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, Wyoming and offshore Gulf of Mexico. As of December 31, 2005, our oil and natural gas properties were estimated to have net proved reserves of approximately 452 Bcfe with a PV-10 value of $1,672 million. Approximately 88% of our net proved reserve base was natural gas and approximately 74% was classified as proved developed. We operate approximately 86% 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, 2005.
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(1) Includes Michigan and Wyoming
(2) Includes California
In 2005, we increased production by 26% to an average of 137.7 MMcfe per day compared to 109.2 MMcfe per day in 2004. 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.
We are a publicly-owned company whose stock is traded on the New York Stock Exchange under the symbol "KCS." We were incorporated in Delaware 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 Road, 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.
2005 HIGHLIGHTS
For the year ended December 31, 2005, we drilled a record 193 wells, of which 180 were commercial, resulting in a 93% success rate and significantly increased production and reserves. In 2005, gross production increased 26%, to 50.3 Bcfe, while net production, after production payment delivery obligations that do not contribute to cash flow from operating activities, increased 33%, to 46.4 Bcfe, compared to 2004. Natural gas and oil reserves increased 38% to 452 Bcfe as of December 31, 2005, compared to 328 Bcfe as of December 31, 2004. In total, we added 180 Bcfe during 2005, sold five Bcfe and had negative revisions of four Bcfe. Sixty-eight percent of our reserve additions were through the drill bit. Total oil and gas capital expenditures were $379.9 million, of which $258.6 million was for oil and gas drilling activities and $121.3 million was for acquisitions of oil and gas properties. The PV-10 value of our proved oil and gas reserves increased 105% to $1,672 million.
As a result of the success of our drilling program, a 32% increase in average realized natural gas and oil prices, and a focus on controlling costs, we achieved record levels of oil and gas revenue ($363.7 million), operating income ($200.7 million) and cash provided by operating activities ($239.1 million).
In 2005, we continued to execute our strategies of focusing on low-risk development and exploitation drilling in our core operating areas and committing approximately 15% to 20% of our capital expenditure budget, exclusive of acquisitions, to moderate-risk, higher-potential exploration prospects.
In April 2005, we completed an acquisition of oil and gas properties and related assets located primarily in our North Louisiana core operating area for $86.9 million. This acquisition significantly increased our acreage position, drilling inventory and reserves in an area that we know well and have been successful in. The acquisition included internally estimated net proved reserves originally estimated at approximately 47 Bcfe, of which approximately two-thirds were undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations. The acquisition also included additional acreage with future drilling locations for which no proved reserves were assigned. In connection with the acquisition, we did a private placement of $100 million aggregate principal amount of 7 1/8% senior notes due 2012. The net proceeds from the private placement were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the acquisition. The remainder of the net proceeds from the offering was used to repay approximately $16.0 million of outstanding borrowings under our bank credit facility. We began drilling operations on these properties in the third quarter. As of December 31, 2005, 20 successful wells have been drilled on the acquired properties, net production had been increased from 6 MMcfe per day to 17 MMcfe per day and approximately 500 additional potential drilling locations with varying working or royalty interests had been identified.
In December 2005, we completed an acquisition of oil and gas properties located in Wharton County, Texas for $24.8 million. The acquisition included net proved reserves originally estimated at approximately 12 Bcfe, of which approximately 82% were proved developed.
We divested three non-core properties in 2005 for proceeds of approximately $11 million.
We further strengthened our financial flexibility by amending our bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million and extend the maturity date to March 31, 2009. In connection with the amended facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of our oil and natural gas reserves and other factors, from $100 million to $185 million.
We believe that the steps taken during 2005, along with our multi-year drilling prospect inventory, position us to increase production and reserves in 2006 and beyond.
COMPETITIVE STRENGTHS AND BUSINESS STRATEGIES
We intend to continue to increase production and reserves 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. Over the last three years, we drilled 401 wells, of which 378 were completed, resulting in a 94% success rate. As a result of this successful drilling program, we steadily increased our reserves and production. With our inventory of drilling prospects, we believe that we are well-positioned to continue growing our reserves and production.
- Reserve Growth -- During the last three years, we have added 375 Bcfe to our reserves, of which 84% were through the drill bit. Oil and gas capital expenditures during this period were $635 million. We achieved a 37%, 22% and 38% increase in reserves in 2003, 2004 and 2005, respectively.
- Production Growth -- As a result of our successful drilling program, we significantly increased our working interest production, net of production payment obligations, in each of the last three years. We achieved 18%, 25% and 33% growth in net production in 2003, 2004 and 2005, respectively. We are currently targeting net production growth of over 20% in 2006.
- Exploit Our Large Inventory of Drilling Projects -- We have a significant inventory of future drilling locations in targeted areas. 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. We have identified over 1,500 potential future drilling locations with varying working or royalty interests in the Elm Grove, Caspiana, Terryville, Sawyer Canyon, Talihina, Joaquin and other fields.
- 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.
- Focus on Natural Gas -- As of December 31, 2005, our proved reserves were 88% natural gas. We believe that the future need for natural gas in the United States will continue to grow. 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.
- Control Drilling and Production Operations -- As of December 31, 2005, we operated approximately 86% of our proved oil and natural gas reserve base. 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, 2005, we controlled the drilling operations on 151 of the 193 wells in which we participated.
- Search for Complimentary Acquisitions -- We proactively search for acquisitions in our core areas to expand our acreage position and drilling inventory. Recent examples of this are our April 2005 acquisition of properties in our North-Louisiana core operating area and the December 2005 acquisition in south Texas discussed above under "-- 2005 Highlights." These acquisitions are consistent with our strategy of focusing on core areas and growth through drilling.
- 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 24 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.
- 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 $315 million, exclusive of acquisitions, on capital projects in 2006. We expect that these projects will be funded primarily with internally generated cash flow. We believe that we have sufficient financial resources available to allow us the flexibility to be opportunistic with our drilling program and to fund larger acquisitions and working capital requirements.
- Control Risk -- We allocate approximately 80% to 85% of our capital on an annual basis to low risk development and exploitation projects and the remainder to moderate risk, higher potential exploration plays. We hedge a portion of our oil and natural gas to protect against downward price swings, and we monitor and 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 region operations provide us with a solid base for production and reserve growth. As of December 31, 2005, approximately 71% of our reserves, or 322 Bcfe, were located in the Mid-Continent fields. Our production from these fields averaged approximately 83 MMcfe per day of production in 2005. 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 2005, we drilled 134 wells in this region with a success rate of 98%. In 2006, we plan to drill approximately 175 wells in this region, approximately 45% of which are planned in the Elm Grove/Caspiana Fields. We will also pursue drilling in the Terryville, Sawyer Canyon, Joaquin and Talihina fields.
- Elm Grove/Caspiana Fields -- Located primarily in Bossier Parish of north Louisiana, production from these fields comes from the Hosston and Cotton Valley formations. These zones are composed of low permeability rocks that require fracture stimulation treatments to produce. In 2005, we significantly increased our acreage and ownership position and currently own working interests in 54 sections with an average WI of approximately 47%. A section is approximately 640 acres or one square mile. We also own overriding royalty interests in another nine sections. In 2005, these fields contributed approximately 31% of our net production. As of December 31, 2005, we had 185 Bcfe of proved reserves in these fields that accounted for approximately 48% of our PV-10 value.
We began a development program in late 2002 that included the drilling of six wells. Pursuant to this development program, we drilled 19 wells in 2003, 41 wells in 2004 and 69 wells in 2005, all of which were successful. This drilling activity increased gross operated production from 6 MMcfe per day in 2002 to approximately 70 MMcfe per day as of December 31, 2005. In 2006, we plan to drill approximately 75 proved undeveloped and step-out locations to continue growing production and reserves. In addition, we anticipate that we will participate in other non-operated wells.
- Terryville Field -- Located in Lincoln Parish, Louisiana, this field represents a developing play for us. We drilled one well in each of 2003 and 2004 and expanded our activity to drill seven wells in 2005, all of which were successfully completed. We have significantly increased our acreage position and hold working interests in the core of the field around the existing wells in over 20 sections and have added substantial additional acreage should the core productive area of the play expand. The objective formations in this field include the Cotton Valley and Gray sands. For 2006, we have budgeted the drilling of approximately 30 additional wells, including several extensional wells designed to determine the potential of the acreage outside the core area of the field.
- Sawyer Canyon Field -- Our second largest field, which contributed approximately 7% of our net production in 2005, is located in Sutton County, west Texas. We are actively producing and developing on lands comprising approximately 50 sections. Over the last several years, we have been conducting drilling programs targeting shallow Canyon sandstone formations. We have a 92% to 100% WI in most of the areas we are actively drilling. We drilled 18 wells in 2003, 25 wells in 2004, 13 wells in 2005 and plan to drill approximately 25 additional wells in 2006.
- Joaquin Field -- We operate a large portion and have rights to approximately 9,700 acres in this field located just west of the Texas- Louisiana border in Shelby County, Texas which produce Travis Peak and Cotton Valley sands at depths of 6,000 to 10,000 feet. In 2005, we drilled ten wells in this field and anticipate drilling approximately five additional wells in 2006.
GULF COAST
In the Gulf Coast region, we concentrate our drilling programs primarily in onshore south Texas. We also have working interests in several Mississippi salt basin properties and minor interests in several non-operated offshore properties. As of December 31, 2005, approximately 20% of our reserves, or 90 Bcfe, were located in the Gulf Coast fields. Our production from these fields averaged 39 MMcfepd of production in 2005. 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 with higher production potential. During 2005, we drilled 39 exploration and 20 development wells in this region with a success rate of 83%. We have initially budgeted drilling approximately 40 wells in this region in 2006, approximately three-fourths of which will be exploratory. In 2005, exploration success was achieved in the Austin Deep Field, Betsy Prospect, East La Grulla Field, North Murdock Pass Field, O'Connor Ranch Field, Coquat Field and the La Reforma Field. The 2006 drilling program will be concentrated in many of these same areas. In December 2005, we acquired a 100% WI in the Magnet Withers Field and have budgeted five wells to be drilled in 2006.
Central, South Texas -- We have been successful in pursuing exploration prospects primarily in Harris, Goliad, Victoria, Live Oak and Galveston counties. Our primary objectives are the abnormally pressured Middle Wilcox sands, although we also explore for and produce from normal pressured Frio and Yegua sands. Typically, we generate these prospects based on 3D seismic information and retain a 25% to 65% WI, although, we also participate in a number of non-operated projects.
In 2005, we drilled 29 wells in the O'Connor Ranch Field, twelve wells in the West Mission Valley area (West Mission Valley, East Marshall, Marshall fields and Betsy Prospect), four wells in the Coquat Field, four wells in the Austin Deep Field, two wells in the La Reforma Field, and eight other wells.
In 2006, we will pursue similar drilling opportunities in the same areas and also have drilling planned in new areas including the Magnet Withers, Sandy Hook and Day Dome fields acquired in 2005 as well as new plays in south Texas and the Mississippi Salt Basin.
Other Gulf Coast -- We have minor, non-operated working interests in several offshore blocks. These properties incurred only relatively minor damage from hurricanes in 2005.
OTHER OPERATING AREAS
We also operate and own majority interests in fields located in the Niagran Reef play of Michigan, several fields in Wyoming and one field in the Los Angeles basin in California. As of December 31, 2005, these properties accounted for approximately 9% of our reserves.
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. Our bank credit facility is secured by our oil and gas assets.
The following table sets forth the number of gross and net producing wells by region as of December 31, 2005.
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(1) Includes Michigan and Wyoming
(2) Includes California
OIL AND GAS RESERVES
The following table sets forth, as of December 31, 2005, 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, 2005 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. Please read Note 12 to our Consolidated Financial Statements for more information.
In accordance with Securities and Exchange Commission, or SEC, 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, 2005 spot price of $10.08 per MMBtu, adjusted by lease for Btu content, transportation fees and regional price differentials. Oil prices are based on a December 31, 2005 West Texas Intermediate posted price of $57.75 per barrel, adjusted by lease for gravity, transportation fees and regional price differentials. Hedge-adjusted prices are not considered for purposes of calculating future cash inflows. 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 "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" for further discussion of these and other factors.
