, and the independent petroleum engineers' reserve report.
The determination to establish and adjust a valuation allowance
requires significant judgment as the estimates used in preparing budgets,
forecasts and reserve reports are inherently imprecise and subject to
substantial revision as a result of changes in the outlook for prices,
production volumes and costs, among other factors. It is difficult to predict
with precision the timing and amount of taxable income the Company will generate
in the future. Accordingly, while the Company's current net operating loss
carryforwards aggregating approximately $173.3 million have remaining lives
ranging from 9 to 19 years, with the majority having a life in excess of 15
years, management examines a much shorter time horizon, usually two to three
years, when projecting estimates of future taxable income and making the
determination as to whether the valuation allowance should be adjusted.
During the second quarter of 2002, uncertainty resulting from
relatively low commodity prices and the January 2003 maturity date for the
Company's Senior Notes led management to increase the valuation allowance by
$15.9 million. This increase in the valuation allowance reduced the carrying
value of net deferred assets to zero. Since that time, the Company has generated
significant levels of taxable income thereby utilizing a portion of its deferred
tax asset and the future outlook for taxable income has improved significantly.
Oil and natural gas prices have improved significantly and are expected to
remain relatively high for the foreseeable future based on existing available
information, including current prices quoted on the New York Mercantile
Exchange. Therefore, during 2003, the Company reversed $19 million of the
valuation allowance related to expected taxes on future years' taxable income,
which is reflected as an income tax benefit in the condensed statements of
consolidated operations.
As of December 31, 2003, the Company had tax net operating losses, or
NOLs, of approximately $173.3 million available to offset future taxable income,
including approximately $11.9 million that will expire in 2012, $73.8 million
that will expire in 2018, $34.1 million that will expire in 2019, $26.0 million
that will expire in 2020 and $27.5 million that will expire in 2022.
10. DERIVATIVES
Oil and natural gas prices have historically been volatile. The Company
has at times utilized derivative contracts, including swaps, futures contracts,
options and collars, to manage this price risk.
Commodity Price Swaps. Commodity price swap agreements require the
Company to make or receive payments from the counter parties based upon the
differential between a specified fixed price and a price related to those quoted
on the New York Mercantile Exchange for the period involved.
Futures Contracts. Oil or natural gas futures contracts require the
Company to sell and the counter party to buy oil or natural gas at a future time
at a fixed price.
Option Contracts. Option contracts provide the right, not the
obligation, to buy or sell a commodity at a fixed price. By buying a "put"
option, the Company is able to set a floor price for a specified quantity of its
oil or natural gas production. By selling a "call" option, the Company receives
an upfront premium from selling the right for a counter party to buy a specified
quantity of oil or natural gas production at a fixed price.
Price Collars. Selling a call option and buying a put option creates a
"collar" whereby the Company establishes a floor and ceiling price for a
specified quantity of future production. Buying a call option with a strike
60
price above the sold call strike price establishes a "3-way collar" that
entitles the Company to capture the benefit of price increases above that call
price.
Upon adoption of SFAS No. 133, the Company recorded a liability of
$43.8 million representing the fair market value of its derivative instruments
at adoption, a related deferred tax asset of $15.3 million and an after-tax
cumulative effect of a change in accounting principle of $28.5 million to
accumulated other comprehensive income, or OCI. The Company elected not to
designate its then-existing derivative instruments as hedges which, subsequent
to adoption of SFAS No. 133, would require that changes in a derivative
instrument's fair value be recognized currently in earnings. However, SFAS No.
133 requires the Company's derivative instruments that had been designated as
cash flow hedges under accounting principles generally accepted prior to the
initial application of SFAS No. 133 to continue to be accounted for as cash flow
hedges with the transition adjustment reported as a cumulative-effect-type
adjustment to accumulated OCI as mentioned above.
In February 2001, the Company terminated certain derivative instruments
in connection with its emergence from bankruptcy for a cash payment of $28.0
million, which was offset against the accrued liability recorded in connection
with the adoption of SFAS No. 133. During the fiscal quarter ended March 31,
2001, the ultimate cost to settle the remaining derivative instruments in place
as of January 1, 2001 was reduced by $7.7 million as a result of market price
decreases. This non-cash gain was recorded in other revenue during the quarter.
The actual cost to settle the remaining derivatives was $8.1 million. During
2001, $15.5 million, net of tax, of the $28.5 million charged to OCI was
reclassified into earnings. The remaining $4.9 million in accumulated other
comprehensive income at December 31, 2003 will be amortized into earnings over
the original term of the derivative instruments, which extends through August
2005 ($2.9 million in 2004 and $2.0 million in 2005).
During 2001, all derivative contracts, other than the derivatives
terminated in connection with the Company's emergence from bankruptcy as
discussed above, were with Enron North America Corp., a subsidiary of Enron
Corp. At the end of November 2001, the Company had price swap contracts,
designated as hedges, covering 0.3 million MMBtu of December 2001 natural gas
production, and price swaps and collars covering 6.2 million MMBtu of 2002
natural gas production. The recorded value of these derivatives at that time was
estimated to be $2.7 million. Because of Enron's financial condition, the
Company concluded that these derivative contracts no longer qualified for hedge
accounting treatment. The Company unwound the December 2001 derivatives and
certain swap contracts covering 1.0 million MMBtu of 2002 natural gas
production. In December 2001, Enron North America Corp. and Enron Corp. filed
for bankruptcy protection and did not pay the Company for the contracts that
were unwound. As of December 31, 2001, $2.3 million in unrealized gains related
to 2002 natural gas production was included in accumulated OCI and was
reclassified into earnings during 2002 as the production relating to those
contracts occurred. The related assets were reclassified as a receivable from
Enron and a provision for doubtful accounts was established.
