shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
the results of exploration efforts and the acquisition, review and analysis of the seismic data;
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
our financial resources and results; and
the availability of leases and permits on reasonable terms for the prospects.
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.
High demand for field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our natural gas and oil properties.
Due to current industry demands, well service providers and related equipment and personnel are in short supply. This may cause escalating prices, delays in drilling and other exploration activities, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures would likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the over use of equipment and inexperienced personnel.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the threefour regions in which we operate. The estimation of reserves for certain properties sold
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Index to Financial Statements
in 2006 as well as a small number of properties currently held in the Gulf Coast region requires more estimates than in Canada and the East and West regions and inherently has more uncertainty surrounding reserve estimation. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgment of the persons preparing the estimate.
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original
estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.
We are continually identifyingFrom time to time, we may identify and evaluatingevaluate opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.
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Index to Financial Statements
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
blowouts, cratering and explosions;
mechanical problems;
uncontrolled flows of natural gas, oil or well fluids;
fires;
formations with abnormal pressures;
pollution and other environmental risks; and
natural disasters.
In addition, we conduct operations in shallow offshore areas (largely coastal waters), which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, impairment of our operations and substantial losses to us.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2005,2006, we owned or operated approximately 3,4002,900 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.
In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. 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 with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. 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 materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
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Index to Financial Statements
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours, particularly in the Rocky Mountains, Mid-Continent, Canada and Gulf Coast areas. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.
From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 20052006 we primarily employed natural gas and crude oil price swap and collar agreements to attempt to manage price risk. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place. The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. In addition, we employed natural gas and crude oil price swap agreements during 2005. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place.
These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
a counterparty is unable to satisfy its obligations;
production is less than expected; or
there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities
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Index to Financial Statements
integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.
Our bylaws provide for a classified board of directors with staggered terms, and our charter authorizes our board of directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and limit stockholder proposals at meetings of stockholders. We also have adopted a stockholder rights plan. Because of our stockholder rights plan and these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.
The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our certificate of incorporation.
The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our certificate of incorporation limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liabilityliability:
for any breach of their duty of loyalty to the company or our stockholders;
for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and
for any transaction from which the director derived an improper personal benefit.
This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.
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Index to Financial Statements
ITEM 1B. UNRESOLVED STAFF COMMENTS
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 2. | PROPERTIES |
See Item 1. Business.
| ITEM 3. | LEGAL PROCEEDINGS |
We are a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Wyoming Royalty Litigation
In January 2002, we were sued by 13 overriding royalty owners in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to us, the case was settled in September 2005 with no payment from us and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. In the third quarter of 2005, management reversed the reserve we had recorded regarding this case, which did not have a material impact on our consolidated financial statements.
West Virginia Royalty Litigation
In December 2001, we were sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that we failed to pay royalty based upon the wholesale market value of the gas, that we had taken improper deductions from the royalty and that we failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.
Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of athe case involving an unrelated party pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses.described below. We intend to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.
The West Virginia Supreme Court of Appeals issued a decision in 2006 in a case against another producer (the Tawney case) that raised some of the same issues as are raised in our case. This recent decision may negatively impact some of the defenses we have raised in our litigation with respect to the issue of deductibility of post-production expenses under certain leases, but we believe that in a significant number of leases we have lease language, factual distinctions and defenses that are not implicated by the ruling.
The Tawney case involves claims concerning the deductibility of post-production expenses and the failure to properly inform, issues shared with our case, but also involves additional claims not raised in our case. The most significant additional claims are related to sales under long-term, fixed-price agreements at prices considered significantly below market value, as well as claims for certain volume reductions and unmetered production. The Tawney case went to trial in January 2007, and the jury returned a verdict against the producer for $130 million in compensatory damages and $270 million in punitive damages. Judgment has not yet been entered in the Tawney case, and an appeal is expected. We are closely monitoring developments in the Tawney case, and we continue to investigate how this recent ruling may impact our defense of our case. The case against us has been re-activated to the docket and trial is set for August 13, 2007.
We are vigorously defending the case. We haveA reserve has been established a reserve that management believes is adequate based on theirits estimate of the probable outcome of this case.
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Index to Financial Statements
Texas Title Litigation
On January 6, 2003, we were served with Plaintiffs’Plaintiffs' Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs filed their Third Amended Original Petition on February 21, 2006, which incorporated all prior supplemental petitions. Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, our subsidiary, acquired certain leases and wells in 1997 and 1998.
The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which we acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass and conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties arewere allowed to amend pleadings or add additional parties to the litigation. DuePlaintiffs did not join additional parties by the abatement deadline. Defendants, including us, re-urged our motion to dismiss, and on April 5, 2006, the Court granted the motion, dismissing the oil company defendants, without prejudice. Because all defendants were not dismissed at that time, the order dismissing us was not then final. A motion to finalize the proceedings in the trial court via severance of the dismissed defendants was filed April 25, 2006, and the remaining defendants moved to join the motions that led to the abatementdismissal of us. In 2006, the case, weCourt dismissed the claims. Plaintiffs have
not had the opportunity to conduct discovery in this matter. We estimate that production revenue from this field since Cody Energy, LLC acquired title is approximately $15.7 million, and that the carrying value filed a Notice of this property is approximately $33.6 million.
Appeal. Although the investigation into this claim continues, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the propertyrecord is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, wenot yet complete and, therefore, specific appellate deadlines have not established a reserve for this matter.been set, we expect that, following briefing and oral argument, the appellate court will issue its decision by the end of 2007 or early 2008.
Raymondville Area
In April 2004, our wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of itsour co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Codywe had proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.
The working interest owners who elected not to participate notified Codyus that they believed that they had the right to participate in wells drilled after the initial well. Cody contendsWe contend that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. The defendants have filed a counter claim against the Company,us, and one of the defendants has filed a lien against Cody’sour interest in the leases in the Raymondville area.Area.
Cody hasWe have signed a settlement agreement with certain of the defendants representing approximately 3%three percent of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’sour Motion for Summary Judgment requiring the remaining defendant to assign to Codyus all of its interest in the prospect and to remove the lien filed against Cody’sour interest.
On July 12, 2006, we entered into a Purchase and Sale Agreement to acquire all of the defendant’s interest in the Raymondville Field. The agreement would make the summary judgment ruling by the trial judge a final order, dismiss, with prejudice, all pending counter claims filed by such defendant and remove the lien against our properties filed by such defendant. We completed the acquisition in the third quarter of 2006. The lien has filedbeen removed, the summary judgment has become a Motion for Reconsiderationfinal order and Oppositionall of the defendant’s claims have been dismissed.