The estimates of our proved oil and natural gas reserves and associated revenues, as of December 31, 2005, were prepared by us and were audited by Netherland Sewell & Associates, Inc., or NSAI. NSAI follows the general principles set forth in the standards pertaining to the auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers, or SPE.
A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:
- A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
- The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that can only be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by the company is reasonable and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
- The methods and procedures used by a company, and the reserve information furnished by the company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. In some cases, the auditing procedure may require the reserve auditor to prepare its own estimates of reserve information for particular properties. The desirability of preparing its own estimates is determined by the reserve auditor exercising its professional judgment.
In performing our reserve audit, NSAI prepares its own estimates of reserves and future value for the properties that represent the majority of our reserves and future value. As part of the audit process, we provide NSAI our assessment of reserves and future value. NSAI compares their estimates to those provided by us and once NSAI is satisfied that our reserve and future value estimates are reasonable and that their audit objectives have been met, the process is deemed complete. When compared on a well-by-well or lease-by-lease basis, some of our estimates of net
proved reserves may be greater and some may be less than the estimates of NSAI. We have been advised by NSAI that it generally issues a completed audit opinion if its reserve estimates are within 10% of a company's reserve estimates. At the conclusion of the audit process, it is NSAI's opinion, as set forth in its audit letter, that our estimates of our proved oil and natural gas reserves and associated net future revenues are, in the aggregate, reasonable and have been prepared in accordance with SEC guidelines and generally accepted petroleum engineering and evaluation principles.
PRODUCTION
The following table presents certain information with respect to production attributable to our properties including average sales prices and unit costs for the years ended December 31, 2005, 2004 and 2003.
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(a) The average realized prices reported above include the non-cash effects of volumes delivered under the production payment as well as the unwinding of various derivative contracts terminated in 2001. These items do not generate cash to fund our operations. Excluding these items, the average realized price per Mcfe was $7.61, $5.85 and $5.05 in 2005, 2004 and 2003, respectively. For further information, please read "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, 2005. 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.
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, 2005, we participated in drilling 401 (283.5 net) wells with a success rate of 94%. During 2005, we participated in drilling 193 (136.4 net) wells with a success rate of 93%. Our drilling results for 2005 include 152 development wells and 41 exploration wells with success rates of 97% and 80%, 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, 2005, 2004 and 2003.
As of December 31, 2005, we were participating in the drilling of 16 (9.7 net) wells.
OTHER FACILITIES
We lease approximately 25,000 square feet of office space at our principal executive offices located at 5555 San Felipe Road, Suite 1200, Houston, Texas 77056 under a lease that expires in December 2006. We also lease approximately 33,000 square feet for the operations of our subsidiaries in Tulsa, Oklahoma under a lease that expires in September 2006. In addition, we have field offices in various locations from which our employees supervise local oil and gas operations.
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 natural gas properties;
- establish maximum rates of production from oil and natural gas wells; and
- 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 natural 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 natural 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 natural gas business involves a variety of operating risks, including the risk of fires, natural disasters, explosions, well blowouts, adverse weather conditions, mechanical problems, including pipe failure, abnormally pressured formations, and environmental accidents, including 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, natural resources or other property or equipment, pollution and other environmental damage. 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 natural 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 or other operations commence;
- 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, among others, 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 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 relative operational, environmental, and human health and other risks.
Our operations are also subject to the United States 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 natural gas exploration and production activities, are subject to regulation. These regulations include permitting, bonding, operating, maintenance and reporting requirements. We do not believe that our operations will be materially adversely affected by these 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.
COMPETITION
We operate in the highly competitive exploration and production segment of the oil and gas industry. We compete with major oil and natural gas companies, other independent oil and natural 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 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 generally 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 with unaffiliated third parties for a portion of our production. Please read Note 11 to our Consolidated Financial Statements for information regarding our derivative instruments.
In 2005, two customers, Louis Dreyfus Corporation and its affiliates and Regency Gas Services, LP (formerly Regency Gas Services LLC), accounted for 26% and 13%, respectively, of our consolidated revenue. In 2004, one customer, Louis Dreyfus Corporation and its affiliates, accounted for 19% of our consolidated revenue. Other than the amortization of deferred revenue associated with the Production Payment sold in 2001, no other customer accounted for more than 10% of our consolidated revenues in 2005, 2004 or 2003.
SEASONALITY
Demand for natural gas and oil is seasonal, principally related to weather conditions.
EMPLOYEES
As of December 31, 2005, we employed a total of 152 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 as soon as reasonably practicable after we electronically file these materials with, or furnish these materials to, the Securities and Exchange Commission.
ITEM 1A.
ITEM 1A. RISK FACTORS.
The risks described below are those which we believe are the material risks that we face. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations.
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 in the future. The NYMEX daily settlement price for natural gas for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. In 2005, the same index ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2004 ranged from a high of $55.17 per barrel to a low of $32.48 per barrel. In 2005, the same index ranged from a high of $69.81 per barrel to a low of $42.12 per barrel. The relatively high oil and natural gas prices that have contributed significantly to our increased earnings over the past few years may not continue and could drop precipitously in a short period of time. The prices of oil and natural gas we receive are subject to wide fluctuations in response to a variety of factors beyond our control, including the following:
- relatively minor changes in the supply of, and demand for, domestic and foreign oil and natural gas;
- weather conditions;
- market uncertainty;
- the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production controls;
- the level of consumer demand;
- political conditions in international oil-producing regions, such as the Middle East, Nigeria and Venezuela;
- domestic and foreign governmental regulations and taxes;
- the price and availability of alternative fuels;
- speculation in the commodity futures markets;
- overall domestic and global economic conditions;
- the price of oil and natural gas imports;
- the effect of worldwide energy conservation measures; and
- the proximity to and capacity of transportation facilities.
These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of oil and natural gas.
As oil and natural gas prices decline, we are affected in several ways:
- we are paid less for our oil and natural gas, thereby reducing our cash flows, which decreases funds available for capital expenditures employed to increase production or replace reserves;
- exploration and development activity may decline as some projects may become uneconomic and either are delayed or eliminated, leading to both lower cash flow and proved reserves;
- our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserve values, thereby reducing our liquidity and possibly requiring mandatory loan repayments; and
- access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable in a low price environment.
Accordingly, any substantial or extended decline in oil or natural gas prices could have material adverse effects on our revenues, cash flow, liquidity and profitability and could cause us to be unable to meet our financial obligations or make planned capital expenditures.
WE MAY BE UNABLE TO PRODUCE SUFFICIENT AMOUNTS OF OIL AND NATURAL GAS AND, AS A RESULT, OUR PROFITABILITY AND CASH FLOW WILL DECLINE.
Developing and exploring properties for oil and natural gas reserves requires significant capital expenditures and involves a high degree of financial risk. We may drill new wells that are not productive or we may not recover all or any portion of our investment as exploratory wells bear a much greater risk of loss than development wells. 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;
- title problems;
- weather conditions;
- equipment shortages;
- mechanical difficulties;
- 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 expected costs of drilling, completing and operating wells are often uncertain and may be exceeded.
If we are unable to produce sufficient amounts of oil and natural gas, our profitability and cash flow will decline.
IF WE ARE UNABLE TO ACQUIRE OR DISCOVER ADDITIONAL RESERVES, OUR RESERVES AND PRODUCTION WILL DECLINE MATERIALLY, WHICH COULD RESULT IN LOWER REVENUES AND CASH FLOW.
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. Further, when oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to conduct exploratory and development drilling and replace our reserves and an increased need to draw on our bank credit facility or raise money in the debt and equity markets. Even if we have sufficient capital to explore or develop a
property, unsuccessful wells will have an adverse effect on our ability to replace reserves. As a consequence, our acquisitions, exploration and development activities may not result in significant additional reserves or reserves that are economically recoverable. Without the acquisition, discovery or development of additional reserves, our proved reserves and production will decline materially, which could result in lower revenues and cash flow.
SHORTAGE OF DRILLING RIGS, EQUIPMENT, SUPPLIES OR PERSONNEL MAY DELAY OR RESTRICT OUR OPERATIONS.
Our industry is experiencing a shortage of drilling rigs, equipment, supplies and qualified personnel. Costs and delivery times of drilling rigs, equipment and supplies are substantially greater than they were several years ago. Shortages of drilling rigs, equipment, supplies or qualified personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
THERE ARE NUMEROUS UNCERTAINTIES INHERENT IN ESTIMATING QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND FUTURE NET REVENUES. ACCORDINGLY, THE QUANTITIES AND VALUES OF OUR PROVED OIL AND NATURAL GAS RESERVES MAY VARY SIGNIFICANTLY FROM EXPECTATIONS.
The quantities and values of our proved reserves included in this annual report and in the other documents we file with, or furnish to, the Securities and Exchange Commission are only estimates and are subject to numerous uncertainties. 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 significantly 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 expenses;
- 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;
- timing and amount of development expenses; and
- workover and remedial costs.
Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserve reports.
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, estimated abandonment pressure and estimates of recovery factors. As production data becomes available, the actual performance is generally used to project the final reserves. As such, initial reserve estimates are much less precise in nature. 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, which may be material, 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 materially 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 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 natural gas industry in general.
For the foregoing reasons, you should not assume that the present value of future net cash flows from our proved reserves referred to in this annual report or in our other reports filed with, or furnished to, the Securities and Exchange Commission is the current market value of our estimated oil and natural gas reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual prices and costs since the date of the estimate and future prices and costs may differ materially from those used in the net present value estimate, and as a result, net present value estimates using current prices and costs may be significantly more or less than the estimate which is provided in this annual report or in our other reports filed with, or furnished to, the Securities and Exchange Commission.
WE MAY BE UNABLE TO SATISFY OUR FUTURE CAPITAL REQUIREMENTS.
We make substantial capital expenditures in connection with the acquisition, exploration and development of oil and natural gas properties. In the past, we have funded these capital expenditures with cash flow from operations, funds from long-term debt financings, including bank financings secured by our oil and natural gas assets, and funds from equity financings. Our future cash flows are subject to a number of factors, some of which are beyond our control, including the following:
- the price 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 natural gas properties and our cash flow in evaluating our prospects for growth and profitability. If our future cash flows decrease, however, and we are unable to obtain additional long-term debt or equity financing or our borrowing base under our bank credit facility is re-determined to a lower amount, we may be unable to satisfy our future capital requirements.
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 natural gas 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 exploration, development and extension wells. Although we regularly engage in discussions concerning, and submit proposals with respect to, potential acquisitions, suitable acquisitions may not be available in the future on reasonable terms as there is intense competition for acquisition opportunities in our industry. If we do identify an appropriate acquisition opportunity, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the acquisition occurs, effectively integrate the acquired
properties or 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 properties or businesses may not generate revenues comparable to our existing properties or business, the anticipated cost efficiencies or synergies may not be realized and these properties or businesses may not be integrated successfully or operated profitably. Further, as is customary in the industry, we generally acquire oil and gas properties without any warranty of title except through the transferor. In many instances, title opinions are not obtained if, in our judgment, it would be uneconomical or impractical to do so. Accordingly, we may incur losses from title defects or from defects in the assignment of leasehold rights.
The success of any acquisition will depend on a number of factors, many of which are beyond our control, including:
- the ability to estimate accurately the recoverable volumes of reserves;
- the ability to estimate accurately rates of future production and future net revenues attainable from the reserves;
- future oil and natural gas prices;
- future operating costs; and
- the ability to estimate accurately potential environmental and other contingent liabilities.
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 not be able to obtain contractual indemnities from the sellers for liabilities that it created and we may assume certain environmental and other risks and liabilities in connection with the acquired properties or businesses. The discovery of any material liabilities associated with our acquisitions could harm our results of operations.