As of December 31, 2003, the Company had derivative instruments
outstanding covering 8.8 million MMBtu of 2004 natural gas production and 0.1
million barrels of 2004 oil production with a fair market value of $0.7 million.
The following table sets forth the Company's oil and natural gas hedged position
as of December 31, 2003.
61
Expected Maturity, 2004
---------------------------------------------------------- Fair Value at
1st 2nd 3rd 4th December 31,
Quarter Quarter Quarter Quarter Total 2003
---------- -------- -------- --------- ---------- -------------
(In thousands)
Swaps:
Oil
Volumes (bbl) 83,250 45,500 9,200 9,200 147,150 $ (201)
Weighted average price ($/bbl) $ 30.59 $ 29.64 $ 28.50 $ 28.50 $ 30.03
Natural Gas
Volumes (MMbtu) 2,420,000 910,000 920,000 - 4,250,000 $ 1,067
Weighted average price ($/MMbtu) $ 6.71 $ 5.00 $ 4.93 $ 5.96
Collars:
Natural Gas
Volumes (MMbtu) - 910,000 920,000 1,840,000 3,670,000 $ (208)
Weighted average price ($/MMbtu)
Floor $ - $ 4.00 $ 4.34 $ 4.00 $ 4.09
Cap $ - $ 6.81 $ 6.00 $ 7.52 $ 6.96
3-way collars:
Natural Gas
Volumes (MMbtu) 910,000 - - - 910,000 $ 31
Weighted average price ($/MMbtu)
Floor (purchased put option) $ 4.50 $ - $ - $ - $ 4.50
Cap 1 (sold call option) $ 8.50 $ - $ - $ - $ 8.50
Cap 2 (purchased call option) $ 9.00 $ - $ - $ - $ 9.00
The Company realized $6.2 million in net hedging losses during 2003,
including $5.5 million net hedging losses due to reclassifications from OCI for
contracts terminated prior to January 1, 2003. During 2002, the Company realized
$4.9 million in net hedging losses, including $5.0 million net hedging losses
due to reclassifications from OCI from contracts terminated prior to January 1,
2002. During 2001, the Company realized $22.1 million in net hedging losses and
$8.6 million net non-hedge derivative losses. The table below presents changes
in OCI associated with the Company's derivative transactions since adopting SFAS
No. 133.
(Amounts in thousands) 2003 2002
- ---------------------- ---- ----
Balance, beginning of year $ (8,501) $(11,162)
Reclassification adjustments of derivatives, net of tax 4,025 2,812
Changes in fair value of hedging positions (117) (144)
Ineffective portion of hedges 13 (7)
-------- --------
Balance, end of year $ (4,580) $ (8,501)
======== ========
The unrealized loss balances as of the end of year on the Company's
derivative transactions are net of income tax benefit of $2.5 million, $4.6
million and $7.0 million for 2003, 2002 and 2001, respectively.
11. LITIGATION
Medallion California Properties Company, a subsidiary of KCS, or MCPC,
was formerly a defendant in a lawsuit filed on January 30, 2001 in the Superior
Court, State of California, County of Los Angeles Central District in 2001 by
the Newhall Land and Farming Company, or Newhall, against MCPC and certain other
parties not affiliated with the Company. The lawsuit alleged environmental
contamination and surface restoration on lands in Los Angeles County, California
covered by an oil and gas lease owned by MCPC, referred to as the RSF Lease. In
addition, Newhall sought a declaration that it was entitled to terminate MCPC's
leasehold interest in the lands covered by the RSF Lease, or at least as to
those portions of the RSF Lease in which Newhall claimed MCPC was in default
under the terms of the lease. The case brought by Newhall was settled effective
as of June 30, 2003 and the parties released each other and dismissed their
respective claims with prejudice to their refiling. Under the terms of the
62
Settlement Agreement with respect to this case, the RSF Lease was declared to be
in full force and effect. Further, MCPC is obligated to conduct certain cleanup
and surface restoration activities in accordance with the lease terms on the
lands covered by the RSF Lease upon the earlier of abandonment of the lease or
the lessor's purchase of the lease, wells and related equipment as the lessor is
entitled to do under the terms of the RSF Lease. Also, MCPC must deposit 15% of
its net cash flow from the RSF Lease into an escrow account to secure
performance of its cleanup and surface restoration obligations. The amount of
the account to secure performance is capped at $2.0 million. Upon the timely,
satisfactory performance of MCPC's obligations, the $2.0 million will be
released from the escrow account and returned to MCPC.
The Company and several of its subsidiaries have been named as
co-defendants along with numerous other industry parties in an action brought by
Jack Grynberg on behalf of the Government of the United States. The complaint,
filed under the Federal False Claims Act in the United States District Court for
the District of Wyoming, alleges underpayment of royalties to the Government of
the United States as a result of alleged mismeasurement of the volume and
wrongful analysis of the heating content of natural gas produced from federal
and Native American lands. The complaint is substantially similar to other
complaints filed by Jack Grynberg on behalf of the Government of the United
States against multiple other industry parties. All of the complaints have been
consolidated into one proceeding. In April 1999, the Government of the United
States filed notice that it had decided not to intervene in these actions. The
Company believes that the allegations in the complaint are without merit.