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Index to Proposed Order. The Court has not yet made a decision on these two motions.Financial Statements
Commitment and Contingency Reserves
We have established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur approximately $10.2$9.1 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
| ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
No matters were submitted to a vote of security holders during the fourth quarter of 2005.2006.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information as of February 16, 2007 about our executive officers, as of February 17, 2006, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
Name | Age | Position | Officer Since | Age | Position | Officer Since | ||||||
Dan O. Dinges | 52 | Chairman, President and Chief Executive Officer | 2001 | 53 | Chairman, President and Chief Executive Officer | 2001 | ||||||
Michael B. Walen | 57 | Senior Vice President, Exploration and Production | 1998 | 58 | Senior Vice President, Chief Operating Officer | 1998 | ||||||
Scott C. Schroeder | 43 | Vice President and Chief Financial Officer | 1997 | 44 | Vice President and Chief Financial Officer | 1997 | ||||||
J. Scott Arnold | 52 | Vice President, Land and Associate General Counsel | 1998 | 53 | Vice President, Land and Associate General Counsel | 1998 | ||||||
Robert G. Drake | 58 | Vice President, Information Services and Operational Accounting | 1998 | 59 | Vice President, Information Services and Operational Accounting | 1998 | ||||||
Abraham D. Garza | 59 | Vice President, Human Resources | 1998 | 60 | Vice President, Human Resources | 1998 | ||||||
Jeffrey W. Hutton | 50 | Vice President, Marketing | 1995 | 51 | Vice President, Marketing | 1995 | ||||||
Thomas S. Liberatore | 49 | Vice President, Regional Manager, East Region | 2003 | 50 | Vice President, Regional Manager, East Region | 2003 | ||||||
Lisa A. Machesney | 50 | Vice President, Managing Counsel and Corporate Secretary | 1995 | 51 | Vice President, Managing Counsel and Corporate Secretary | 1995 | ||||||
Henry C. Smyth | 59 | Vice President, Controller and Treasurer | 1998 | 60 | Vice President, Controller and Treasurer | 1998 |
All officers are elected annually by our Board of Directors. Except for the following, allAll of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.
Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief Operating Officer and as a member of the Board of Directors in September 2001. He was promoted
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Index to his current position of Chairman, President and Chief Executive Officer in May 2002. Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as Samedan’s Senior Vice President, as well as Division General Manager for the Offshore Division, a position he held since August 1996. He also served as a member of the Executive Operating Committee for Samedan. Mr. Dinges started his career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and the central Gulf of Mexico. After four years of expanding responsibilities at Mobil, he joined Samedan as a Division Landman – Offshore. Over the years, Mr. Dinges held positions of increasing responsibility at Samedan including Division Manager, Vice President and ultimately Senior Vice President. Mr. Dinges received his B.B.A. degree in Petroleum Land Management from The University of Texas.Financial Statements
PART II
Thomas S. Liberatorejoined Cabot in January 2002 as Regional Manager, East and was promoted to his current position in July 2003. Prior to joining the Company, Mr. Liberatore served as Vice President, Exploration and Production for North Coast Energy. He began his career as a geologist and has held various positions of increasing responsibility for Presidio Oil Company and Belden & Blake Corporation. Mr. Liberatore received his B.S. in Geology from West Virginia University.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of the common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. A regular dividend has been declared each quarter since we became a public company in 1990.
On February 28, 2005, we announced that our Board of Directors had declared a 3-for-2 split of our common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, we paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 3-for-2 split of our common stock.
| High | Low | Cash Dividends | High | Low | Dividends | |||||||||||||
2006 | ||||||||||||||||||
First Quarter | $ | 52.01 | $ | 43.18 | $ | 0.04 | ||||||||||||
Second Quarter | 54.44 | 38.42 | 0.04 | |||||||||||||||
Third Quarter | 55.15 | 44.15 | 0.04 | |||||||||||||||
Fourth Quarter | 65.71 | 44.38 | 0.04 | |||||||||||||||
2005 | ||||||||||||||||||
First Quarter | $ | 38.04 | $ | 27.78 | $ | 0.027 | $ | 38.04 | $ | 27.78 | $ | 0.027 | ||||||
Second Quarter | 38.13 | 28.29 | 0.040 | 38.13 | 28.29 | 0.04 | ||||||||||||
Third Quarter | 50.81 | 36.05 | 0.040 | 50.81 | 36.05 | 0.04 | ||||||||||||
Fourth Quarter | 51.54 | 40.48 | 0.040 | 51.54 | 40.48 | 0.04 | ||||||||||||
2004 | ||||||||||||||||||
First Quarter | $ | 21.93 | $ | 19.17 | $ | 0.027 | ||||||||||||
Second Quarter | 28.20 | 20.09 | 0.027 | |||||||||||||||
Third Quarter | 30.05 | 25.87 | 0.027 | |||||||||||||||
Fourth Quarter | 32.25 | 27.27 | 0.027 | |||||||||||||||
As of January 31, 2006,2007, there were 632590 registered holders of the common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.
Issuer Purchases of Equity SecuritiesISSUER PURCHASES OF EQUITY SECURITIES
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum of Shares that | |||||
October 2005 | — | $ | — | — | 1,918,750 | ||||
November 2005 | 207,400 | $ | 43.10 | 207,400 | 1,711,350 | ||||
December 2005 | 225,200 | $ | 42.95 | 225,200 | 1,486,150 | ||||
Total | 432,600 | $ | 43.02 | ||||||
On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has been adjusted to three million shares. On October 26, 2006, we announced that our Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. We did not repurchase any shares under the program in the fourth quarter of 2006. As of December 31, 2006, 2,397,650 shares remained authorized for repurchase under the plan.
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Index to Financial Statements
PERFORMANCE GRAPH
The following graph compares our common stock performance (“COG”) with the performance of the Standard & Poors’ 500 Stock Index and the Dow Jones Secondary Oils-US Index for the period December 2001 through December 2006. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2001 and that all dividends were reinvested.