In addition, acquisitions of properties or 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 notes contain certain covenants that limit, or which may have the effect of limiting, among other things, acquisitions, the sale of assets and the incurrence of additional indebtedness. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.
IF WE ARE UNSUCCESSFUL TRANSPORTING OUR OIL AND NATURAL GAS TO MARKET AT COMMERCIALLY ACCEPTABLE PRICES, OUR PROFITABILITY WILL DECLINE.
We deliver oil and natural gas through gathering systems and pipelines, most of which we do not own. Our ability to transport our oil and natural gas to market at commercially acceptable prices or at all depends on, among other factors, the following:
- the availability, proximity and capacity of third-party gathering systems, processing facilities and pipelines;
- the contractual terms we negotiate with third parties to transport our production;
- federal and state regulation of oil and natural gas production and transportation;
- tax and energy policies;
- pipeline pressures;
- damage to or destruction of pipelines;
- changes in supply and demand; and
- general economic conditions.
Our inability to respond appropriately to changes in any of the foregoing factors could result in the shut-in of producing wells and/or the delay or discontinuance of development plans for properties, which would negatively affect our profitability. For example, we are subject to several of the aforementioned risks with respect to our production from the Elm Grove Field in north Louisiana where we deliver approximately 85% of the production from this field to one pipeline system owned by Intrastate Gas LLC.
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.
TERRORIST ATTACKS AND CONTINUED HOSTILITIES IN THE MIDDLE EAST OR OTHER SUSTAINED MILITARY CAMPAIGNS MAY ADVERSELY IMPACT OUR FINANCIAL CONDITION AND OPERATIONS.
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 continued threat of terrorism and the impact of military and other action, including U.S. military operations in Iraq, may lead to continued volatility in prices for crude oil and natural gas and could affect the markets for our operations. In addition, future acts of terrorism could be directed against companies operating in the United States. The United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations, and those of our purchasers, to increased risks and, depending on their ultimate magnitude, may adversely impact our financial condition and operations.
OUR RESERVES, PRODUCTION AND CASH FLOW ARE HIGHLY DEPENDENT UPON OPERATIONS THAT ARE CONCENTRATED IN THREE PRIMARY AREAS.
At December 31, 2005, the vast majority of our oil and gas reserves were located in north Louisiana, Texas and Oklahoma. Approximately 41% of our reserves are located in the Elm Grove and Caspiana fields in north Louisiana. The concentrated nature of our operations subjects us to the risk that a regional event could cause a significant interruption in our production or otherwise have a material affect on our profitability.
OUR SUCCESS DEPENDS ON KEY PERSONNEL, THE LOSS OF WHOM COULD ADVERSELY AFFECT OUR BUSINESS.
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, and 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 the oil and natural 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. Our drilling success and the success of other activities integral to our operations depends, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals and competition for these individuals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete will be adversely affected. We do not maintain key person life insurance on any of our senior management members or our technical staff.
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 natural 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 natural gas companies, other independent oil and natural gas concerns and individual producers and operators in most aspects of our business, including the following:
- the acquisition of oil and natural gas properties and businesses;
- the exploration, development, production and marketing of oil and natural gas;
- the acquisition of properties and equipment; and
- the hiring and 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 than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition and results of operations may be adversely affected.
WE HAVE LIMITED CONTROL OVER THE ACTIVITIES ON PROPERTIES THAT WE DO NOT OPERATE, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON THE REALIZATION OF OUR TARGETED RETURNS OR LEAD TO UNEXPECTED FUTURE COSTS.
As of December 31, 2005, we operated approximately 86% of our proved oil and natural gas reserve base. However, other companies operate the other 14%. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the number of wells we drill, realization of our targeted returns or lead to unexpected future costs.
OUR OPERATING ACTIVITIES INVOLVE SIGNIFICANT RISKS THAT ARE INHERENT IN THE OIL AND NATURAL GAS INDUSTRY, WHICH MAY RESULT IN SUBSTANTIAL LOSSES, AND INSURANCE MAY BE UNAVAILABLE OR INADEQUATE TO PROTECT US AGAINST THESE RISKS.
Our operations are subject to numerous operating risks that are beyond our control, are inherent in the oil and natural gas industry and could result in substantial losses. These risks include:
- fires;
- hurricanes or other natural disasters;
- explosions;
- well blowouts and craterings;
- adverse weather conditions;
- mechanical problems, including pipe failure, stuck oil field drilling and services tools and casing collapse;
- abnormally pressured formations; and
- environmental accidents, including oil spills, natural gas leaks or ruptures, or other discharges of brine, well fluids, toxic gases or other pollutants into the environment, including groundwater and shoreline contamination.
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, natural resources or other property or equipment, pollution and other environmental damage. 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:
- unexpected drilling conditions;
- the presence of unanticipated pressure or irregularities in formations;
- equipment failures or accidents;
- title problems;
- weather conditions;
- compliance with governmental requirements; and
- costs of, shortages or delays in the availability of drilling rigs or in the delivery of equipment and experienced labor.
UNINSURED JUDGMENTS OR A RISE IN INSURANCE PREMIUMS MAY ADVERSELY IMPACT OUR RESULTS OF OPERATIONS.
The exploration for, and production of, oil and natural gas can be hazardous, involving unforeseen occurrences as described in the immediately preceding risk factor. Accordingly, in the ordinary course of business, we are subject to various claims and litigation. In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described in the immediately preceding risk factor. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The levels of insurance we maintain are in amounts that management believes to be prudent, but they may not be adequate to fully cover any and all losses or liabilities. If the occurrence of a significant accident, judgment, claim or other event is not fully insured or indemnified against, it could have a material adverse effect on our business, financial condition and results of operations. Further, we may not be able to maintain insurance at commercially acceptable premium levels or at all.
WE ENGAGE IN HEDGING TRANSACTIONS THAT INVOLVE CREDIT RISK AND MAY LIMIT OUR POTENTIAL GAINS AND EXPOSE US TO RISK OF FINANCIAL LOSS.
We currently, and expect to in the future, 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 instruments are intended to lock in prices in order to limit volatility and increase the predictability of cash flow, but may limit our potential gains if oil and natural gas prices 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 their contract obligations;
- we fail to make timely deliveries; and
- a sudden, unexpected event materially impacts oil or natural gas prices or the relationship between the hedged price index and the oil and natural gas sales price.
OUR BANK CREDIT FACILITY AND INDENTURE GOVERNING OUR SENIOR NOTES IMPOSE RESTRICTIONS ON US THAT MAY AFFECT OUR ABILITY TO SUCCESSFULLY OPERATE OUR BUSINESS AND OUR ABILITY TO MAKE PAYMENTS ON OUR INDEBTEDNESS.
Our bank credit facility and the indenture governing our senior notes include covenants that, among other things, restrict our ability to:
- borrow money;
- create liens;
- pay dividends;
- sell or transfer any of our material property; and
- merge into or consolidate with any third party or sell or dispose of all or substantially all of our assets.
We are also required by our bank credit facility to maintain specified interest coverage and current ratios. All of these and other covenants may restrict our ability to expand or to pursue our business strategies. Adverse financial or economic developments beyond our control may cause us to breach these covenants. The breach of any of these covenants could result in a default under our debt, causing the debt to become due and payable. Further, our borrowing base under our bank credit facility, which is redetermined semi- annually, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values. Upon a re-determination, if our outstanding borrowings were in excess of the revised borrowing capacity, we could be forced to repay a portion of that outstanding debt. We may not be able to repay the debt due as a result of an acceleration or a revision to our borrowing capacity.
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.
OUR LEVERAGE AND DEBT SERVICE OBLIGATIONS MAY ADVERSELY AFFECT OUR CASH FLOW AND OUR FINANCIAL AND OPERATING ACTIVITIES.
As of December 31, 2005, we had $291.1 million of total debt outstanding, which comprised approximately 50% of our total book capitalization. Our level of indebtedness may have important consequences for us, including the following:
- 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;
- 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 meet debt service obligations, thereby reducing the funds that would otherwise be available for working capital, capital expenditures and other general business activities;
- 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;
- limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
- making us vulnerable to increases in interest rates as the interest on debt under our bank credit facility is at variable rates;
- we could be more vulnerable to a downturn in our business or the economy in general; and
- we may be at a competitive disadvantage to the extent that we are more highly leveraged than some of our peers.
IN ADDITION TO OUR CURRENT INDEBTEDNESS, WE MAY BE ABLE TO INCUR SUBSTANTIALLY MORE DEBT. THIS COULD EXACERBATE THE RISKS DESCRIBED ABOVE.
Together with our subsidiaries, we may be able to incur substantially more debt in the future. Although our bank credit facility and the indenture governing our senior notes contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness as defined in the relevant agreement. As of December 31, 2005, we had $166.7 million of borrowing capacity available under our bank credit facility, subject to a number of qualifications. In addition, the indenture governing our senior notes allows for an unlimited amount of available capacity, subject to a number of qualifications. However, the bank credit facility contains provisions that restrict the amount of additional indebtedness that could be incurred under the indenture without consent ($25 million as of December 31, 2005). To the extent new debt is added to our current debt levels, the risks described in the immediately preceding risk factor could substantially increase.
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. Please read "Business -- Regulation" for more information. We 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 drilling locations or the rate of allowable hydrocarbon production from a well;
- affect the cost, terms and availability of oil and natural gas transportation by pipeline;
- impose liability on us under an oil and natural gas lease for the cost of pollution clean-up and remediation resulting from operations;
- impose liability on us for personal injuries and property damage;
- subject us to liability for pollution damages, including oil spills, discharge of hazardous materials and reclamation costs; and
- require suspension or cessation of operations in affected areas and subject the lessee to administrative, civil and criminal penalties.
Any of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more expensive for us to conduct our business or cause us to limit or curtail some of our operations.
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 Department of Transportation, through the Office of Pipeline Safety and Research and Special Programs Administration, has implemented a series of rules requiring operators of natural gas and hazardous liquid pipelines to develop integrity management plans for pipelines that, in the event of failure, could impact certain high consequence areas. These rules also require operators to conduct baseline integrity assessments of all applicable
pipeline segments located in the high consequence areas. We continually are in the process of identifying any of our pipeline segments that may be subject to these rules. We have developed an integrity management plan for all covered pipeline segments. We do not expect to incur significant costs in achieving compliance with these rules.
Further, 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.
The oil and natural gas regulatory environment could change in ways that could substantially increase the cost of complying with the requirements of environmental and other regulations. 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.
LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.
We perform quarterly "ceiling test" calculations as the 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. We refer to this expense as a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce net income. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and natural gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. We cannot assure you that we will not experience ceiling test write-downs in the future.
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.
WE ARE DEPENDENT ON OUR SUBSIDIARIES FOR OUR CASH FLOW.
We are a holding company with no material assets other than the equity interests of our subsidiaries. Our subsidiaries conduct substantially all of our operations and directly own substantially all of our assets. Therefore, our operating cash flow and ability to meet our debt obligations will depend on the cash flow provided by our subsidiaries in the form of loans, dividends or other payments to us as a shareholder, equity holder, service provider or lender. The ability of our subsidiaries to make such payments to us will depend on their earnings, tax considerations, legal restrictions and restrictions under their indebtedness.
NEW TECHNOLOGIES MAY CAUSE OUR CURRENT EXPLORATION AND DRILLING METHODS TO BECOME OBSOLETE.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at significant cost. One or more of the technologies that we currently utilize or that we may implement in the future may become obsolete. We may be unable to implement new technologies on a timely basis or at a cost that is acceptable to us. If we are not able to maintain technological advancements consistent with industry standards, our business, prospects, financial condition and results of operations may be adversely affected.
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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES.
Reference is made to Item 1. Business, "-- Core Operating Areas," "-- Other Operating Areas," "-- 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.
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to Note 8 to our Consolidated Financial Statements included elsewhere in this annual report on Form 10-K.
ITEM 4.