The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of these proceedings and the Grynberg proceeding cannot be predicted
with certainty, management does not expect such matters to have a material
adverse effect, either individually or in the aggregate, on the financial
condition or results of operations of the Company. It is possible, however, that
charges could be required that would be significant to the operating results
during a particular period.
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters
--------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
(Dollars in thousands, except per share data)
2003
- ----
Revenue and other $ 40,440 $ 42,732 $ 40,671 $ 40,984
Operating income 18,941 20,732 16,122 14,360
Net income $ 13,902 $ 27,301 $ 11,681 $ 15,708
Basic earnings per common share $ 0.36 $ 0.71 $ 0.30 $ 0.35
Diluted earnings per common share $ 0.34 $ 0.66 $ 0.28 $ 0.35
Quarters
--------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
2002
- ----
Revenue and other $ 28,824 $ 30,277 $ 30,472 $ 29,246
Operating income 5,422 7,784 7,830 8,445
Net income (loss) $ (4,908) $ (12,368) $ 3,813 $ 3,349
Basic earnings (loss) per common share $ (0.15) $ (0.36) $ 0.10 $ 0.09
Diluted earnings (loss) per common share $ (0.15) $ (0.36) $ 0.09 $ 0.08
Effective January 1, 2002, the Company changed its method of amortizing
its oil and gas properties from FGR to UOP. Please read Note 1 to Consolidated
Financial Statements. The previously reported amounts reflected in quarterly
reports on Form 10-Q for the first three quarters of 2002 reflected FGR. These
amounts have been recalculated to reflect UOP in the table above. The effect of
this change was to decrease the net losses in the first and second quarters by
$2.1 million and $0.8 million, respectively, and increase net income by $0.2
million in both the third and fourth quarters.
63
The total of the earnings per share for the quarters may not equal the
earnings per share elsewhere in the Consolidated Financial Statements as each
quarterly computation is based on the weighted average number of common shares
outstanding during that period. In addition, certain potentially dilutive
securities were not included in certain of the quarterly computations of diluted
earnings (loss) per common share because to do so would have been anti-dilutive.
13. OIL AND NATURAL GAS PRODUCING OPERATIONS (UNAUDITED)
The following data is presented pursuant to SFAS No. 69 "Disclosure
about Oil and Gas Producing Activities" with respect to oil and natural gas
acquisition, exploration, development and producing activities and is based on
estimates of year-end oil and natural gas reserve quantities and forecasts of
future development costs and production schedules. These estimates and forecasts
are inherently imprecise and subject to substantial revision as a result of
changes in estimates of remaining volumes, prices, costs and production rates.
Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and natural gas prices as of
December 31, 2003 are not necessarily reflective of the prices the Company
expects to receive in the future. Other than natural gas sold under contractual
arrangements, natural gas prices were based on year-end spot market prices of
$5.97, $4.74 and $2.65 per MMBtu, adjusted by lease for Btu content,
transportation fees and regional price differentials as of December 31, 2003,
2002 and 2001, respectively. Oil prices were based on West Texas Intermediate,
or WTI, posted prices of $29.25, $28.00 and $16.75 as of December 31, 2003, 2002
and 2001, respectively, adjusted by lease for gravity, transportation fees and
regional price differentials.
Oil and natural gas reserves have been reduced to reflect the sale of
the Production Payment of 38.3 Bcf of natural gas and 797,000 barrels of oil in
2001 as discussed in Note 2.
64
PRODUCTION REVENUES AND COSTS (UNAUDITED)
Information with respect to production revenues and costs related to
oil and natural gas producing activities are set forth in the following table.
For the Year Ended December 31,
-----------------------------------------
2003 2002 2001
----------- ----------- -----------
(Dollars in thousands)
Revenue (a) $ 159,826 $ 120,002 $ 174,434
----------- ----------- -----------
Production (lifting) costs and taxes 34,606 30,835 38,651
Technical support and other 1,738 3,198 5,049
Depreciation, depletion and amortization (b) 48,908 49,120 58,172
----------- ----------- -----------
Total expenses 85,252 83,153 101,872
----------- ----------- -----------
Pretax income from producing activities 74,574 36,849 72,562
Income tax expense (benefit) (20,229) 13,763 (8,359)
----------- ----------- -----------
Results of oil and gas producing activities
(excluding corporate overhead and interest) $ 94,803 $ 23,086 $ 80,921
=========== =========== ===========
Depreciation, depletion and amortization rate
per Mcfe $ 1.41 $ 1.31 $ 1.25
=========== =========== ===========
Capitalized costs incurred:
Property acquisition $ (159) $ 4,822 $ 26,770
Exploration 10,067 12,428 15,321
Development (c) 78,646 30,314 42,942
----------- ----------- -----------
Total capitalized costs incurred $ 88,554 $ 47,564 $ 85,033
=========== =========== ===========
Capitalized costs at year end:
Proved properties $ 1,210,594 $ 1,119,339 $ 1,097,143
Unproved properties 6,769 3,364 8,470
----------- ----------- -----------
1,217,363 1,122,703 1,105,613
Less accumulated depreciation, depletion and
amortization (933,572) (891,124) (837,096)
----------- ----------- -----------
Net investment in oil and gas properties $ 283,791 $ 231,579 $ 268,517
=========== =========== ===========
- ----------
(a) Includes amortization of deferred revenue of $27,886 in 2003, $45,182 in
2002, and $63,089 in 2001 related to volumes delivered under the Production
Payment sold in February 2001. See Note 2.