Calculated Values | 2001 | 2002 | 2003 | 2004 | 2005 | 2006 | ||||||
S&P 500 | 100.0 | 76.6 | 96.9 | 105.6 | 108.7 | 123.5 | ||||||
COG | 100.0 | 104.1 | 124.4 | 189.1 | 290.6 | 392.2 | ||||||
DJ Secondary Oils-US | 100.0 | 100.8 | 130.4 | 183.2 | 300.6 | 314.6 |
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
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Index to Financial Statements
ITEM 6. SELECTED FINANCIAL DATA
| ITEM 6. | SELECTED FINANCIAL DATA |
The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes.Notes in Item 8.
| Year Ended December 31, | |||||||||||||||
| (In thousands, except per share amounts) | 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||
Statement of Operations Data | |||||||||||||||
Operating Revenues | $ | 682,797 | $ | 530,408 | $ | 509,391 | $ | 353,756 | $ | 447,042 | |||||
Impairment of Oil and Gas Properties (1) | — | 3,458 | 93,796 | 2,720 | 6,852 | ||||||||||
Income from Operations | 258,731 | 160,653 | 66,587 | 49,088 | 95,366 | ||||||||||
Net Income | 148,445 | 88,378 | 21,132 | 16,103 | 47,084 | ||||||||||
Basic Earnings per Share(2)(3) | $ | 3.04 | $ | 1.81 | $ | 0.44 | $ | 0.34 | $ | 1.04 | |||||
Dividends per Common Share(2) | $ | 0.147 | $ | 0.107 | $ | 0.107 | $ | 0.107 | $ | 0.107 | |||||
Balance Sheet Data | |||||||||||||||
Properties and Equipment, Net | $ | 1,238,055 | $ | 994,081 | $ | 895,955 | $ | 971,754 | $ | 981,338 | |||||
Total Assets | 1,495,370 | 1,210,956 | 1,055,056 | 1,100,947 | 1,092,810 | ||||||||||
Current Portion of Long-Term Debt | 20,000 | 20,000 | — | — | — | ||||||||||
Long-Term Debt | 320,000 | 250,000 | 270,000 | 365,000 | 393,000 | ||||||||||
Stockholders’ Equity | 600,211 | 455,662 | 365,197 | 350,657 | 346,552 | ||||||||||
| Year Ended December 31, | ||||||||||||||||
(In thousands, except per share amounts) | 2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||
Statement of Operations Data | ||||||||||||||||
Operating Revenues | $ | 761,988 | $ | 682,797 | $ | 530,408 | $ | 509,391 | $ | 353,756 | ||||||
Impairment of Oil and Gas Properties(1) | 3,886 | — | 3,458 | 93,796 | 2,720 | |||||||||||
Gain / (Loss) on Sale of Assets(2) | 232,017 | 74 | (124 | ) | 12,173 | 244 | ||||||||||
Income from Operations | 528,946 | 258,731 | 160,653 | 66,587 | 49,088 | |||||||||||
Net Income | 321,175 | 148,445 | 88,378 | 21,132 | 16,103 | |||||||||||
Basic Earnings per Share(3) (4) | $ | 6.64 | $ | 3.04 | $ | 1.81 | $ | 0.44 | $ | 0.34 | ||||||
Dividends per Common Share(3) | $ | 0.160 | $ | 0.147 | $ | 0.107 | $ | 0.107 | $ | 0.107 | ||||||
Balance Sheet Data | ||||||||||||||||
Properties and Equipment, Net | $ | 1,480,201 | $ | 1,238,055 | $ | 994,081 | $ | 895,955 | $ | 971,754 | ||||||
Total Assets | 1,834,491 | 1,495,370 | 1,210,956 | 1,055,056 | 1,100,947 | |||||||||||
Current Portion of Long-Term Debt | 20,000 | 20,000 | 20,000 | — | — | |||||||||||
Long-Term Debt | 220,000 | 320,000 | 250,000 | 270,000 | 365,000 | |||||||||||
Stockholders’ Equity | 945,198 | 600,211 | 455,662 | 365,197 | 350,657 | |||||||||||
(1) | For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements. |
(2) | Gain on Sale of Assets for 2006 reflects $231.2 million related to the sale of offshore and certain south Louisiana properties in the third quarter of 2006. |
(3) | All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 3-for-2 split of our common stock effective March 31, 2005. |
(4) |
| Year 2003 includes a cumulative effect of a change in accounting principle loss of $0.14 per share related to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.” |
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Index to Financial Statements
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details.
We operate in one segment, natural gas and oil explorationdevelopment, exploitation and exploitation,exploration, exclusively within the United States and Canada.
OVERVIEW
Cabot Oil & Gas and its subsidiaries are a leading independent oil and gas company engaged in the exploration, development, acquisition, exploitation, exploration, production and marketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. We also transport, store, gather and produce natural gas for resale. Our exploitation and exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced with a focus on achieving strong financial returns.
At Cabot, there are three types of investment alternatives that constantly compete for available capital: drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment or repurchase of common stock. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time. At any one time, one or more of these may not be economically feasible.
Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Price volatility in the commodity markets has remained prevalent in the last few years. Throughout 20042005 and 2005,2006, the futures market reported unprecedentedstrong natural gas and crude oil contract prices. Our realized natural gas and crude oil price was $6.74$7.13 per Mcf and $44.19$65.03 per Bbl, respectively, in 2005.2006. These realized prices include the realized impact of derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars and swaps.collars. These financial instruments are an important element of our risk management strategy but prevented usand assisted in the increase in our realized natural gas price from realizing the full impact of the price environment.2005 to 2006.
Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, natural gas liquids and crude oil prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See “Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business” and “Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable” in Item 1A.