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, 2005.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
MARKET AND HOLDERS INFORMATION
Our common stock is traded on the New York Stock Exchange under the symbol "KCS." As of February 15, 2006, there were approximately 841 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 2005 and 2004, the high and low sales price per share of our common stock, as reported in the composite transaction reporting system.
On March 10, 2006, the last reported sales price of our common stock on the New York Stock Exchange was $21.63 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.
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, 2005.
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(1) Represents shares that may be issued in the future pursuant to the KCS Energy, Inc. 2005 Employee and Directors Stock Plan, or 2005 Stock Plan. The 2005 Stock Plan permits the issuance of stock options, including incentive stock options, retainer stock , stock appreciation rights, restricted stock and bonus stock.
(2) Represents options granted under our 2001 Employee and Directors Stock Plan, or 2001 Stock Plan. With the adoption of the 2005 Stock Plan, that was approved by our stockholders on June 10 2005, no additional options or other awards will be granted under the 2001 Stock Plan.
(3) Includes 749,920 shares authorized for issuance pursuant to our employee stock purchase program and 629,590 shares authorized for issuance in connection with our savings and investment (401(k)) plan.
KCS Energy, Inc. 2001 Employees and Directors Stock Plan. With the adoption of the 2005 Stock Plan, that was approved by our stockholders on June 10, 2005, no additional options or other awards will be granted under the 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. As of December 31, 2005, grants of 350,156 restricted shares were outstanding under the 2001 Stock Plan. Please read Note 5 to our Consolidated Financial Statements for a description of the 2001 Stock Plan.
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. Please read Note 5 to our Consolidated Financial Statements for a description of the employee stock purchase plan and Note 4 to our consolidated Financial Statements for a description of our savings and investment plan.
ITEM 6.
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, 2005. 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. Please read "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 for a discussion of factors that affect the comparability of this information and material uncertainties that may cause this information not to be indicative of our future financial condition or results of operations.
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(1) Includes stock compensation of $2.4 million in 2005, $2.6 million in 2004, $2.7 million in 2003, $0.8 million in 2002 and $1.4 million in 2001.
(2) Includes derivative liabilities of $48.1 million in 2005 and derivative assets of $0.9 million and $0.7 million in 2004 and 2003, respectively.
(3) Includes a $13.9 million income tax benefit related to the reversal of the remaining portion of our valuation allowance against net deferred income tax assets.
(4) Includes a $20.2 million 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."
(5) 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.
ITEM 7.
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.
OVERVIEW
We are 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, Wyoming and offshore Gulf of Mexico.
For the year ended December 31, 2005, we drilled a record 193 wells, of which 180 were commercial, resulting in a 93% success rate and significantly increased production and reserves. In 2005, gross production increased 26%, to 50.3 Bcfe, while net production, after production payment delivery obligations that do not contribute to cash flow from operating activities, increased 33%, to 46.4 Bcfe, compared to 2004. Natural gas and oil reserves increased 38% to 452 Bcfe as of December 31, 2005, compared to 328 Bcfe as of December 31, 2004. We added 180 Bcfe
during 2005, sold five Bcfe and had negative revisions of four Bcfe. Sixty-eight percent of our reserve additions were through the drill bit. Total oil and gas capital expenditures were $379.9 million, of which $258.6 million was for oil and gas drilling activities and $121.3 million was for acquisitions of oil and gas properties. The PV-10 value of our proved oil and gas reserves increased 105% to $1,672 million.
As a result of the success of our drilling program, a 32% increase in average realized natural gas and oil prices, and a focus on controlling costs, we achieved record levels of oil and gas revenue ($363.7 million), operating income ($200.7 million) and cash provided by operating activities ($239.1 million).
In 2005, we continued to execute our strategies of focusing on low-risk development and exploitation drilling in our core operating areas and committing approximately 15% to 20% of our capital expenditure budget, exclusive of acquisitions, to moderate-risk, higher-potential exploration prospects.
In April 2005, we completed an acquisition of oil and gas properties and related assets located primarily in our North Louisiana core operating area for $86.9 million. This acquisition significantly increased our acreage position, drilling inventory and reserves in an area that we know well and have been successful in. The acquisition included internally estimated net proved reserves originally estimated at approximately 47 Bcfe, of which approximately two-thirds were undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations. The acquisition also included additional acreage with future drilling locations for which no proved reserves had been assigned. In connection with the acquisition, we did a private placement of $100 million aggregate principal amount of 7 1/8% senior notes due 2012. The net proceeds from the private placement were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the acquisition. The remainder of the net proceeds from the offering was used to repay approximately $16.0 million of outstanding borrowings under our bank credit facility. We began drilling operations on these properties in the third quarter. As of December 31, 2005, 20 successful wells have been drilled on the acquired properties, net production had been increased from 6 MMcfe per day to 17 MMcfe per day and approximately 500 additional potential drilling locations with varying working or royalty interests had been identified.
In December 2005, we completed an acquisition of oil and gas properties located in Wharton County, Texas for $24.8 million. The acquisition included net proved reserves originally estimated at approximately 12.4 Bcfe, of which approximately 82% were proved developed.
We divested three non-core properties in 2005 for proceeds of approximately $11 million.
We further strengthened our financial flexibility by amending our bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million and extend the maturity date to March 31, 2009. In connection with the amended facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of our oil and natural gas reserves and other factors, from $100 million to $185 million.
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. As of December 31, 2005, approximately 71% of our reserves, or 322 Bcfe, were located in the Mid-Continent fields. Our production from these fields averaged approximately 83 MMcfe per day in 2005. 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 2005, we drilled 134 wells in this region with a success rate of 98%. In 2006, we plan to drill approximately 175 wells in this region, approximately 45% of which are planned in the Elm Grove/Caspiana Fields. We will also pursue drilling in the Terryville, Sawyer Canyon, Joaquin and Talihina fields.
In the Gulf Coast region, we concentrate our drilling programs primarily in onshore south Texas. We also have working interests in several Mississippi salt basin properties and minor interests in several non-operated offshore properties. As of December 31, 2005, approximately 20% of our reserves, or 90 Bcfe, were located in the Gulf Coast fields. These fields averaged approximately 39 MMcfepd of production in 2005. 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 with higher production potential.
During 2005, we drilled 39 exploration and 20 development wells in this region with a success rate of 83%. We have initially budgeted drilling approximately 40 wells in this region in 2006, approximately three-fourths of which will be exploratory. In 2005, exploration success was achieved in the Austin Deep Field, Betsy Prospect, East La Grulla Field, North Murdock Pass Field, O'Connor Ranch Field, Coquat Field and the La Reforma Field. The 2006 drilling program will be concentrated in many of these same areas. In December 2005, we acquired a 100% WI in the Magnet Withers Field and have budgeted five wells to be drilled in 2006.
We believe that the steps taken over the last several years position us to continue growing 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 primarily 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, among others, geopolitical activities, worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by OPEC, the level of consumer demand, domestic and foreign governmental regulations and taxes and the price and availability of alternative fuels. During 2005, natural gas prices were high in relation to historical prices. The 12-month average of NYMEX daily settlement price of natural gas increased from $6.18 per MMBtu as of December 31, 2004 to $9.01 per MMBtu as of December 31, 2005. Please read "-- Results of Operations" for information regarding the impact of oil and natural gas prices on our results of operations.
Our reported realized prices for oil and natural gas were also affected by the production payment, or Production Payment, we sold in February 2001 at a weighted average discounted price realized of $4.05 per Mcfe that had the effect of lowering our reported realized price in periods when cash prices exceeded $4.05 per Mcfe. The effect of the Production Payment was to reduce realized prices by $0.32, $0.27 and $0.29 per Mcfe in 2005, 2004 and 2003, respectively. Our delivery obligations under the Production Payment were fulfilled in January 2006. Accordingly, our reported prices for periods after January 2006 will not be impacted by the Production Payment.
We use commodity derivative contracts on a limited basis to manage our exposure to oil and natural gas price volatility. Our strategy is to maintain a disciplined approach by layering in a series of derivative contracts at different price levels depending on market conditions and other factors. We have typically targeted hedging approximately 30% to 50% of our near-term production. We do not enter into derivative or other financial instruments for trading or speculative purposes. Excluding the effect of the impact of the terminated derivative instruments discussed below and derivatives that did not qualify for hedge accounting treatment, hedging activities decreased realized oil and natural gas prices by $0.79, $0.10 and $0.02 in 2005, 2004 and 2003, respectively.
Certain terminated derivative instruments also affected our reported realized oil and natural gas 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 was amortized as a non-cash reduction of revenue over the original term of the derivative instruments which ended on December 31, 2005. The effect of this amortization of the cost of these terminated swaps was to reduce realized prices by $0.06, $0.11 and $0.16 per Mcfe in 2005, 2004 and 2003, respectively.
Production. The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. Our reported production includes volumes dedicated to the Production Payment discussed below. However, we view the net production after our delivery obligations associated with the Production Payment as more important because it is net production that generates cash flow. For example, while total production increased 26%, from 40.0 Bcfe in 2004 to 50.3 Bcfe in 2005, our net production actually increased 33%, from 34.8 Bcfe in 2004 to 46.4 Bcfe in 2005 as delivery obligations associated with the Production Payment declined from 5.2 Bcfe in 2004 to 3.9 Bcfe in 2005. This 1.3 Bcfe decrease in production committed to the Production Payment obligations in 2005 resulted in incremental cash flow of approximately $10.9 million.
Sale of Production Payment. In February 2001, we sold a Production Payment in connection with our emergence from Chapter 11. The net proceeds from this sale of approximately $175 million was recorded as deferred revenue which was amortized over the five-year period ended January 2006 as scheduled deliveries of production were made. Deliveries under this Production Payment were recorded as non-cash oil and gas revenue with a corresponding reduction of deferred revenue at the weighted average discounted price realized of approximately $4.05 per Mcfe. We also reflected the production volumes and depletion expense as deliveries were made. However, the associated oil and natural gas reserves were excluded from our oil and natural gas reserve data. Amortization of deferred revenue comprised 4%, 10% and 17% of our oil and gas revenue during 2005, 2004 and 2003, respectively.
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 better able to control our lease operating expenses because we are focused in certain core areas which allows us to operate more efficiently. Lease operating expenses were $35.4 million in 2005, $28.6 million in 2004 and $24.6 million in 2003. These costs reflect the levels of production and workover activities and increased service costs experienced by the oil and gas industry. In order to measure our operating performance, we monitor lease operating expenses on a per unit of production basis. Lease operating expenses per Mcfe were $0.70 in 2005, $0.72 in 2004 and $0.71 in 2003.
General and administrative expenses are monitored closely with the objective of operating an efficient organization with an appropriate cost structure. General and administrative expenses, excluding non-cash stock compensation, were $11.1 million, or $0.22 per Mcfe, in 2005, $9.3 million, or $0.23 per Mcfe, in 2004 and $8.4 million, or $0.24 per Mcfe, in 2003. The increases in gross dollars reflect the growth of the Company. The decrease in the per unit of production costs reflects our emphasis on cost containment as we grow the company.
Loss on mark-to-market derivatives. Net realized and unrealized gains and losses associated with our derivative instruments that do not qualify for hedge accounting treatment and the unrealized ineffective component of our derivatives that do qualify are reported below operating income as gains or losses on mark- to-market derivatives. For the year ended December 31, 2005, the net loss on mark-to-market derivatives was $9.7 million of which $5.2 million was related to the ineffective component of our hedge derivative contracts and $4.5 million was attributable to the change in fair value of our derivative instruments that do not qualify for hedge accounting treatment. This compares to a net loss of $1.1 million in 2004 primarily due to the ineffective component of our hedge derivative contracts.