(b) Includes accretion of asset retirement obligation of $1,116 as a result of
adoption of SFAS 143 in 2003. See Note 1.
(c) Includes the asset retirement costs incurred during the year.
DISCOUNTED FUTURE NET REVENUES (UNAUDITED)
The following information relating to discounted future net revenues
has been prepared on the basis of the Company's estimated net proved oil and
natural gas reserves in accordance with SFAS No. 69.
65
DISCOUNTED FUTURE NET REVENUES RELATING TO PROVED OIL AND GAS RESERVES
December 31,
-----------------------------------------
2003 2002 2001
----------- ----------- -----------
(Dollars in thousands)
Future cash inflows $ 1,556,851 $ 908,031 $ 631,061
Future costs:
Production (369,497) (279,282) (228,701)
Development (a) (117,726) (58,253) (64,251)
Future income taxes (229,892) (49,203) --
----------- ----------- -----------
Future net revenues 839,736 521,293 338,109
Discount - 10% (323,463) (199,077) (135,921)
----------- ----------- -----------
Standardized measure of discounted future
net cash flows $ 516,273 $ 322,216 $ 202,188
=========== =========== ===========
CHANGES IN DISCOUNTED FUTURE NET REVENUES FROM PROVED RESERVE QUANTITIES
For the Year Ended December 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
(Dollars in thousands)
Balance, beginning of year $ 322,216 $ 202,188 $ 852,608
Increases (decreases)
Sales, net of production costs (103,527) (48,878) (72,694)
Net change in prices, net of production costs 79,455 135,290 (660,420)
Discoveries and extensions, net of future production and
development costs 252,501 66,487 37,865
Changes in estimated future development costs (2,952) 13,636 7,046
Change due to acquisition of reserves in place 102 11,945 27,591
Development costs incurred during the period 28,978 6,868 10,689
Revisions of quantity estimates 24,916 (38,541) (14,433)
Accretion of discount 32,222 20,219 85,261
Net change in income taxes (92,391) (21,306) 251,871
Sales of reserves in place (6,450) (24,842) (341,223)
Changes in production rates (timing) and other (18,797) (850) 18,027
--------- --------- ---------
Net increase (decrease) 194,057 120,028 (650,420)
--------- --------- ---------
Balance, end of year (b) $ 516,273 $ 322,216 $ 202,188
========= ========= =========
- --------------------------
(a) Includes the cash outflows associated with asset retirement obligations.
(b) Excludes $27,886, $66,582 and $111,880 of deferred revenue at December 31,
2003, 2002 and 2001, respectively, related to the Production Payment sold
in 2001 as discussed in Note 2.
66
RESERVE INFORMATION (UNAUDITED)
The reserve estimates and associated revenues for all properties for
the years ended December 31, 2003 and 2001 were prepared by the Company and
audited by Netherland, Sewell & Associates, Inc., or NSAI. For the year ended
December 31, 2002, the reserve estimates and associated revenues for all
properties were prepared by NSAI. Proved developed reserves represent only those
reserves expected to be recovered through existing wells using equipment
currently in place. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells or from existing wells after material
recompletion expenditures. All of the Company's reserves are located within the
United States.
2003 2002 2001
--------------------- --------------------- --------------------
Natural Gas Oil Natural Gas Oil Natural Gas Oil
MMcf Mbbl MMcf Mbbl MMcf Mbbl
-------- ----- ------- ------ ------- -----
Proved developed and
undeveloped reserves
Balance, beginning of year 154,993 6,772 190,141 6,644 211,628 8,986
Production (a) (22,102) (972) (19,733) (1,082) (23,133) (1,273)
Discoveries, extensions, etc. 89,691 681 25,777 1,043 35,250 725
Acquisition of reserves in place 49 -- 6,253 161 18,382 140
Sales of reserves in place (b) (1,963) (293) (21,406) (879) (41,759) (1,064)
Revisions of estimates 7,450 507 (26,039) 885 (10,227) (870)
-------- -------- -------- -------- -------- --------
Balance, end of year 228,118 6,695 154,993 6,772 190,141 6,644
======== ======== ======== ======== ======== ========
Proved developed reserves
Balance, beginning of year 124,451 5,653 139,137 5,915 173,995 7,885
-------- -------- -------- -------- -------- --------
Balance, end of year 164,787 5,685 124,451 5,653 139,137 5,915
======== ======== ======== ======== ======== ========
- ----------
(a) Excludes volumes produced and delivered with respect to the Production
Payment sold in February 2001 as discussed in Note 2.
(b) The Company sold a Production Payment in 2001 as discussed in Note 2. The
approximate 38.3 Bcf of natural gas and 797,000 barrels of oil Production
Payment is reflected as sales of reserves in place in 2001 in the table
above. In 2002, the Company sold certain non-core properties.