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Index to Financial Statements
The tables below illustrate how natural gas prices have fluctuated by month over 20042005 and 2005.2006. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2004”“2005” and “2005”“2006” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas price collar and swap arrangements, as applicable:
| (in $ per Mcf) | Natural Gas Prices by Month - 2005 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Natural Gas Prices by Month - 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(In $ per Mcf) | Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 11.45 | $ | 8.46 | $ | 7.13 | $ | 7.25 | $ | 7.22 | $ | 5.93 | $ | 5.89 | $ | 7.04 | $ | 6.82 | $ | 4.20 | $ | 7.16 | $ | 8.33 | ||||||||||||||||||||||||||||||||||||||||||||||||
2006 | $ | 9.79 | $ | 7.83 | $ | 7.11 | $ | 6.90 | $ | 7.02 | $ | 6.37 | $ | 6.49 | $ | 7.10 | $ | 6.71 | $ | 5.45 | $ | 7.27 | $ | 7.64 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Natural Gas Prices by Month - 2005 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(In $ per Mcf) | Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 6.21 | $ | 6.29 | $ | 6.30 | $ | 7.33 | $ | 6.77 | $ | 6.13 | $ | 6.98 | $ | 7.65 | $ | 10.97 | $ | 13.93 | $ | 13.85 | $ | 11.21 | $ | 6.21 | $ | 6.29 | $ | 6.30 | $ | 7.33 | $ | 6.77 | $ | 6.13 | $ | 6.98 | $ | 7.65 | $ | 10.97 | $ | 13.93 | $ | 13.85 | $ | 11.21 | ||||||||||||||||||||||||
2005 | $ | 5.78 | $ | 5.84 | $ | 5.52 | $ | 6.28 | $ | 6.19 | $ | 5.55 | $ | 6.05 | $ | 6.58 | $ | 7.76 | $ | 8.94 | $ | 8.53 | $ | 7.78 | $ | 5.78 | $ | 5.84 | $ | 5.52 | $ | 6.28 | $ | 6.19 | $ | 5.55 | $ | 6.05 | $ | 6.58 | $ | 7.76 | $ | 8.94 | $ | 8.53 | $ | 7.78 | ||||||||||||||||||||||||
| (in $ per Mcf) | Natural Gas Prices by Month - 2004 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 6.15 | $ | 5.77 | $ | 5.15 | $ | 5.37 | $ | 5.94 | $ | 6.68 | $ | 6.14 | $ | 6.04 | $ | 5.08 | $ | 5.79 | $ | 7.63 | $ | 7.78 | ||||||||||||||||||||||||||||||||||||||||||||||||
2004 | $ | 5.23 | $ | 5.23 | $ | 5.17 | $ | 4.88 | $ | 4.96 | $ | 5.23 | $ | 5.39 | $ | 5.21 | $ | 4.54 | $ | 5.29 | $ | 5.63 | $ | 5.55 | ||||||||||||||||||||||||||||||||||||||||||||||||
Prices for crude oil have followed a similar path as the commodity price continued to maintain strength in 20042005 and rose further in 2005.2006. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 20042005 and 2005.2006. The “2004”“2005” and “2005”“2006” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:
| (in $ per Bbl) | Crude Oil Prices by Month - 2005 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Crude Oil Prices by Month - 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(In $ per Bbl) | Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 65.54 | $ | 61.93 | $ | 62.97 | $ | 70.16 | $ | 70.96 | $ | 70.97 | $ | 74.46 | $ | 73.08 | $ | 63.90 | $ | 59.14 | $ | 59.40 | $ | 62.09 | ||||||||||||||||||||||||||||||||||||||||||||||||
2006 | $ | 63.53 | $ | 60.83 | $ | 59.28 | $ | 68.27 | $ | 68.56 | $ | 68.12 | $ | 74.03 | $ | 73.01 | $ | 60.87 | $ | 53.88 | $ | 55.97 | $ | 59.47 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Crude Oil Prices by Month - 2005 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(In $ per Bbl) | Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 46.85 | $ | 48.05 | $ | 54.63 | $ | 53.22 | $ | 49.87 | $ | 56.42 | $ | 59.03 | $ | 64.99 | $ | 65.55 | $ | 62.27 | $ | 58.34 | $ | 59.45 | $ | 46.85 | $ | 48.05 | $ | 54.63 | $ | 53.22 | $ | 49.87 | $ | 56.42 | $ | 59.03 | $ | 64.99 | $ | 65.55 | $ | 62.27 | $ | 58.34 | $ | 59.45 | ||||||||||||||||||||||||
2005 | $ | 38.18 | $ | 40.57 | $ | 47.30 | $ | 44.95 | $ | 41.88 | $ | 44.58 | $ | 46.24 | $ | 46.62 | $ | 45.05 | $ | 45.92 | $ | 45.59 | $ | 43.70 | $ | 38.18 | $ | 40.57 | $ | 47.30 | $ | 44.95 | $ | 41.88 | $ | 44.58 | $ | 46.24 | $ | 46.62 | $ | 45.05 | $ | 45.92 | $ | 45.59 | $ | 43.70 | ||||||||||||||||||||||||
| (in $ per Bbl) | Crude Oil Prices by Month - 2004 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Index | $ | 34.23 | $ | 34.50 | $ | 36.72 | $ | 36.62 | $ | 40.28 | $ | 38.05 | $ | 40.81 | $ | 44.88 | $ | 45.94 | $ | 53.09 | $ | 48.48 | $ | 43.26 | ||||||||||||||||||||||||||||||||||||||||||||||||
2004 | $ | 30.62 | $ | 30.66 | $ | 31.62 | $ | 30.97 | $ | 30.80 | $ | 31.51 | $ | 31.43 | $ | 33.00 | $ | 31.61 | $ | 32.87 | $ | 33.15 | $ | 30.46 | ||||||||||||||||||||||||||||||||||||||||||||||||
We reported earnings of $6.64 per share, or $321.2 million, for 2006. This is up from the $3.04 per share, or $148.4 million, for 2005. This is up from the $1.81 per share, or $88.4 million, reported in 2004. The2005. Earnings increased from 2005 to 2006 due to the $231.2 million ($144.5 million, net of tax) gain recorded in 2006 related to the sale of our offshore and certain south Louisiana properties. In addition, the stronger price environment, was afavorable natural gas hedge settlements and increased natural gas production were primary contributorcontributors to the earnings increase due to the increase in natural gas and oil revenues. Prices, including the realized impact of derivative instruments, rose 30%six percent for natural gas and 40%47% for oil.
We drilled 316387 gross wells with a success rate of 95%96% in 20052006 compared to 256316 gross wells with a 95% success rate in 2004.2005. Total capital and exploration expenditures increased by $166.1$111.9 million to $537.5 million in 2006, of which $6.7 million was for property acquisitions, compared to $425.6 million in 2005, of which $73.1 million was for property acquisitions, in 2005 compared to $259.5 million for 2004.acquisitions. We believe our operating cash flow in 20062007 will be sufficient to fund a substantial portion of our budgeted capital and exploration budgeted spending of approximately $396$434 million, and again provide excess cash flow. Any excess cash flow may be used for acquisitions, to pay current debt due, repurchase common stock, expandwith minimal borrowings from our capital program or other opportunities.credit facility.
Our 20062007 strategy will remain consistent with 2005.2006. We will remain focused on our strategies of balancing our capital investments between higher risk projects with the potential for higher returns andpursuing lower risk projects withdrilling opportunities that provide more stable returns, along with balancing longer life investments withpredictable results and selectively pursuing impact exploration opportunities.opportunities as we accelerate drilling on our accumulated acreage position. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.