OTHER FACTORS AFFECTING COMPARABILITY
Income Taxes. At December 31, 2002, we had established a valuation allowance against the full amount of our net deferred income tax assets as a result of uncertainty that the tax assets would ultimately be realized. Since that time, we have generated significant levels of taxable income due to drilling success and strong natural gas and oil prices. As a result of our evaluation of the outlook for continued generation of taxable income based on existing available information, including prices quoted on the New York Mercantile Exchange and our production levels, we reversed approximately $37.6 million of the valuation allowance in 2003 and the remaining $44.2 million in 2004. These amounts are reflected within the income tax benefits on our statements of consolidated income. In 2005, no such tax benefits flowed through our statement of consolidated operations as we resumed recording federal and state income taxes based on statutory rates. However, while our recorded effective income tax rate in 2005 was 38.7%, we continued to utilize our net operating loss carryforwards and paid only federal alternative minimum tax and state taxes equating, in the aggregate, to approximately 2% of pre-tax income. The remainder of the tax expense recorded in 2005 is deferred to future years.
Sale of Emission Credits. We sold emission credits totaling $4.9 million in 2003 which are reflected in other, net in our statements of consolidated operations. We sold only minor amounts in 2004 and 2005. We currently do not anticipate any significant emission credit sales in 2006.
Redemption Premium on Early Extinguishment of Debt. On May 1, 2004, we redeemed our $125 million 8 7/8% senior subordinated notes due 2006. Pursuant to the indenture, we paid an early redemption premium of $3.7 million, which was charged against earnings in the second quarter of 2004.
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 policies, 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 estimates, 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 policies, estimates and judgments 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 compensation 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 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 by Netherland, Sewell & Associates, Inc., independent petroleum engineers.
AMORTIZATION OF OIL AND GAS PROPERTIES
We amortize 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 WI. 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 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 our oil and natural gas 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 we will generate in the future. Our current net operating loss carryforwards aggregating approximately $75 million have remaining lives ranging from 14 to 17 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 to establish or adjust a valuation allowance.
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.
Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations", or 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.
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.
DERIVATIVES
We use commodity derivative contracts 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. Our derivative instruments that do not qualify for hedge accounting treatment pursuant to SFAS No. 133 and the ineffective component of our derivatives that do qualify are reported below operating income as gains or losses on mark-to-market derivatives.
RESULTS OF OPERATIONS
For the year ended December 31, 2005, total revenue and other increased 67% to $364.7 million compared to $218.4 million in 2004 due primarily to a 26% increase in oil and natural gas production (33% increase in daily net production contributing to cash flow from operating activities) and a 32% increase in average realized prices. Operating income in 2005 increased 90% to $200.7 million compared to $105.4 million in 2004. Loss on mark-to-market derivatives, net for the twelve months ended December 31, 2005 was $9.7 million compared to $1.1 million in 2004. Income before income taxes and cumulative effect of accounting change in 2005 increased 99%, to $172.6 million compared to $86.5 million in 2004. Federal and state income tax expense in 2005 was $66.7 million reflecting an effective tax rate of 38.7%. This compares to an income tax benefit of $13.9 million in 2004 due to the change in our valuation allowance against our net deferred tax asset. Please read Note 10 to our Consolidated Financial Statements for more information regarding income taxes. Net income in 2005 was $105.9 million, or $2.13 per basic share and $2.11 per diluted share, compared to $100.4 million, or $2.06 per basic share and $2.03 per diluted share, in 2004.
For the year ended December 31, 2004, total revenue and other increased 32% to $218.4 million compared to $164.9 million in 2003 due primarily to a 15% increase in oil and natural gas production (25% increase in daily net production contributing to cash flow from operating activities) and a 19% increase in average realized prices, partially offset by lower non oil and gas revenue. Operating income in 2004 increased 50% to $105.4 million compared to $70.2 million in 2003. Income before income taxes and cumulative effect of accounting change in 2004 increased 76% to $86.5 million compared to $49.3 million in 2003. Income tax benefit for 2004 was $13.9 million compared to $20.2 million in 2003 due to changes in our valuation allowance against our net deferred tax asset. In 2003, we recorded a cumulative effect of accounting change of $0.9 million as a result of the adoption of
SFAS No. 143. Income available to common stockholders in 2004 was $100.4 million, or $2.06 per basic share and $2.03 per diluted share, compared to $67.7 million, or $1.71 per basic and $1.61 per diluted share, in 2003.
The following table sets forth: (i) our gross natural gas, oil and natural gas liquids production; (ii) our production net of obligations under a production payment (net production); (iii) our associated revenue; (iv) the average realized prices received for our production; (v) our production cost; and (vi) our per unit production cost for the periods presented.
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(a) The average realized prices reported above include the non-cash effects of volumes delivered under the Production Payment as well as the unwinding of various derivative contracts terminated in 2001. These items do not generate cash to fund our operations. Excluding these items, the average realized price per Mcfe was $7.61, $5.85 and $5.05 in 2005, 2004 and 2003, respectively. For further information, please read "-- Major Influences on Results of Operations."
REVENUE
Natural Gas Revenue. In 2005, natural gas revenue increased $133.6 million, to $324.0 million, compared to $190.4 million in 2004 as a result of a 30% increase in production and a 31% increase in realized natural gas prices. The production increase was primarily due to our successful drilling program discussed above in "-- Overview."
Natural gas prices are influenced by several factors as discussed above in "-- Major Influences on Results of Operations."
In 2004, natural gas revenue increased $55.6 million, to $190.4 million, compared to $134.8 million in 2003 as a result of a 20% increase in production and a 17% increase in realized natural gas prices. The production increase was primarily due to our successful drilling program.
Oil and Liquids Revenue. In 2005, oil and liquids revenue increased $11.3 million to $39.7 million due to a 38% increase in average realized prices and a 1% increase in production.
In 2004, oil and liquids revenue increased $3.4 million to $28.4 million due to a 23% increase in average realized prices, partially offset by an 8% decrease in production. The decrease in oil and natural gas liquids production reflected the natural decline associated with our oil and natural gas liquids properties as our drilling program was focused primarily on natural gas prospects.
Other, net. In 2003, other, net was $5.0 million primarily related to the sale of emission reduction credits. Since that time, no significant transactions have occurred that affect other, net nor do we currently anticipate any significant sales of emission reduction credits or other transactions in the foreseeable future.
LEASE OPERATING EXPENSES
For the year ended December 31, 2005, lease operating expenses, or LOE, increased $6.8 million, to $35.4 million, compared to $28.6 million in 2004 due to generally higher service costs experienced industry-wide and the increase in the number of producing wells primarily as a result of our expanded drilling and acquisition programs. On a per unit of production basis, LOE was $0.70 per Mcfe in 2005 compared to $0.72 per Mcfe in 2004. The decrease in the per unit costs for 2005 as compared to 2004 reflect higher production rates and efficiencies realized in certain of our larger fields where significant production increases have been achieved.
For the year ended December 31, 2004, LOE increased $4.0 million, to $28.6 million, compared to $24.6 million in 2003 due to generally higher service costs experienced industry-wide and the increase in the number of producing wells as a result of our expanded drilling program. On a per unit of production basis, LOE was $0.72 per Mcfe in 2004 compared to $0.71 per Mcfe in 2003.
PRODUCTION AND OTHER TAXES
Production and other taxes increased $7.1 million, to $21.4 million in 2005, compared to $14.2 million in 2004. On per unit of production basis, 2005 production and other taxes were approximately $0.42 per Mcfe compared to $0.35 per Mcfe in 2004. The increase in 2005 reflects higher production taxes as a result of increased natural gas and oil production and prices and higher tax rates. Ad valorem taxes increased as a result of the increased value of our of our oil and gas properties and the significant increase in new wells drilled.
Production and other taxes increased $4.2 million, to $14.2 million in 2004, compared to $10.0 million in 2003. On a per unit of production basis, 2004 production and other taxes were approximately $0.35 per Mcfe compared to $0.29 per Mcfe in 2003. The increase was primarily attributable to increased production and oil and gas prices. Ad valorem taxes increased due to the higher value of our oil and gas properties.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administration expenses -- excluding stock compensation (G&A). G&A expenses increased $1.8 million to $11.1 million in 2005, compared to $9.3 million in 2004 primarily due to higher labor cost associated with an increase in our work force. On a per unit of production basis, G&A expense in 2005 was $0.22 per Mcfe compared to $0.23 per Mcfe in 2004, reflecting our continued emphasis on cost containment and increased oil and natural gas production.
G&A expense increased $0.9 million to $9.3 million in 2004, compared to $8.4 million in 2003 primarily due to increased costs to comply with corporate governance initiatives mandated by the Sarbanes-Oxley Act of 2002 and the New York Stock Exchange and higher insurance costs. On a per unit of production basis, G&A was $0.23 per Mcfe in 2004 and $0.24 per Mcfe in 2003.
Stock compensation. Through December 31, 2005, stock compensation reflected the non-cash expense associated with stock options issued in 2001 that were 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 was directly related to the movement in the market price of our common stock during that period. Stock compensation included in G & A expense was $2.4 million in 2005 ($1.1 million from variable stock options) compared to $2.6 million in 2004 ($1.6 million from variable stock options) and $2.7 million in 2003 ($1.9 million from variable stock options). Pursuant to SFAS 123R, which we adopted on January 1, 2006, variable accounting for our 2001 options is no longer applicable. Beginning January 1, 2006, we will expense the fair value of all stock-based compensation.
ACCRETION OF ASSET RETIREMENT OBLIGATION
Effective January 1, 2003, we adopted SFAS No. 143. Accretion of our asset retirement obligation was $1.0 million in each of 2005, 2004 and 2003.
DEPRECIATION, DEPLETION AND AMORTIZATION
We amortize our oil and gas properties using the unit of production, or UOP, method based on proved reserves. For the year ended December 31, 2005, depreciation, depletion and amortization expense, or DD&A, was $92.8 million ($1.85 per Mcfe) compared to $57.3 million ($1.43 per Mcfe) for the year ended December 31, 2004. This $35.5 million increase reflects higher natural gas and oil production and increased cost of our drilling and acquisition programs. The increased cost reflects, among other things, our decision to pursue certain projects (including our acquisition of oil and gas properties and related assets in our North Louisiana core operating area) with higher finding and development costs that provide attractive margins at current oil and gas prices.
For the year ended December 31, 2004, DD&A was $57.3 million ($1.43 per Mcfe) compared to $47.9 million ($1.38 per Mcfe) for the year ended December 31, 2003. This $9.4 million increase reflects the higher production associated with our successful drilling program and the increased cost of drilling wells.
LOSS ON MARK-TO-MARKET DERIVATIVES, NET
Losses on mark-to-market derivatives, net, which were previously reported as a component of other, net on our statements of consolidated income, are comprised of net realized and unrealized gains and losses on derivative contracts that do not qualify for hedge accounting treatment pursuant to SFAS No. 133 and the unrealized ineffective component of derivative contracts that do qualify for hedge accounting treatment.
In 2005, the net loss on mark-to-market derivatives was $9.7 million, of which $5.2 million was related to the unrealized ineffective component of our hedge derivative contracts and $4.5 million was attributable to the change in fair value of our derivative instruments that do not qualify for hedge accounting treatment. This compares to a net loss on mark-to-market derivatives of $1.1 million in 2004 and less than $0.1 million in 2003.
REDEMPTION PREMIUM ON EARLY EXTINGUISHMENT OF DEBT
On May 1, 2004, we redeemed our $125 million 8 7/8% senior subordinated notes due 2006. Pursuant to the indenture, we paid an early redemption premium of $3.7 million, which was charged against earnings in the second quarter of 2004.
INTEREST EXPENSE
Interest expense was $18.6 million in 2005 compared to $14.3 million in 2004. The increase in interest expense in 2005 compared to 2004 reflects higher average outstanding borrowings following the issuance of $100 million of 7 1/8% senior notes in April 2005.
Interest expense was $14.3 million in 2004 compared to $21.0 million in 2003. This significant decrease in interest expense in 2004 reflects reduced amounts of average outstanding debt and substantially lower borrowing costs.