Approximately 26% of the Company's reserves were classified as proved
undeveloped. Furthermore, approximately 14% of the Company's proved developed
reserves are classified as proved not producing. These reserves relate to zones
that are either behind pipe or that have been completed but not yet produced, or
zones that have been produced in the past but are not producing due to
mechanical reasons. These reserves may be regarded as less certain than
producing reserves because they are frequently based on volumetric calculations
rather than performance data.
67
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
By unanimous written consent dated July 1, 2002, our board of
directors, upon the recommendation of its audit committee, approved the
dismissal of Arthur Andersen LLP, or Andersen, and the appointment of Ernst &
Young LLP to serve as our independent public accountants for the fiscal year
ending December 31, 2002.
The audit reports of Andersen with respect to our consolidated
financial statements as of and for the fiscal years ended December 31, 2001 and
December 31, 2000 did not contain any adverse opinion or disclaimer of opinion,
nor were they qualified or modified as to uncertainty or audit scope. In
addition, there were no modifications as to accounting principles except that
the most recent audit report of Andersen dated March 13, 2002 contained an
explanatory paragraph with respect to the change in the method of accounting for
derivative instruments effective January 1, 2001 as required by the Financial
Accounting Standards Board.
During the fiscal year ended December 31, 2001 and the subsequent
interim period through July 1, 2002, there were no disagreements with Andersen
on any matter of accounting principles or practices, financial statement
disclosure, or auditing scope or procedure which, if not resolved to Andersen's
satisfaction, would have caused them to make reference to the subject matter in
connection with their report on our financial statements for those years, and
there were no reportable events as defined in Item 304(a)(1)(v) of Regulation
S-K.
We provided Andersen with a copy of the above disclosures and requested
that Andersen furnish us with a letter addressed to the Securities and Exchange
Commission stating whether or not Andersen agreed with the statements made by us
and, if not, stating the respects in which it does not agree. We were informed
by Andersen's national office that Andersen could not issue such a letter due to
the discontinuance of its audit practice.
During our fiscal year ended December 31, 2001 and the subsequent
interim period through July 1, 2002, we did not consult Ernst & Young LLP with
respect to the application of accounting principles to a specified transaction,
either completed or proposed, or the type of audit opinion that might be
rendered on our consolidated financial statements, or any other matters or
reportable events described in Items 304(a)(2)(i) and (ii) of Regulation S-K.
ITEM 9A. CONTROLS AND PROCEDURES.
Evaluation of disclosure controls and procedures. Based on their
evaluation of our disclosure controls and procedures as of the end of the period
covered by this report, our Chief Executive Officer and Chief Financial Officer
have concluded that our disclosure controls and procedures are effective in
ensuring that the information required to be disclosed by us in the reports that
we file or submit under the Securities Exchange Act of 1934, as amended, is
recorded, processed, summarized and reported, within the time periods specified
in the Securities and Exchange Commission's rules and forms.
Changes in internal control over financial reporting. There were no
changes in our internal control over financial reporting that occurred during
our last fiscal quarter that have materially affected, or are reasonably likely
to materially affect, our internal control over financial reporting.
68
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information concerning our officers and directors is set forth in the
sections entitled "Election of Directors" and "Executive Officers" of our Proxy
Statement for the 2004 Annual Meeting of Stockholders, which sections are
incorporated in this annual report on Form 10-K by reference. Information
concerning compliance with Section 16(a) of the Securities Exchange Act of 1934,
as amended, is set forth in the section entitled "Section 16(a) Beneficial
Ownership Reporting Compliance" of our Proxy Statement for the 2004 Annual
Meeting of Stockholders, which section is incorporated in this annual report on
Form 10-K by reference.
Information concerning our audit committee and our audit committee
financial expert is set forth in the section entitled "Information Concerning
the Board of Directors and Certain Committees of the Board of Directors" in our
Proxy Statement for the 2004 Annual Meeting of Stockholders, which section is
incorporated in this annual report on Form 10-K by reference.
We have adopted a Code of Ethics applicable to our principal executive
officer, principal financial officer and principal accounting officer. The Code
of Ethics applicable to our principal executive officer, principal financial
officer and principal accounting officer is filed as Exhibit 14.1 to this annual
report on Form 10-K. If we amend the Code of Ethics or grant a waiver, including
an implicit waiver, from the Code of Ethics, we intend to disclose the
information on our Internet website located at www.kcsenergy.com.
ITEM 11. EXECUTIVE COMPENSATION.
Information for this item is set forth in the sections entitled
"Executive Compensation," "Report of the Compensation Committee of the Board of
Directors on Executive Compensation," "Compensation Committee Interlocks and
Insider Participation," "Employment Agreements, Change in Control Agreements and
Retention Agreements," "Compensation of Directors" and "Performance Graph" in
our Proxy Statement for the 2004 Annual Meeting of Stockholders, which sections
are incorporated in this annual report on Form 10-K by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information for this item is set forth in the section entitled
"Security Ownership of Certain Beneficial Owners and Management" in our Proxy
Statement for the 2004 Annual Meeting of Stockholders, which section is
incorporated in this annual report on Form 10-K by reference.
Information concerning securities authorized for issuance under our
equity compensation plans is set forth in Item 5 of this Form 10-K and is
incorporated in Item 12 of this annual report on Form 10-K by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information for this item is set forth in the section entitled "Certain
Relationships and Related Transactions" in our Proxy Statement for the 2004
Annual Meeting of Stockholders, which section is incorporated in this annual
report on Form 10-K by reference.