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Index to Financial Statements
FINANCIAL CONDITION
Capital Resources and Liquidity
Our primary sourcesources of cash in 2005 was2006 were from funds generated from operations, as well as borrowings onthe sale of natural gas and crude oil production and proceeds from the sale of our revolving credit facilityoffshore and certain south Louisiana properties and, to a lesser extent, proceeds from the exercise of stock options under our stock plans. We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been subject tovolatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout the recent years. Working capital is also substantially influenced by these variables. During 2005, approximately 1.4 Bcfe of expected production in our Gulf Coast region was deferred due to the impacts of Hurricanes Katrina and Rita. These hurricanes did not have a material adverse impact on our capital resources nor liquidity. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures and to pay dividends. Proceeds from the disposition of our offshore and certain south Louisiana properties were used to fund additional capital expenditures, reduce borrowings under our revolving credit facility and to purchase treasury stock and pay dividends.stock. Proceeds from the exercise of stock options under stock option plans and the tax benefit of stock based compensation during 20052006 partially offset our repurchase of 452,3001,088,500 treasury shares of common stock at a weighted average purchase price of $42.41.$42.71. See below for additional discussion and analysis of cash flow.
| Year-Ended December 31, | ||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Cash Flows Provided by Operating Activities | $ | 364,560 | $ | 273,022 | $ | 241,638 | ||||||
Cash Flows Used by Investing Activities | (412,150 | ) | (255,357 | ) | (151,856 | ) | ||||||
Cash Flows Provided / (Used) by Financing Activities | 48,190 | (8,363 | ) | (90,660 | ) | |||||||
Net Increase / (Decrease) in Cash and Cash Equivalents | $ | 600 | $ | 9,302 | $ | (878 | ) | |||||
| Year-Ended December 31, | ||||||||||||
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Cash Flows Provided by Operating Activities | $ | 357,104 | $ | 364,560 | $ | 273,022 | ||||||
Cash Flows Used in Investing Activities | (187,353 | ) | (412,150 | ) | (255,357 | ) | ||||||
Cash Flows (Used in) / Provided by Financing Activities | (138,523 | ) | 48,190 | (8,363 | ) | |||||||
Net Increase in Cash and Cash Equivalents | $ | 31,228 | $ | 600 | $ | 9,302 | ||||||
Operating Activities. Net cash provided by operating activities in 2006 decreased by $7.5 million over 2005. This decrease was primarily due to an increase in current income tax expense related to the sale of our offshore and certain south Louisiana properties, partially offset by an increase in earnings and an increase in working capital changes. Other factors impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased six percent over 2005, while crude oil realized prices increased 47% over the same period. Equivalent production increased by five percent in 2006 compared to 2005. While we believe 2007 commodity production may exceed 2006 levels, we are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.
Net cash provided by operating activities in 2005 increased $91.5 million over 2004. This increase iswas primarily due to higher commodity prices. Key components impacting net operating cash flows arewere commodity prices, production volumes and operating costs. Average realized natural gas prices increased 30% over 2004, while crude oil realized prices increased 40% over the same period. Production volumes declined slightly, with a less than one percent reduction of equivalent production in 2005 compared to 2004. While we believe 2006 commodity production may exceed 2005 levels, we are unable to predict future commodity prices, and as a result cannot provide any assurance about future levels of net cash provided by operating activities.
Net cash provided by operating activities in 2004 increased $31.4 million over 2003. This increase is primarily due to higher commodity prices. Key components of net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 15% over 2003, while crude oil realized prices increased 7% over the same period. Production volumes declined, with a 5% reduction of equivalent production in 2004 compared to 2003. See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue.
Investing Activities. The primary uses of cash byin investing activities arewere capital spending and exploration expense.expenses. We establishestablished the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities decreased by $224.8 million from 2005 to 2006 and increased for the years ended December 31, 2005 and 2004 in the amounts ofby $156.8 million from 2004 to 2005. Cash flows used in investments in capital and $103.5exploration expenditures were $516.8 million respectively. in 2006 compared to $413.1 million used in 2005, in response to higher commodity prices. This increase of $103.7 million in investments in capital and exploration expenses was entirely offset by the increase of $328.5 million in proceeds from the sale of assets, primarily as a result of the sale of our offshore and certain south Louisiana properties.
The increase from 2004 to 2005 iswas primarily due to an increase in drilling activity in the East region and the Rocky Mountains area of our West region in response to higher commodity prices. Our continued drilling activity in Canada also contributed to the increase. In addition, we spent $73.1 million in proved property acquisitions, primarily in the Gulf Coast. The increase from 2003
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Index to 2004 was also primarily due to an increase in drilling activity in response to higher commodity prices. This increase largely occurred in our East region and the Rocky Mountains area of our West region. Our initial drilling activity in Canada also contributed to the increase.Financial Statements
Financing Activities. Cash flows used in financing activities were $138.5 million for 2006, and were comprised of payments made to decrease outstanding debt under our revolving credit facility, to purchase treasury stock and to pay dividends. Partially offsetting these cash uses were inflows from the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows provided by financing activities were $48.2 million for the year ended December 31, 2005, resulting from borrowings under the credit facility, partially offset by the purchase of treasury stock and dividend payments. Cash flows used byin financing activities for the year ended December 31, 2004 were $8.4 million. This is the result ofmillion, resulting from proceeds from the exercise of stock options, offset by the purchase of treasury shares and dividend payments. Cash flows used by financing activities for the year ended December 31, 2003 were $90.7 million. This is substantially due to a net repayment on our revolving credit facility in the amount of $95.0 million. Cash utilized for the repayments was generated from operating cash flows.
At December 31, 2005,2006, we had $90$10 million of debt outstanding under our credit facility. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.
In August 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has beenwas adjusted to three million shares. In October 2006, we announced that our Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares for a total of five million shares. During 2005,2006, we repurchased 452,3001,088,500 shares of our common stock at a weighted average price of $42.41.$42.71. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The maximum number of shares that may yet be purchased under the plan as of December 31, 20052006 was 1,486,150.2,397,650. See Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional information.
Capitalization
Information about our capitalization is as follows:
| December 31, | ||||||||
| (In millions) | 2005 | 2004 | ||||||
Debt (1) | $ | 340.0 | $ | 270.0 | ||||
Stockholders’ Equity | 600.2 | 455.7 | ||||||
Total Capitalization | $ | 940.2 | $ | 725.7 | ||||
Debt to Capitalization | 36 | % | 37 | % | ||||
Cash and Cash Equivalents | $ | 10.6 | $ | 10.0 | ||||
| December 31, | ||||||||
(In millions) | 2006 | 2005 | ||||||
Debt(1) | $ | 240.0 | $ | 340.0 | ||||
Stockholders’ Equity | 945.2 | 600.2 | ||||||
Total Capitalization | $ | 1,185.2 | $ | 940.2 | ||||
Debt to Capitalization | 20 | % | 36 | % | ||||
Cash and Cash Equivalents | $ | 41.9 | $ | 10.6 | ||||
(1) | Includes $20.0 million of current portion of long-term debt at both December 31, |
For the year ended December 31, 2005,2006, we paid dividends of $7.2$7.8 million on our common stock. A regular dividend of $0.04 per share of common stock, or $0.027 per share for dividends prior to the 3-for-2 stock split as adjusted for the split, has been declared for each quarter since we became a public company.company in 1990.