INCOME TAXES
In 2005, we resumed recording book income taxes based on statutory rates following the reversal of the remainder of the valuation allowance against net deferred income tax assets at December 31, 2004. Please read Note 10 to our Consolidated Financial Statements. As a result, our federal and state income tax provision for 2005 was $66.7 million (38.7% of pre-tax income) compared to a $13.9 million income tax benefit in 2004. However, we continued to utilize our net operating loss carryforwards and paid only federal alternative minimum taxes and state taxes equating, in the aggregate, to approximately 2% of pre-tax income. The remainder of the tax expense recorded in 2005 is deferred to future years.
Income tax benefits were $13.9 million in 2004 compared to $20.2 million in 2003. These amounts reflect changes in our valuation allowance against net deferred income tax assets discussed in Note 10 to our Consolidated Financial Statements.
As of December 31, 2005, we had remaining net operating loss carryforwards of approximately $75 million to offset future taxable income.
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements are for the exploration, development and acquisition of oil and gas properties, operating expenses and debt service. Our initial budget for capital expenditures for 2006 is $315 million, which will be focused primarily on drilling at least 215 new wells, primarily in north Louisiana and south Texas. Although we intend to continue to pursue acquisitions in our core areas, acquisition capital is not included in the capital expenditure budget. We expect to fund our drilling activities primarily with internally generated cash flow and to have sufficient capital resources available to allow us the flexibility to be opportunistic with our drilling program and to fund larger acquisitions and working capital requirements. We believe this approach allows us to maintain an appropriate capital structure while increasing our oil and gas reserves and production.
Execution of this strategy in 2005 is reflected in our Statements of Consolidated Cash Flows. We invested $368 million in oil and gas properties, $247 million on our drilling program and $121 million on acquisitions. The drilling program was funded primarily with net cash provided by operating activities ($239.1 million) and our acquisitions were funded primarily with proceeds from borrowings ($116.1 million). With these resources and the relatively high oil and gas price environment in 2005, we continued our aggressive drilling program, drilling 193 wells with a 93% success rate and made important property acquisitions. As a result, we were able to significantly increase oil and gas production, reserves and cash flow.
In March 2005, we further strengthened our financial flexibility by amending our bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million and extend the maturity date to March 31, 2009. In connection with the amended facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of our oil and natural gas reserves and other factors, from $100 million to $185 million. As of December 31, 2005, we had $4.8 million of cash on hand and $166.7 million of unused committed borrowing capacity under our bank credit facility.
In April 2005, we completed a private placement of $100 million aggregate principal amount of 7 1/8% Senior Notes due 2012. The net proceeds from the private placement were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the Company's acquisition discussed in the following paragraph. The remainder of the net proceeds from the offering was used to repay approximately $16.0 million of outstanding borrowings under our bank credit facility.
On April 13, 2005, we completed an acquisition of oil and gas properties and related assets located primarily in our North Louisiana core operating area. Please read "-- Overview" for more information on the acquisition.
Our net working capital position at December 31, 2005 was a deficit of $46.9 million as compared to a deficit of $28.7 million at December 31, 2004. As of December 31, 2005, we had $4.8 million of cash and $166.7 million of
unused availability under our bank credit facility. Working capital deficits are not unusual in our industry. We, like many other oil and gas companies, typically maintain relatively low cash reserves and use any excess cash to fund our capital expenditure program or pay down borrowings under our bank credit facility.
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 budget and satisfy our short-term liquidity needs. In the future, we may also utilize various financing sources available to us, including the issuance of debt or equity securities under a shelf registration statement or through private placements to fund our long-term liquidity needs. Our ability to complete future debt 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 increased 78% in 2005 to $239.1 million compared to $134.1 million in 2004, primarily due to higher production, higher realized oil and natural gas prices and decreased delivery obligations under the Production Payment. The net increase in trade accounts receivable also reflects the higher natural gas and oil price environment in 2005 and the timing of cash receipts for sales of our increased production. The net change in accounts payable and accrued liabilities is primarily attributable to increased prices, drilling activities and production levels.
Net cash provided by operating activities for 2004 was $134.1 million compared to $71.0 million in 2003. The 89% improvement in our cash flow in 2004 was primarily due to higher production, higher realized oil and natural gas prices and decreased delivery obligations under the Production Payment. The net increase in trade accounts receivable also reflects the higher natural gas and oil price environment in 2004 and the timing of cash receipts for sales of our increased production. The net change in accounts payable and accrued liabilities is primarily attributable to the growth of our operations.
INVESTING ACTIVITIES
Net cash used in investing activities in 2005 was $359.2 million compared to net cash used in investing activities of $155.1 million in 2004 and $79.0 million in 2003. Substantially all the net cash used in investing activities for these years was invested in oil and gas properties. We sold several non-core properties in 2005 for a total of $11.2 million.
Capital expenditures for the year ended December 31, 2005 were $380.7 million, including $220.5 million used for development activities, $38.1 million used for lease acquisitions,seismic surveys and exploratory drilling, $121.3 million in property acquisitions and $0.8 million used for other assets. These amounts include costs that were incurred and accrued as of December 31, 2005 but are not reflected in the net cash used in investing activities above until payment is made in 2006.
Capital expenditures for the year ended December 31, 2004 were $167.2 million, including $132.1 million used for development activities, $34.1 million used for lease acquisitions,seismic surveys and exploratory drilling, $0.5 million in capitalized asset retirement obligation and $0.5 million used for other assets. These amounts include costs that were incurred and accrued as of December 31, 2004 but are not reflected in the net cash used in investing activities above until payment was made in 2005.
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 not reflected in the net cash used in investing activities above until payment was made in 2004.
FINANCING ACTIVITIES
Net cash provided by financing activities in 2005 was $118.2 due mainly from the proceeds of our senior note offering and, to a lesser extent, borrowings under our bank credit facility. Net cash provided by financing activities in 2004 was $25.4 million due to the refinancing of our debt as discussed in Note 6 to our Consolidated Financial Statements. Net cash provided by financing activities was $3.2 million in 2003 which was comprised of net proceeds from our common stock offering of $52.0 million, proceeds from borrowings under the bank credit facility of $69.3 million, repayments of debt of $114.1 million and net payments of financing costs and other of $4.0 million.
SHELF REGISTRATION STATEMENT
In September 2003, we, along with two of our operating subsidiaries, KCS Resources, Inc. and Medallion California Properties Company, filed a $200.0 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. As of December 31, 2005, there was $144.8 million remaining under our shelf registration statement. We may, in the future, replace this shelf registration statement with another shelf registration statement in accordance with the new rules created by the Securities Act Reform that became effective on December 1, 2005.
CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our future contractual cash obligations as of December 31, 2005 (in thousands).
The above table does not include the liability for dismantlement, abandonment and restoration cost of oil and gas properties. Please read Note 13 to our Consolidated Financial Statements for further discussion.
OTHER COMMERCIAL COMMITMENTS
As of December 31, 2005, we had $3.0 million of surety bonds that remain outstanding until specific events or projects are completed and any claims that may be made are settled.
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.
IMPACT OF INFLATION AND CHANGING PRICES
Our revenues, the value of our assets and our ability to obtain bank debt or additional capital on attractive terms have been and will continue to be affected by changes in oil and natural gas prices. Oil and natural gas prices
are subject to significant fluctuations that are beyond our control to predict. Certain of our costs and expenses are affected by general inflation and other cost increases are associated with material, equipment and service supply shortages.
OTHER MATTERS
Hurricanes Katrina and Rita struck the Gulf Coast region of the United States in August and September of 2005, respectively, causing widespread damage to the energy infrastructure in the region. The damage caused by the storms did not have a significant impact on our operations.
NEW ACCOUNTING PRINCIPLES
On January 1, 2006, we adopted Financial Accounting Standards Board, or FASB, Statement No. 123 (Revised 2004) "Share-Based Payment," or SFAS 123R, which is a revision of SFAS Statement No. 123, "Accounting for Stock-Based Compensation." SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Please read Note 1 to our Consolidated Financial Statements for further discussion.
ITEM 7A.
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." Please read "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 expect to continue to utilize, derivative contracts, including swaps, futures contracts, options and collars, each of which are discussed below, to manage this price risk. While these derivative contracts are structured to reduce our exposure to decreases in the price associated with the underlying commodity, they also 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. We typically have targeted hedging approximately 30% to 50% of our near-term production.
Commodity Price Swaps. Commodity price swap agreements require us to make payments to, or entitle us to 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.
Commodity Basis Swaps. Commodity basis swap agreements require the us to make payments to, or receive payments from, the counterparties based upon the differential between certain pricing indices and a stated differential amount.
As of December 31, 2005, we had derivative instruments outstanding covering 19.5 million MMBtu of 2006 natural gas production, 2.3 million MMBtu of 2007 natural gas production, 0.3 million barrels of 2006 oil production and less than 0.1 million barrels of 2007 oil production, with a negative fair value of $55.7 million.
As of December 31, 2004, we had derivative instruments outstanding covering 8.6 million MMBtu of 2005 natural gas production, 1.4 million MMBtu of 2006 natural gas production and 0.2 million barrels of 2005 oil production, with a fair market value of $1.3 million. In addition, we had commodity basis swaps outstanding covering 0.5 million MMBtu.
The following table sets forth information with respect to our oil and natural gas hedged position as of December 31, 2005. There were no derivative instruments outstanding beyond 2007.
During 2005, we delivered approximately 8% of our production under the Production Payment, under which final deliveries were made in January 2006, and entered into derivative arrangements at various times designed to reduce price downside risk for approximately 44% of our production. During 2004, we delivered approximately 13% of our production under the Production Payment and entered into derivative arrangements at various times for approximately 46% of our production.
Please read Note 11 to our Consolidated Financial Statements for more information regarding our derivatives.
INTEREST RATE RISK
We use fixed and variable rate long-term debt to finance our capital spending program and for general corporate purposes. Our bank credit facility exposes us to market risk related to changes in interest rates, specifically LIBOR and Prime Rate. Our fixed rate debt and the associated weighted average interest rate was $275.0 million at 7 1/8% as of December 31, 2005 and $175.0 million at 7 1/8% as of December 31, 2004. Our variable rate debt and weighted average interest rate was $15.5 million at 7 1/4% on December 31, 2005. We did not have any outstanding variable rate debt as of December 31, 2004.
The tables below present principal payment requirements and related average interest rates by expected maturity date for our debt obligations as of December 31, 2005 and 2004 (dollars in millions).
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of KCS Energy, Inc., including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a- 15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, for KCS Energy, Inc. and subsidiaries (KCS). Our internal control system was designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and fair presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Management conducted an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this assessment. Through this assessment, we did not identify any material weaknesses in our internal control over financial reporting. There are inherent limitations in the effectiveness of any system of internal control over financial reporting; however, based on our assessment, we have concluded that our internal control over financial reporting was effective as of December 31, 2005 based on the aforementioned criteria.
Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report on management's assessment of KCS' internal control over financial reporting, which is included on the following page of this report.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of KCS Energy, Inc.:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that KCS Energy, Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). KCS Energy, Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that KCS Energy, Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, KCS Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of KCS Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders' equity (deficit), and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 14, 2006 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
Houston, Texas March 14, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2005 and 2004, and the related consolidated statements of income, stockholders' equity (deficit), and cash flows for each of the three years in the period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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, 2005 and 2004 and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As described in Note 2, 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.
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of KCS Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2006 expressed an unqualified opinion thereon.
/S/ ERNST & YOUNG LLP
Houston, Texas March 14, 2006
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
The accompanying notes are an integral part of these financial statements.
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these financial statements.
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (DEFICIT)
The accompanying notes are an integral part of these financial statements.
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
The accompanying notes are an integral part of these financial statements.
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 predominantly 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 (collectively "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.