ITEM 14. PRINCIPLE ACCOUNTING FEES AND SERVICES.
Information for this item is set forth in the section entitled
"Independent Public Accountants" in our Proxy Statement for the 2004 Annual
Meeting of Stockholders, which section is incorporated in this annual report on
Form 10-K by reference.
69
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) LIST OF DOCUMENTS FILED AS PART OF THE REPORT:
(1) FINANCIAL STATEMENTS. The following consolidated financial
statements and the related Report of Independent Public Accountants are
presented in Part II, Item 8 of this annual report on Form 10-K on the pages
indicated.
Page
----
Report of Independent Public Accountants......................................................... 39 - 40
Statements of Consolidated Operations for the years ended December 31, 2003, 2002 and 2001....... 41
Consolidated Balance Sheets at December 31, 2003 and 2002........................................ 42
Statements of Consolidated Stockholders' Equity (Deficit) for the years ended
December 31, 2003, 2002 and 2001............................................................ 43
Statements of Consolidated Cash Flows for the years ended December 31, 2003, 2002 and 2001....... 44
Notes to Consolidated Financial Statements....................................................... 45 - 67
(2) FINANCIAL STATEMENT SCHEDULES. Financial statement schedules have
been omitted because they are either not required, not applicable or the
information required to be presented is included in our financial statements and
related notes.
(3) EXHIBITS.
Exhibit No. Description
- ----------- -----------
2.1 Order of the United States Bankruptcy Court for the District
of Delaware confirming the KCS Energy, Inc. Plan of
Reorganization (incorporated by reference to Exhibit 2 to Form
8-K (File No. 001-13781) filed with the SEC on March 1, 2001).
3.1 Restated Certificate of Incorporation of KCS Energy, Inc.
(incorporated by reference to Exhibit (3)i to Form 10-K (File
No. 001-13781) filed with the SEC on April 2, 2001).
3.2 Certificate of Designation, Preferences, Rights and
Limitations of Series A Convertible Preferred Stock of KCS
Energy, Inc. (incorporated by reference to Exhibit (3)ii to
Form 10-K (File No. 001-13781) filed with the SEC on April 2,
2001).
3.3 Restated By-Laws of KCS Energy, Inc. (incorporated by
reference to Exhibit (3)iii to Form 10-K (File No. 001-13781)
filed with the SEC on April 2, 2001).
3.4 Amendments to Restated By-Laws of KCS Energy, Inc. effective
April 22, 2003 (incorporated by reference to Exhibit 3.1 to
Form 10-Q (File No. 001-13781) filed with the SEC on August
14, 2003).
4.1 Form of Common Stock Certificate, $0.01 Par Value
(incorporated by reference to Exhibit 5 to registration
statement on Form 8-A (No. 001-11698) filed with the SEC on
January 27, 1993).
4.2 Indenture dated as of January 15, 1998 between KCS Energy,
Inc., certain of its subsidiaries and State Street Bank and
Trust Company and First Supplemental Indenture dated February
20, 2001 (incorporated by reference to Exhibit (4)v to Form
10-K (File No. 001-13781) filed with the SEC on April 2,
2001).
4.3 Form of 8-7/8% Senior Subordinated Note due 2006 (included in
Exhibit 4.2).
4.4 Form of Series A Convertible Preferred Stock Certificate,
$0.01 Par Value (incorporated by reference to Exhibit (4)vii
to Form 10-K (File No. 001-13781) filed with the SEC on April
2, 2001).
10.1 1988 KCS Group, Inc. Employee Stock Purchase Program
(incorporated by reference to Exhibit 4.1 to registration
statement on Form S-8 (No. 33-24147) filed with the SEC on
September 1, 1988).*
70
10.2 Amendments to 1988 KCS Energy, Inc. Employee Stock Purchase
Program (incorporated by reference to Exhibit 4.2 to
registration statement on Form S-8 (No. 33-63982) filed with
the SEC on June 8, 1993).*
10.3 KCS Energy, Inc. 2001 Employee and Directors Stock Plan
(incorporated by reference to Exhibit (10)iii to Form 10-K
(File No. 001-13781) filed with the SEC on April 2, 2001). *
10.4 KCS Energy, Inc. Savings and Investment Plan and related
Adoption Agreement and Summary Plan Description. * +
10.5 Purchase and Sale Agreement between KCS Resources, Inc., KCS
Energy Services, Inc., KCS Michigan Resources, Inc. and KCS
Medallion Resources, Inc., as sellers, and Star VPP, LP, as
Buyer, dated as of February 14, 2001 (incorporated by
reference to Exhibit (10)vi to Form 10-K (File No. 001-13781)
filed with the SEC on April 2, 2001).
10.6 Second Amended and Restated Credit Agreement, dated as of
November 18, 2003 by and among KCS Energy, Inc., the lenders
from time to time party thereto, Bank of Montreal, as Agent
and Collateral Agent, and BNP Paribas, as Documentation Agent
(incorporated by reference to Exhibit 10.1 to Form 8-K (File
No. 001-13781) filed with the SEC on November 19, 2003).