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Index to Financial Statements
Increase in Authorized Shares
On May 4, 2006, our stockholders approved an increase in the authorized number of shares of our common stock from 80 million to 120 million shares. We correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to our Rights Agreement with The Bank of New York, as Rights Agent.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration activities, excluding significant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2005.2006.
| (In millions) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||
Capital Expenditures | ||||||||||||||||||
Drilling and Facilities | $ | 249.3 | $ | 174.0 | $ | 102.0 | $ | 406.9 | $ | 249.3 | $ | 174.0 | ||||||
Leasehold Acquisitions | 22.1 | 18.3 | 14.1 | 42.6 | 22.1 | 18.3 | ||||||||||||
Pipeline and Gathering | 17.9 | 13.5 | 10.6 | 24.2 | 17.9 | 13.5 | ||||||||||||
Other | 1.4 | 1.6 | 1.8 | 7.7 | 1.4 | 1.6 | ||||||||||||
| 290.7 | 207.4 | 128.5 | 481.4 | 290.7 | 207.4 | |||||||||||||
Proved Property Acquisitions | 73.1 | 4.0 | 1.5 | 6.7 | 73.1 | 4.0 | ||||||||||||
Exploration Expense | 61.8 | 48.1 | 58.2 | 49.4 | 61.8 | 48.1 | ||||||||||||
Total | $ | 425.6 | $ | 259.5 | $ | 188.2 | $ | 537.5 | $ | 425.6 | $ | 259.5 | ||||||
We plan to drill about 391approximately 440 gross wells in 20062007 compared with 316387 gross wells drilled in 2005.2006. This 20062007 drilling program includes approximately $396$434 million in total capital and exploration expenditures, down from $425.6$537.5 million in 2005. Capital and exploration expenditures in 2005 included a layer of $73.1 million in proved property acquisitions as shown in the table above.2006. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.
There are many factors that impact our depreciation, depletion and amortization (DD&A) rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in a future period. In 20062007, management expects an increase in our depreciation, depletion and amortizationDD&A rate due to negative reserve revisions and higher capital costs.costs, partially as a result of inflationary cost pressures in the industry over the last three years, and downward reserve revisions. This change may result in an increase of depreciation, depletion and amortization of 10%is currently estimated to be approximately 15% greater than 20052006 levels. This increase will not have an impact on our cash flows.
Contractual Obligations
Our known material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations,obligations.
During 2006, we assisted certain non-executive employees in obtaining loans to purchase interests offered under our Mineral, Royalty and we have not guaranteedOverriding Royalty Interest Plan by providing a guarantee of repayment should the debtnon-executive employee fail to repay the loan. The repayment term for all of any other party.these loans is five years. All loans are collateralized by the interests transferred to the employees in the producing properties. The outstanding loan balances are approximately $0.3 million in the aggregate, and the fair value of these guarantees are immaterial to our financial statements.
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Index to Financial Statements
A summary of our known contractual obligations as of December 31, 20052006 are set forth in the following table:
| Payments Due by Year | |||||||||||||||
| 2007 | 2009 | 2011 & | |||||||||||||
| (In thousands) | Total | 2006 | to 2008 | to 2010 | Beyond | ||||||||||
Long-Term Debt(1) | $ | 340,000 | $ | 20,000 | $ | 40,000 | $ | 110,000 | $ | 170,000 | |||||
Interest on Long-Term Debt (2) | 132,960 | 24,632 | 44,950 | 32,673 | 30,705 | ||||||||||
Firm Gas Transportation Agreements(3) | 93,766 | 11,661 | 19,839 | 6,762 | 55,504 | ||||||||||
Drilling Rig Commitments (3) | 104,315 | 26,055 | 68,585 | 9,675 | — | ||||||||||
Operating Leases | 17,746 | 4,876 | 9,174 | 3,696 | — | ||||||||||
Total Contractual Cash Obligations | $ | 688,787 | $ | 87,224 | $ | 182,548 | $ | 162,806 | $ | 256,209 | |||||
| Total | Payments Due by Year | ||||||||||||||
(In thousands) | 2007 | 2008 to 2009 | 2010 to 2011 | 2012 & Beyond | |||||||||||
Long-Term Debt(1) | $ | 240,000 | $ | 20,000 | $ | 50,000 | $ | 75,000 | $ | 95,000 | |||||
Interest on Long-Term Debt(2) | 91,888 | 17,596 | 30,878 | 24,914 | 18,500 | ||||||||||
Firm Gas Transportation Agreements(3) | 85,118 | 9,864 | 15,356 | 7,140 | 52,758 | ||||||||||
Drilling Rig Commitments(3) | 120,261 | 54,382 | 63,629 | 2,250 | — | ||||||||||
Operating Leases(3) | 14,076 | 5,014 | 8,254 | 808 | — | ||||||||||
Total Contractual Cash Obligations | $ | 551,343 | $ | 106,856 | $ | 168,117 | $ | 110,112 | $ | 166,258 | |||||
(1) | Including current portion. At December 31, |
(2) | Interest payments have been calculated utilizing the fixed rates of our |
(3) | For further information on our obligations under firm gas transportation agreements, |
Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2005 is2006 was $22.7 million, down from $43.0 million.
Subsequent tomillion at December 31, 2005, we entered into an agreement for one additional drilling rig inprimarily due to the Gulf Coast. The total commitment oversale of the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 millionoffshore and $8.4 million will be paid outcertain south Louisiana properties during the years 2006, 2007, 2008 and 2009, respectively.end of the third quarter of 2006.
Potential Impact of Our Critical Accounting Policies
Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The most significant policies are discussed below.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the threefour regions in which we operate. The estimation of reserves for certain properties sold in 2006 as well as a small number of properties currently held in the Gulf Coast region requires more estimates than in Canada and the East and West regions and inherently has more uncertainty surrounding reserve estimation. Theestimation.The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgment of the persons preparing the estimate.
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Index to Financial Statements
Since 1990, 100% of our reserves have been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates presented to be reasonable in the aggregate. We have not been required to record a significant reserve revision in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.”
Our rate of recording depreciation, depletion and amortizationDD&A expense (DD&A) is dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately $0.05 to $0.06 per Mcfe. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would have a $0.01 impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A.&A rate.
In addition, a decline in proved reserve estimates may impact the outcome of our annual impairment test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived AssetsAssets..” Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.