The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards ("SFAS") 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. In addition, any net gain or loss from hedges terminated prior to maturity continues to be deferred until the hedged production is produced and sold. Once the hedged volumes are produced and sold, the realized hedge gain or loss associated with derivatives that qualify for hedge accounting treatment is included as a component of oil and natural gas revenue in the Statements of Consolidated Income. 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 recognized currently in earnings. 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. If it becomes probable that the hedged transaction will not occur, the derivative gain or loss
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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 earnings. Net gains or losses on derivatives that have not been designated as hedges or otherwise do not qualify for hedge accounting treatment and unrealized hedge ineffectiveness are reported as "Loss on mark-to-market derivatives, net" on the Statements of Consolidated Income.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of certain financial instruments, including cash and cash equivalents approximates estimated fair value due to their short-term maturities. The estimated carrying value the debt outstanding under the bank credit facility approximates estimated fair value due to its variable interest rates. The estimated fair value of the 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 compensation, 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. The Company provides for depreciation, depletion and amortization, or DD&A, of evaluated costs using the unit-of-production method based on proved reserves, including reserves associated with the Production Payment. The Company includes the estimated amount of asset retirement obligations that will be incurred in connection with future development activity on proved reserves in the costs to be amortized. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the DD&A 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 $40.6 million and $11.2 million as of December 31, 2005 and 2004, respectively. The Company amortizes these costs once proved reserves are established or impairment is determined.
The Company performs quarterly "ceiling test" calculations as capitalized costs of oil and gas properties, net of accumulated DD&A 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.
Proceeds from dispositions of oil and gas properties are credited to the cost center with no recognition of gains or losses unless such adjustments would significantly alter the relationship between capital costs and proved reserves.
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
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Company follows the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold. The volume of natural gas volumes 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. Under the sales method, no receivables are recorded where the Company has taken less than its share of production.
In February, 2001 the Company 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. The Company recorded the net proceeds from the sale of the Production Payment as deferred revenue on the balance sheet. 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 discounted 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 2005, the Company delivered 3.9 Bcfe under this Production Payment and recorded $16.1 million of oil and natural gas revenue. During 2004, the Company delivered 5.2 Bcfe under the Production Payment and recorded $21.4 million of oil and gas revenue. During 2003, the Company delivered 6.8 Bcfe under the Production Payment and recorded $27.9 million of oil and gas revenue. Final deliveries of 0.3 Bcfe were made in January 2006.
In 2005, two customers, Louis Dreyfus Corporation and its affiliates and Regency Gas Services, LP (formerly Regency Gas Services LLC), accounted for 26% and 13%, respectively, of the Company's consolidated revenue. In 2004, one customer, Louis Dreyfus Corporation and its affiliates, accounted for 19% of consolidated revenue. Other than the amortization of deferred revenue associated with the Production Payment sold in 2001, no other customer accounted for more than 10% of the Company's consolidated revenue in 2005, 2004 or 2003.
STOCK COMPENSATION
Through December 31, 2005, as permitted by Financial Accounting Standards Board, or FASB, Statement No. 123, "Accounting for Stock-Based Compensation", or SFAS 123, the Company accounted for share-based payments to employees using the intrinsic value provisions of Accounting Principles Board, or APB, Opinion No. 25 "Accounting for Stock Issued to Employees." As such, the Company generally did not recognize compensation cost for employee stock options. Certain stock options issued in 2001, however, were subject to variable accounting in accordance with FASB 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. In addition, the Company recognizes non-cash stock compensation expense for the amortization of its non-vested shares.
Stock compensation, which is included as a component of general and administrative expenses on the statements of consolidated income, was $2.4 million in 2005 ($1.1 million from variable stock options) compared to $2.6 million in 2004 ($1.6 million from variable stock options) and $2.7 million in 2003 ($1.9 million from variable stock options).
ADOPTION OF SFAS 123R
On January 1, 2006, the effective date, the Company adopted FASB Statement No. 123 (Revised 2004) "Share-Based Payment", or SFAS 123R, which is a revision of SFAS 123. SFAS 123R supersedes APB Opinion No. 25 and amends FASB Statement No. 95, "Statement of Cash Flows".
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Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.
The Company adopted the provisions of 123R using the modified prospective method whereby compensation cost is recognized beginning with the effective date; (a) for all share-based payment awards granted after the effective date; and (b) for the unvested portion of share-based payment awards granted prior to the effective date.
The impact of adoption of SFAS 123R cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had the Company adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the disclosure of pro forma net income and earnings per share in the table below.
SFAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as previously required, thereby reducing cash flows from operating activities and increasing cash flows from financing activities in periods after adoption. SFAS 123R also requires the Company to estimate forfeitures, which will result in an immaterial cumulative effect of change in accounting principle upon adoption.
Finally, upon adoption of SFAS 123R, variable accounting will no longer be applicable to the 2001 options. Accordingly, no future compensation expense will be recognized with respect to the 2001 options.
The following table illustrates the effect on income available to common stockholders and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123, as amended.
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 $4.5 million as of December 31, 2005 and $4.9 million as of December 31, 2004. Included in the allowance is $3.7 million that represents a 79% reserve against receivables from various Enron entities currently in bankruptcy. The Company currently believes that the remaining $1.0 million receivable from such entities will
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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.
COMMON STOCK OUTSTANDING
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.
2. SIGNIFICANT ACQUISITION OF OIL AND GAS PROPERTIES
On April 13, 2005, the Company completed an acquisition of oil and gas properties and related assets located primarily in the Company's North Louisiana core operating area for $86.9 million, of which approximately $64 million was allocated to proved properties and the remainder allocated to unproven properties. The acquisition included net proved reserves initially estimated at approximately 47 Bcfe, of which approximately two-thirds were undeveloped, associated with 137 producing wells and 81 proved undeveloped drilling locations and additional acreage with an estimated 185 drilling locations for which no proved reserves were assigned. The acquisition was primarily financed with proceeds from issuance of the Additional Notes as described in Note 6 to the Consolidated Financial Statements.
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The following table reflects the Company's unaudited pro forma revenue, net income and earnings per share as if the acquisition had taken place at the beginning of fiscal 2005 and 2004. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.
3. EARNINGS PER SHARE
Basic earnings per share of common stock is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings 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:
4. 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
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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 $764,613 in 2005, $633,818 in 2004, and $524,419 in 2003.
5. STOCK OPTION AND INCENTIVE PLANS
In June 2005, the stockholders of the Company approved the KCS Energy, Inc. 2005 Employee and Directors Stock Plan, or 2005 Stock Plan. The purpose of the 2005 Stock Plan is to promote the long-term success of the Company by providing financial incentives to employees and non-employee directors of the Company who are in a position to make significant contributions toward such success. The 2005 Stock Plan is designed to attract and retain talented employees, further align employee and stockholder interests, continue to closely link employee compensation with company performance, and maintain a culture based on employee stock ownership. The 2005 Stock Plan provides that stock options, stock appreciation rights, restricted stock and bonus stock may be granted to employees of the Company. The 2005 Stock Plan also provides that stock options and retainer stock may be granted to non-employee directors. The 2005 Stock Plan provides that the option price of shares issued be equal to the market price on the date of grant. All options vest ratably on the anniversary of the date of grant over a period of time, typically three years. All options expire ten years after the date of grant.
The 2005 Stock Plan replaced the KCS Energy, Inc. 2001 Employees and Directors Stock Plan, or 2001 Stock Plan. Upon adoption of the 2005 Stock Plan, no additional options or other awards were or will be granted under the 2001 Stock Plan. The 2001 Stock Plan provided that stock options, stock appreciation rights, restricted stock and bonus stock may be granted to employees of the Company. The 2001 Stock Plan also provided that stock options and retainer stock may be granted to non-employee directors. The 2001 Stock Plan provided 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 vested immediately. All other options vested ratably on the anniversary of the date of grant over a period of time, typically three years. All options expire ten years after the date of grant.
Restricted shares awarded under the 2005 Stock Plan and the 2001 Stock Plan typically 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 accelerated vesting 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. Restricted stock grants were 169,364 shares in 2005, 162,874 shares in 2004 and 282,604 shares in 2003. The fair value 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, 2005, there were 365,855 outstanding shares of restricted stock with a weighted average fair value on the date of grant of $10.53 per share.
As of December 31, 2005, a total of 3,656,790 shares were available for future grants under the 2005 Stock Plan.
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A summary of the status of the stock options under the 2005 Stock Plan and the 2001 Stock Plan as of December 31, 2005, 2004, and 2003 and changes during the years then ended is presented in the following table. 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 2005: (1) risk-free interest rate of 4.03%; (2) expected dividend yield of 0.00%; (3) expected life of 7.9 years; and (4) expected stock price volatility of 78.4%. The weighted average assumptions used for grants in 2004 were: (1) risk-free interest rate of 4.47%; (2) expected dividend yield of 0.00%; (3) expected life of 10 years; and (4) expected stock price volatility of 90.7%. The weighted average assumptions used for grants in 2003 were: (1) risk-free interest rate of 3.67%; (2) expected dividend yield of 0.00%; (3) expected life of ten years; and (4) expected stock price volatility of 88.6%.
The following table summarizes information about stock options outstanding as of December 31, 2005.
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 4,150 shares, 2,525 shares and 19,394 shares during 2005, 2004 and 2003, respectively. As of December 31, 2005, there were 749,920 shares available for issuance under the Program.
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6. DEBT
The following table sets forth information regarding the Company's outstanding debt.
Bank Credit Facility. In March 2005, the Company amended its bank credit facility to, among other things, increase the maximum commitment amount from $100 million to $250 million and extend the maturity date to March 31, 2009. In connection with the amended bank credit facility, the lenders increased the borrowing base, which is redetermined semi-annually and may be adjusted based on the lenders' valuation of the Company's oil and natural gas reserves and other factors, from $100 million to $185 million. The borrowing base is automatically reduced by an amount equal to a specified percentage of the net proceeds from the issuance of any additional indebtedness, as defined, that is not applied to refinance existing public indebtedness.
Effective December 1, 2004, borrowings under the bank credit facility bear interest, at the Company's option, at an interest rate of LIBOR plus 1.75% to 2.5% or the greater of (1) the Federal Funds Rate plus 0.5% or (2) the Base Rate, plus 0.0% to 0.75%, depending on utilization. The LIBOR and Base Rate margins will decrease by 0.5%, but not to less than 0.0%, after the final deliveries are made in connection with the Production Payment (January 31, 2006) and the lien on the subject property is released. Also effective December 1, 2004, a commitment fee of 0.35% to 0.5% per year, depending on utilization, is paid on the unused availability under the bank credit facility. From November 18, 2003 through November 30, 2004, the applicable margin for LIBOR rate loans was 2.25% to 3.0%, the applicable margin for base rate loans was 0.5% to 1.25%, depending on utilization, and the commitment fee was 0.5% per year on the unused availability under the bank credit facility.
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 prohibitions on a change of control, prohibitions on the payment of cash dividends, acceleration upon the occurrence of an event of default, restrictions on certain other distributions and restricted payments, and limitations on the incurrence of additional debt and the sale of assets.
Substantially all of the Company's assets, including the stock of all of its subsidiaries, are pledged to secure the bank credit facility. Further, each of the Company's subsidiaries has guaranteed the obligations under the bank credit facility.
As of December 31, 2005, $15.5 million was outstanding under the bank credit facility and $166.7 million of unused borrowing capacity was available for future financing needs. The Company was in compliance with all covenants under the bank credit facility as of that date.
Senior Notes. In April 2004, the Company issued $175 million of 7 1/8% senior notes due April 1, 2012 (the "Original Notes"). The Company received $171.1 million in net proceeds from the issuance of the Original Notes. Net proceeds of the issuance were used to redeem the aggregate principal amount of the Company's $125 million 8 7/8% senior subordinated notes due 2006 (the "Senior Subordinated Notes"), together with an early redemption premium of $3.7 million, to repay the $22 million outstanding under the Company's bank credit facility, and for general corporate purposes.
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The Senior Subordinated Notes were redeemed on May 1, 2004 and the early redemption premium of $3.7 million was charged against earnings. In addition, the Company incurred an additional $0.9 million of interest expense as both the Senior Subordinated Notes and the Original Notes were outstanding during the month of April 2004.