10.7 First Amendment to Second Amended and Restated Credit
Agreement, effective as of February 26, 2004 by and among KCS
Energy, Inc., the lenders from time to time party thereto,
Bank of Montreal, as Agent and Collateral Agent, and BNP
Paribas, as Documentation Agent. +
10.8 Employment Agreement between KCS Energy, Inc. and James W.
Christmas (incorporated by reference to Exhibit (10)vii to
Form 10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.9 Employment Agreement between KCS Energy, Inc. and William N.
Hahne (incorporated by reference to Exhibit (10)viii to Form
10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.10 Employment Agreement between KCS Energy, Inc. and Harry Lee
Stout (incorporated by reference to Exhibit (10)ix to Form
10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.11 Change in Control Agreement dated May 27, 2003 between KCS
Energy, Inc. and Joseph T. Leary (incorporated by reference to
Exhibit 10.2 to Form 10-Q (File No. 001-13781) filed with the
SEC on August 14, 2003). *
10.12 Change in Control Agreement dated May 1, 2003 between KCS
Energy, Inc. and Frederick Dwyer (incorporated by reference to
Exhibit 10.3 to Form 10-Q (File No. 001-13781) filed with the
SEC on August 14, 2003). *
12.1 Statement regarding Computation of Ratios.+
14.1 Code of Ethics.+
21.1 Subsidiaries of KCS Energy, Inc.+
23.1 Consent of Netherland, Sewell and Associates, Inc.+
23.2 Notice Regarding Consent of Arthur Andersen LLP.+
23.3 Consent of Ernst & Young LLP.+
71
31.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
31.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
32.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002. +
32.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002. +
- -----------------------------
* Management contract or compensatory plan or arrangement.
+ Filed herewith.
(b) REPORTS ON FORM 8-K.
On October 2, 2003, we filed a report on Form 8-K under Item 5, Other
Events, reporting the issuance of a press release announcing continued
production increases in two significant fields and an increase in our capital
expenditure budget for 2003.
On October 29, 2003, we filed a report on Form 8-K under Item 5, Other
Events, reporting the issuance of a press release announcing the results of
recent drilling activity.
On November 6, 2003, we filed a report on Form 8-K under Item 5, Other
Events, reporting the issuance of a press release announcing our plans to sell
6,000,000 shares of common stock pursuant to an effective shelf registration
statement on Form S-3. The report on Form 8-K also furnished information under
Item 9, Regulation FD Disclosure, regarding anticipated prospectus supplement
disclosure regarding the use of proceeds of the proposed offering and that we
were currently negotiating a refinancing of our existing bank credit facility.
On November 7, 2003, we furnished a report on Form 8-K under Item 9,
Regulation FD Disclosure, disclosing certain information to be presented to
analysts and investors in connection with a common stock offering.
On November 7, 2003, we furnished a report on Form 8-K under Item 12,
Results of Operations and Financial Condition, reporting the issuance of a press
release announcing financial and operating results for the three and nine months
ended September 30, 2003.
On November 19, 2003, we filed a report on Form 8-K under Item 5, Other
Events, announcing that we had amended and restated our bank credit facility.
The report on Form 8-K also furnished information pursuant to Item 9, Regulation
FD Disclosure, announcing the issuance of a press release regarding the amended
and restated bank credit facility.
On November 21, 2003, we filed a report on Form 8-K under Item 5, Other
Events, announcing the execution of an Underwriting Agreement for the sale of
6,000,000 shares of common stock. The report on Form 8-K also furnished
information pursuant to Item 9, Regulation FD Disclosure, regarding the pricing
of the common stock offering.
On November 26, 2003, we furnished a report on Form 8-K under Item 9,
Regulation FD Disclosure, announcing that we closed a previously announced sale
of 6,000,000 shares of common stock.
On December 29, 2003, we filed a report on Form 8-K under Item 5, Other
Events, reporting the issuance of a press release announcing an increase in our
2004 capital expenditure budget.
72
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KCS ENERGY, INC.
Date: March 15, 2004 By: /s/ Frederick Dwyer
-------------------------------------------
Frederick Dwyer
Vice President, Controller and Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME TITLE DATE
---- ----- ----
/s/ James W. Christmas Chairman, Chief Executive Officer and Director March 15, 2004
- ---------------------------------
James W. Christmas (Principal Executive Officer)
/s/ William N. Hahne President, Chief Operating Officer and Director March 15, 2004
- ---------------------------------
William N Hahne
/s/ Joseph T. Leary Vice President and Chief Financial Officer March 15, 2004
- ---------------------------------
Joseph T. Leary (Principal Financial Officer)
/s/ Frederick Dwyer Vice President, Controller and Secretary (Principal March 15, 2004
- ---------------------------------
Frederick Dwyer Accounting Officer)
/s/ James L. Bowles Director March 15, 2004
--------------------------------
James L. Bowles
/s/ G. Stanton Geary Director March 15, 2004
- ---------------------------------
G. Stanton Geary
/s/ Robert G. Raynolds Director March 15, 2004
- ---------------------------------
Robert G. Raynolds
/s/ Joel D. Siegel Director March 15, 2004
- ---------------------------------
Joel D. Siegel
/s/ Christopher A. Viggiano Director March 15, 2004
- ---------------------------------
Christopher A. Viggiano
73
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------
2.1 Order of the United States Bankruptcy Court for the District
of Delaware confirming the KCS Energy, Inc. Plan of
Reorganization (incorporated by reference to Exhibit 2 to Form
8-K (File No. 001-13781) filed with the SEC on March 1, 2001).