Carrying Value of Oil and Gas Properties
We evaluate the impairment of our oil and gas properties on a lease-by-lease basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. In 2003, we significantly revised the estimated cash flow utilized in our impairment review of the Kurten field due to a loss of a reversionary interest in the field. In December 2003, our remaining interest in the field was sold. For additional discussion on the Kurten field impairment see Note 2 of the Notes to the Consolidated Financial Statements. In2006, 2005 and 2004, and 2005, there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test.
Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regional basis and based on the estimated life of unproved property leasehold rights. Historically, the average property lives in each of the regions have not significantly changed. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.7$2.1 million or decrease by approximately $1.6$2.0 million, respectively per year.
In the past, the average leasehold life in the Gulf Coast region has been shorter than the average life in the East and West regions. Average property lives in the East, Gulf Coast East and West regions have been four, sevensix, three and seven years, respectively. Average property lives in Canada are estimated to be sixfour years. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration program.
Accounting for Derivative Instruments and Hedging Activities
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. We follow the accounting prescribed in SFAS No. 133. Under SFAS No. 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated Other
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Index to Financial Statements
Comprehensive Income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. Under SFAS No. 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. AnyThe ineffective portion, if any, of the gains or losses that are considered ineffective underchange in the SFAS No. 133 test arefair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded immediatelycurrently in earnings as a component of Operating Revenue, either in Natural Gas Production orand Crude Oil and Condensate Revenue, onas appropriate in the Consolidated Statement of Operations.
Long-Term Employee Benefit Costs
Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions.
The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates of return published for a theoretical portfolio of high-quality fixed income securities. In order to select the discount rate, we use benchmarks such as the
Moody’s Aa Corporate Rate, which was 5.48%5.8% annualized for 2005,2006, and the Citigroup Pension Liability Index, which was 5.55% for 2005.5.9% at the end of 2006. We look to these benchmarks as well as considering durations of expected benefit payments. We have determined based on these assumptions that a discount rate of 5.5%5.75% at December 31, 20052006 is reasonable.
In order to value our pension liabilities, we use the RP-2000 mortality table.Combined Mortality Table. This is a widely accepted table used for valuing pension liabilities. This table represents a more recent and conservative mortality table than the prior years’ 1983 Group Annuity Mortality Table, and appears to be an appropriate table based on the demographics of our benefit plans. Another consideration that is made is a salary scale selection. We have assumed that salaries will increase 4%four percent based on our expectation of future salary increases.
The benefit obligation and the periodic cost of postretirement medical benefits also are measured based on assumed rates of future increase in the per capita cost of covered health care benefits. As of December 31, 2005,2006, the assumed rate of increase was 9.0%8.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility.
We have established objectives regarding plan assets in the pension plan. We attempt to maximize return over the long-term, subject to appropriate levels of risk. One of our plan objectives is that the performance of the equity portion of the pension plan exceed the Standard and Poors’ 500 Index by a minimum of two percent annually over the long term. We also seek to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In our pension calculations, we have used 8%eight percent as the expected long-term return on plan assets for 2006, 2005 2004 and 2003. However,2004. A Monte Carlo simulation was run using 5,000 simulations based upon our actual asset allocation and liability duration, which has been determined to be approximately 16 years. This model uses historical data for the period of 1926-2003 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that we expect to achieve over 50 percent of the time, is approximately nine percent. We expect to achieve a minimum 5%6.4% annual real rate of return on the total portfolio over the long term. We believe that this is a reasonable estimate based on our actual results. Theterm at least 75 percent of the time. In addition, the actual rate of return on plan assets annualized over the past ten years is approximately 10%.six percent. We believe that the eight percent chosen is a reasonable estimate based on our actual results.
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Index to Financial Statements
We generally target a portfolio of assets utilizing equity securities, fixed income securities and cash equivalents that are within a range of approximately 60%50% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of our portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be invested in money market investments up to 20%. One percent of the portfolio is invested in short-term funds at the designated bank to meet the cash flow needs of the plan. No prohibited investments, including direct or indirect investments in commodities, commodity futures, derivatives, short sales, real estate investment trusts, letter stock, restricted stock or other private placements, are allowed without prior committee approval.
Stock-Based Compensation
Prior toEffective January 1, 2006, we adopted the issuance ofaccounting policies described in SFAS No. 123(R), “Share Based Payment (revised 2004).”, there We chose to use the modified prospective method of transition, and accordingly, no adjustments to prior period financial statements were two alternative methods that could be usedmade. Prior to accountJanuary 1, 2006, we accounted for stock-based compensation. The firstcompensation in accordance with the intrinsic value based method is the Intrinsic Valueprescribed by Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Under this method, and recognizeswe recognized compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. The secondIn addition, SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method is the Fair Value method.of accounting for stock options or similar equity instruments. Under the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period. As of December 31, 2005, we account for stock-based compensation in accordance with the Intrinsic Value method. SFAS No. 123(R) requires that the fair value of stock options and any other equity-based compensation must be expensed at the grant date. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. We currently
One primary difference in our method of accounting after the adoption of SFAS No. 123(R) is that unvested stock options are now expensed as a component of Stock-Based Compensation cost in General and Administrative Expense in the Consolidated Statement of Operations. This expense is based on the fair value of the award at the original grant date and is recognized over the vesting period. Prior to the adoption of SFAS No. 123(R), we included this amount as a pro-forma disclosure in the Notes to the Consolidated Financial Statements. The expense resulting from the expensing of stock options was $0.3 million for the year ended December 31, 2006. Another change relates to the accounting for our performance share awards; however, beginningawards. Certain of these awards are now accounted for by bifurcating the equity and liability components. A Monte Carlo model is used to value the liability component, rather than accounting for the award using the average closing stock price at the end of each reporting period. All other awards are accounted for in substantially the same way as they were or would have been in prior periods, with the exception of the differences noted below.
Other differences in the way we account for stock-based compensation after January 1, 2006, result from the application of a forfeiture rate to all grants rather than recording actual forfeitures as they occur. We are now required to estimate forfeitures on all equity-based compensation and adjust periodic expense. Upon adoption, we did not record a cumulative effect adjustment for these forfeitures as the amount was immaterial. In addition, this change in accounting for forfeitures resulted in an immaterial change in overall compensation cost for the year ended December 31, 2006. Furthermore, we are required to expense certain awards to retirement-eligible employees in the month an employee becomes retirement eligible, depending on the structure of each individual plan. The retirement-eligibility provision only applies to new grants that were awarded after January 1, 2006. The total expense that we recognized related to restricted stock awards granted to retirement-eligible employees in 2006 was $0.6 million.