In April 2005, the Company consummated a private placement of $100 million aggregate principal amount of 7 1/8% senior notes due 2012 (the "Additional Notes"). In connection therewith, the Company entered into a supplemental indenture that amended the indenture governing the Original Notes so that the Original Notes together with the Additional Notes would form a single class of securities (the "Senior Notes"). All other material terms of the original indenture remain the same. The Additional Notes were issued at 100.625% of the face amount. The net proceeds from the issuance of the Additional Notes were approximately $98.2 million after deducting expenses of the offering. Approximately $82.2 million of the net proceeds, along with approximately $4.7 million paid as a deposit in February 2005, was used to finance the Company's acquisition of oil and gas properties and related assets located primarily in the Company's North Louisiana core operating area. The remainder of the net proceeds from the issuance of the Additional Notes was used to repay approximately $16.0 million of outstanding borrowings under the bank credit facility.
The Senior Notes bear interest at a rate of 7 1/8% per annum with interest payable semi-annually on April 1 and October 1. The Company may redeem the Senior Notes at its option, in whole or in part, at any time on or after April 1, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 3.563% in 2008 to 0% in 2010 and thereafter. In addition, at any time prior to April 1, 2007, the Company may redeem up to a maximum of 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of one or more equity offerings at a price equal to 107.125% of the principal amount, plus accrued and unpaid interest. The Senior Notes are senior unsecured obligations and rank subordinate in right of payment to all existing and future secured debt, including secured debt under the Company's bank credit facility, and will rank equal in right of payment to all existing and future senior indebtedness.
The Senior Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of the Company's current subsidiaries. KCS Energy, Inc., the issuer of the Senior Notes, has no independent assets or operations apart from the assets and operations of its subsidiaries.
The indenture governing the Senior Notes contains covenants that, among other things, restrict or limit the ability of the Company and the subsidiary guarantors to: (i) borrow money; (ii) pay dividends on stock; (iii) purchase or redeem stock or subordinated indebtedness; (iv) make investments; (v) create liens; (vi) enter into transactions with affiliates; (vii) sell assets; and (viii) merge with or into other companies or transfer all or substantially all of the Company's assets.
In addition, upon the occurrence of a change of control (as defined in the indenture governing the Senior Notes), the holders of the Senior Notes will have the right to require the Company to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest, if any.
OTHER INFORMATION
The estimated fair value of the Company's Senior Notes was $275.0 million based on quoted market values at December 28, 2005. The estimated fair value of the Company's Senior Notes was $184.2 million based on quoted market values at December 31, 2004.
Total interest payments were $16.8 million in 2005, $15.3 million in 2004 and $18.6 million in 2003. Capitalized interest was $1.7 million in 2005, $0.6 million in 2004 and $0.4 million in 2003.
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7. 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) $5.1 million in 2006; (2) $3.9 million in 2007; and (3) $0.5 million after 2007. Lease payments charged to operating expenses amounted to $2.8 million, $2.0 million and $1.7 million during 2005, 2004 and 2003, respectively. In addition, the Company has unconditional purchase obligations, primarily related to natural gas transportation and drilling contracts, of $17.6 million in 2006, $16.0 million in 2007 and $2.6 million in 2008.
8. LITIGATION
The Company is party to various lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of these proceedings 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.
9. QUARTERLY FINANCIAL DATA (UNAUDITED)
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.
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10. INCOME TAXES
Federal and state income tax provision (benefit) includes the following components:
The primary differences giving rise to the Company's net deferred tax assets are as follows:
Federal alternative minimum tax payments, or AMT, of $1.3 million, $1.0 million and $0.7 million were made in 2005, 2004 and 2003, respectively. State income tax payments were $0.8 million in 2005. There were no state income tax payments in 2004 or 2003.
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The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements. 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 its estimate 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 company's oil and gas 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.
At December 31, 2002, the Company had established a valuation allowance against the full amount of its net deferred income tax assets as a result of uncertainty that the tax asset would ultimately be realized. Since that time, the Company generated significant levels of taxable income due to drilling success and strong natural gas and oil prices. As a result of the Company's assessment of the outlook for continued generation of taxable income, $37.6 million of the valuation allowance was reversed in 2003 and the remaining $44.2 million was reversed in 2004. These amounts are reflected as income tax benefits in the statements of consolidated income. In 2005, the Company resumed recording income tax expense based on statutory rates. However, the Company continued to utilize its net operating loss carryforwards and paid only AMT and state income taxes as discussed above.
As of December 31, 2005, we had remaining net operating loss carryforwards of approximately $75 million to offset future taxable income. The net operating loss carryforwards have remaining lives ranging from 14 to 17 years.
11. 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 payments to, or entitle it to 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 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.
Commodity Basis Swaps. Commodity basis swap agreements require the Company to make payments to, or receive payments from, the counter parties based upon the differential between certain pricing indices and a stated differential amount.
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As of December 31, 2005, the Company had derivative instruments outstanding covering 19.5 million MMBtu of 2006 natural gas production, 2.3 million MMBtu of 2007 natural gas production, 0.3 million barrels of 2006 oil production and less than 0.1 million barrels of 2007 oil production. The following table sets forth the Company's oil and natural gas hedged position as of December 31, 2005.
The fair value of the Company's derivative instruments are reflected as assets or liabilities in the Company's financial statements as presented in the following table.
During 2005, the Company delivered approximately 8% of its production under the Production Payment, with final deliveries made in January 2006. During 2005, the Company also entered into derivative arrangements at various times designed to reduce price downside risk for approximately 44% of its production. During 2004, the Company delivered approximately 13% of its production under the Production Payment and entered into derivative arrangements at various times for approximately 46% of its production. During 2003, the Company delivered
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
approximately 20% of its production under the Production Payment and entered into derivative arrangements at various times for approximately 16% of its production.
The Company realized $42.6 million in net hedging losses in 2005, $8.6 million in 2004 and $6.2 million in 2003. These amounts were reflected as a reduction of oil and natural gas revenue on the statements of consolidated income. In addition, the Company recorded losses of $9.7 million in 2005 and $1.1 million in 2004 which are reflected as "Loss on mark-to-market derivatives, net" on the statements of consolidated income. These amounts are comprised of net realized and unrealized losses on derivative contracts not subject to hedge accounting treatment pursuant to SFAS No. 133 and the unrealized ineffective component of derivative contracts that do qualify for hedge accounting treatment. The $9.7 million loss in 2005 includes $5.2 million related to the unrealized ineffective component of hedge derivative contracts and $4.5 million associated with derivatives that do not qualify for hedge accounting treatment.
As of December 31 2005, the Company had approximately $28.9 million of derivative losses, net of tax, recorded in Accumulated Other Comprehensive Income (Loss) ("AOCI"), of which $24.9 million are related to derivatives that are expected to mature during 2006. The following table details the AOCI activity related to commodity derivatives on both a pre-tax and after-tax basis during 2005 and 2004.
12. OIL AND NATURAL GAS PRODUCING OPERATIONS (UNAUDITED)
The following data is presented pursuant to SFAS No. 69 "Disclosures 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, 2005 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 $10.08, $6.18 and $5.97 per MMBtu, adjusted by lease for Btu content, transportation fees and regional price differentials as of December 31, 2005, 2004 and 2003, respectively. Oil prices were based on West Texas Intermediate, or WTI, posted prices of $57.75, $40.25 and $29.25 as of December 31, 2005, 2004 and 2003, respectively, adjusted by lease for gravity, transportation fees and regional price differentials. Hedge-adjusted prices are not considered for purposes of calculating future cash inflows.
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
CAPITALIZED COSTS (UNAUDITED)
Information with respect to capitalized costs related to oil and natural gas producing activities are set forth in the following table.
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(1) Includes $36.0 million, $3.6 million and $1.0 million incurred in 2005, 2004 and 2003, respectively.
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.
DISCOUNTED FUTURE NET REVENUES RELATING TO PROVED OIL AND GAS RESERVES
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
CHANGES IN DISCOUNTED FUTURE NET REVENUES FROM PROVED RESERVE QUANTITIES
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(a) Includes the cash outflows associated with asset retirement obligations.
(b) Excludes $16,149, $21,370 and $27,886 of deferred revenue at December 31, 2005, 2004 and 2003, respectively, related to the production payment.
RESERVE INFORMATION (UNAUDITED)
The reserve estimates and associated revenues for the years ended December 31, 2005, 2004 and 2003 were prepared by the Company and audited by Netherland, Sewell & Associates, Inc., or NSAI. Proved oil and gas reserves are estimated by the Company in accordance with the Securities and Exchange Commission's definitions in Rule 4-10(a) of Regulation S-X. These definitions can be found on the SEC webite at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas. All of the Company's reserves are located within the United States.
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
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(a) Excludes volumes produced and delivered with respect to the Production Payment for which reserves were removed at the time the Production Payment was sold in February 2001..
Approximately 26% of the Company's reserves as of December 31, 2005 were classified as proved undeveloped. Furthermore, approximately 17% 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 at December 31, 2005, or zones that have been produced in the past but are not currently producing due to mechanical reasons. These reserves may be regarded as less certain than producing reserves.
13. ASSET RETIREMENT OBLIGATIONS
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. Included in other assets at December 31, 2005 is $2.8 million held in escrow accounts related to certain asset retirement obligations.
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
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, 2005:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
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 (including our consolidated subsidiaries) 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.
Management's annual report on internal control over financial reporting. Management's annual report on internal control over financial reporting and the attestation report of our independent registered public accounting firm are included under "Financial Statements and Supplementary Data" included elsewhere in this annual report on Form 10-K, and such reports are incorporated herein by reference.
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.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information concerning our executive officers and directors is set forth in the sections entitled "Election of Directors" and "Executive Officers" of our Proxy Statement for the 2006 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 2006 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 2006 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 and a Code of Business Conduct and Ethics applicable to our directors, officers and employees. The Code of Ethics and the Code of Business Conduct and Ethics are available on the Investor Relations section of our Internet website at www.kcsenergy.com. If we amend the Code of Ethics or the Code of Business Conduct and Ethics or grant a waiver, including an implicit waiver, from the Code of Ethics or the Code of Business Conduct and Ethics, we intend to disclose this information on our Internet website within four business days of such amendment or waiver.
As required by New York Stock Exchange, or NYSE, listing standards, James W. Christmas, our Chief Executive Officer, certified on June 23, 2005 that he was not aware of any violation by KCS of NYSE corporate governance listing standards. The certifications required by Section 302 of the Sarbanes-Oxley Act were filed with the Securities and Exchange Commission on March 16, 2006 as exhibits 31.1 and 31.2 to KCS' Annual Report on Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information for this item is set forth in the sections entitled "Executive Compensation," "Compensation Committee Interlocks and Insider Participation," "Employment Agreements and Change-in-Control Agreements," and "Compensation of Directors" in our Proxy Statement for the 2006 Annual Meeting of Stockholders, which sections are incorporated in this annual report on Form 10-K by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
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 2006 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.
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 2006 Annual Meeting of Stockholders, which section is incorporated in this annual report on Form 10-K by reference.
ITEM 14.
ITEM 14. PRINCIPLE ACCOUNTING FEES AND SERVICES.
Information for this item is set forth in the section entitled "Independent Registered Public Accounting Firm" in our Proxy Statement for the 2006 Annual Meeting of Stockholders, which section is incorporated in this annual report on Form 10-K by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) List of documents filed as part of the report:
(1) Financial Statements. The following consolidated financial statements and the related Report of Independent Registered Accounting Firm are presented in Part II, Item 8 of this annual report on Form 10-K on the pages indicated below.
(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 consolidated financial statements and related notes.
(3) Exhibits.
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* Management contract or compensatory plan or arrangement.
# Pursuant to Item 601(b)(2) of Regulation S-K, KCS Energy, Inc. agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.
+ Filed herewith.
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.
By: /s/ FREDERICK DWYER ------------------------------------ Frederick Dwyer Vice President, Controller and Secretary
Date: March 16, 2006
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.
EXHIBIT INDEX
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* Management contract or compensatory plan or arrangement.
# Pursuant to Item 601 (b)(2) of Regulation S-K, KCS Energy, Inc. agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.
+ Filed herewith.