3.1 Restated Certificate of Incorporation of KCS Energy, Inc.
(incorporated by reference to Exhibit (3)i to Form 10-K (File
No. 001-13781) filed with the SEC on April 2, 2001).
3.2 Certificate of Designation, Preferences, Rights and
Limitations of Series A Convertible Preferred Stock of KCS
Energy, Inc. (incorporated by reference to Exhibit (3)ii to
Form 10-K (File No. 001-13781) filed with the SEC on April 2,
2001).
3.3 Restated By-Laws of KCS Energy, Inc. (incorporated by
reference to Exhibit (3)iii to Form 10-K (File No. 001-13781)
filed with the SEC on April 2, 2001).
3.4 Amendments to Restated By-Laws of KCS Energy, Inc. effective
April 22, 2003 (incorporated by reference to Exhibit 3.1 to
Form 10-Q (File No. 001-13781) filed with the SEC on August
14, 2003).
4.1 Form of Common Stock Certificate, $0.01 Par Value
(incorporated by reference to Exhibit 5 to registration
statement on Form 8-A (No. 001-11698) filed with the SEC on
January 27, 1993).
4.2 Indenture dated as of January 15, 1998 between KCS Energy,
Inc., certain of its subsidiaries and State Street Bank and
Trust Company and First Supplemental Indenture dated February
20, 2001 (incorporated by reference to Exhibit (4)v to Form
10-K (File No. 001-13781) filed with the SEC on April 2,
2001).
4.3 Form of 8-7/8% Senior Subordinated Note due 2006 (included in
Exhibit 4.2).
4.4 Form of Series A Convertible Preferred Stock Certificate,
$0.01 Par Value (incorporated by reference to Exhibit (4)vii
to Form 10-K (File No. 001-13781) filed with the SEC on April
2, 2001).
10.1 1988 KCS Group, Inc. Employee Stock Purchase Program
(incorporated by reference to Exhibit 4.1 to registration
statement on Form S-8 (No. 33-24147) filed with the SEC on
September 1, 1988).*
10.2 Amendments to 1988 KCS Energy, Inc. Employee Stock Purchase
Program (incorporated by reference to Exhibit 4.2 to
registration statement on Form S-8 (No. 33-63982) filed with
the SEC on June 8, 1993).*
10.3 KCS Energy, Inc. 2001 Employee and Directors Stock Plan
(incorporated by reference to Exhibit (10)iii to Form 10-K
(File No. 001-13781) filed with the SEC on April 2, 2001). *
10.4 KCS Energy, Inc. Savings and Investment Plan and related
Adoption Agreement and Summary Plan Description. * +
10.5 Purchase and Sale Agreement between KCS Resources, Inc., KCS
Energy Services, Inc., KCS Michigan Resources, Inc. and KCS
Medallion Resources, Inc., as sellers, and Star VPP, LP, as
Buyer, dated as of February 14, 2001 (incorporated by
reference to Exhibit (10)vi to Form 10-K (File No. 001-13781)
filed with the SEC on April 2, 2001).
10.6 Second Amended and Restated Credit Agreement, dated as of
November 18, 2003 by and among KCS Energy, Inc., the lenders
from time to time party thereto, Bank of Montreal, as Agent
and Collateral Agent, and BNP Paribas, as Documentation Agent
(incorporated by reference to Exhibit 10.1 to Form 8-K (File
No. 001-13781) filed with the SEC on November 19, 2003).
10.7 First Amendment to Second Amended and Restated Credit
Agreement, effective as of February 26, 2004 by and among KCS
Energy, Inc., the lenders from time to time party thereto,
Bank of Montreal, as Agent and Collateral Agent, and BNP
Paribas, as Documentation Agent. +
10.8 Employment Agreement between KCS Energy, Inc. and James W.
Christmas (incorporated by reference to Exhibit (10)vii to
Form 10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.9 Employment Agreement between KCS Energy, Inc. and William N.
Hahne (incorporated by reference to Exhibit (10)viii to Form
10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.10 Employment Agreement between KCS Energy, Inc. and Harry Lee
Stout (incorporated by reference to Exhibit (10)ix to Form
10-K (File No. 001-13781) filed with the SEC on April 1,
2002). *
10.11 Change in Control Agreement dated May 27, 2003 between KCS
Energy, Inc. and Joseph T. Leary (incorporated by reference to
Exhibit 10.2 to Form 10-Q (File No. 001-13781) filed with the
SEC on August 14, 2003). *
10.12 Change in Control Agreement dated May 1, 2003 between KCS
Energy, Inc. and Frederick Dwyer (incorporated by reference to
Exhibit 10.3 to Form 10-Q (File No. 001-13781) filed with the
SEC on August 14, 2003). *
12.1 Statement regarding Computation of Ratios.+
14.1 Code of Ethics.+
21.1 Subsidiaries of KCS Energy, Inc.+
23.1 Consent of Netherland, Sewell and Associates, Inc.+
23.2 Notice Regarding Consent of Arthur Andersen LLP.+
23.3 Consent of Ernst & Young LLP.+
31.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
31.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
32.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002. +
32.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002. +
- ----------------------
* Management contract or compensatory plan or arrangement.
+ Filed herewith.