We issued stock appreciation rights to executive employees for the first time during the first quarter of 2006. The grant date fair value of these awards is measured using a Black-Scholes model and compensation cost is expensed over the three year graded-vesting service period. Expense related to these awards was $1.0 million, before the effect of taxes, for 2006. In addition, a new type of performance share was issued to non-executive employees. These awards measure our performance based on three internal metrics, rather than a peer group’s stock performance which we use to measure our other performance share awards. These awards cliff vest at the end of the three year service period. Compensation cost related to these new internal-metric based performance share awards granted to
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Index to Financial Statements
employees was $1.4 million, before the effect of taxes, for 2006. In addition, we incurred a $0.6 million ($0.4 million, net of tax) cumulative effect charge in the first quarter of 2006, which is included within General and Administrative Expenses due to its immateriality, as a result of changes made in our accounting for performance shares. For further information on the accounting for these and our other stock-based compensation awards, please refer to Notes 1 and 10 of the Notes to the Consolidated Financial Statements.
During the third quarter of 2006, we will be required to expense all stock-based compensation. Further discussion of SFASadopted the provisions outlined under FASB Staff Position (FSP) FAS No. 123(R) and-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock compensation is included in “Recently Issued Accounting Pronouncements.”awards using the APIC Pool concept. We made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. We chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors.
On October 26, 2005, theOur Compensation Committee of our Board of Directors made one modification to our stock option awards in 2005. It approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under our Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under our 2004 Incentive Plan.
The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in each of April 2006 and April 2007, respectively.2007. The decision to accelerate the vesting of these unvested options, which we believed to be in the best interest of our shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with our adoption of SFAS No. 123(R).
The accelerated vesting of the options did not have an impact on our results of operations or cash flows for 2005. The acceleration of vesting is expected to reducereduced our compensation expense related to these options by approximately $0.2 million for 2006.
OTHER ISSUES AND CONTINGENCIES
Corporate Income Tax.We have benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer’staxpayer's alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions for corporations other than integrated oil companies. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference can notcannot reduce a taxpayer’staxpayer's alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference.
Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See “Regulation of Oil and Natural Gas Exploration and Production”,Production,” “Natural Gas Marketing, Gathering and Transportation”,Transportation,” “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 “Business” for a discussion of these regulations.
Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in the Company’sCompany's various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2005,2006, we are in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, the Company may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation. See further discussion in Capital“Capital Resources and Liquidity.”
Limited Partnership.As part of the 2001 Cody acquisition, we acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. We had approximately a 25% interest in the field, including a one percent interest in the partnership. Under the partnership agreement, we had the right
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Index to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the addition of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. The limited partner was a financial entity and not an industry operator. Their decision to liquidate was based upon their perception that the value of their investment in the partnership had increased due to an increase in underlying commodity prices, primarily oil, since their investment in 1999. We proceeded with the liquidation to avoid having a minority interest in a non-operated water flood field for which the new operator was not designated at the time of liquidation. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, we were required to test the field for recoverability in accordance with SFAS No. 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an impairment charge in the first quarter of 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.
Financial Statements
Operating Risks and Insurance Coverage.Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses” in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East.
Commodity Pricing and Risk Management Activities.Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially impact the outcome of our annual impairment test under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.
The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collarcollars and, in previous years, swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also risk that the movement of the index prices will result in the Company not being able to realize the full benefit of a market improvement.
Recently Issued Accounting Pronouncements
In March 2005,February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. We do not believe that our financial position, results of operations or cash flows will be impacted by SFAS No. 155 as we do not currently hold any hybrid financial instruments.
In July 2006, the FASB issued FASB Interpretation (FIN) No. 47,48, “Accounting for Conditional Asset Retirement Obligations.Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” This Interpretation clarifies the definitionFIN No. 48 provides guidance for recognizing and treatment of conditional asset retirement obligationsmeasuring uncertain tax positions, as discusseddefined in SFAS No. 143,109, “Accounting for Asset Retirement Obligations.Income Taxes.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or methodFIN No. 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of settlement are dependent on future events that may“more likely than not” should be outside the controlmet to determine whether any of the Company.benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN No. 47 states48 provides additional guidance on measuring the amount of the uncertain tax position. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and disclosure of these uncertain tax positions. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. We are completing our evaluation of the impact of the adoption of FIN No. 48 and believe that the impact will not have a company must recordmaterial effect on our financial position, results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a liability when incurredformal framework for conditional asset retirement obligations if themeasuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles (GAAP) to be measured at fair value. SFAS No. 157 clarifies guidance in
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Index to Financial Statements
FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value of the obligation is reasonably estimable. This Interpretationmeasurements are prescribed, and SFAS No. 157 is intended to provide more information about long-lived assets, more information about futurecodify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating what impact SFAS No. 157 may have on our financial position, results of operations or cash outflowsflows.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for these obligationsDefined Benefit Pension and more consistentOther Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires recognition of these liabilities. FINthe funded status of a benefit plan in the balance sheet and the recognition through other comprehensive income of gains, losses, prior service costs and credits, net of tax, arising during the period but not included as a component of periodic benefit cost. In addition, the measurement date of plan assets and obligations must be as of a company’s balance sheet date. Additional disclosures in the notes to the financial statements are required and guidance is prescribed regarding the selection of discount rates to be used in measuring the benefit obligation. For public companies, the effective date of SFAS No. 47158 is as of the end of the fiscal year ending after December 15, 2006. The effective date of the new measurement date provision is for fiscal years ending after December 15, 2005. Our2008; however, our measurement date is currently our balance sheet date, so no change will be required. The incremental effect of SFAS No. 158, as discussed in Note 5 of the Notes to the Consolidated Financial Statements, was an increase to total long-term liabilities of $21.7 million, an increase to current liabilities of $0.6 million, an increase to total assets of $8.2 million and a decrease to total stockholders’ equity of $14.1 million based on actuarial reports as of December 31, 2006.
In September 2006, the SEC Staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We have adopted the provisions of SAB No. 108 and there was no impact to our financial position, results of operations and cash flows were not impacted by this Interpretation, since we currently record all asset retirement obligations.
On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For our disclosures, refer to Note 2 of the Notes to the Consolidated Financial Statements.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle
was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoptionresult of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We plan to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact our operating results, nor will there be any impact on our future cash flows. See “Stock-Based Compensation” below for further information.
In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with our corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).
In November 2005, the FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS No. 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).
In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a company. Under SFAS No. 123(R), it is required that options and similar instruments be classified as liabilities if the entity can be required under any circumstances to settle the instrument in cash or other assets. Under the FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS No. 123(R). We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).
* * *pronouncement.
Forward-Looking Information
The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.
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Index to Financial Statements
RESULTS OF OPERATIONS
2006 and 2005 Compared
We reported net income for the year ended December 31, 2006 of $321.2 million, or $6.64 per share. During 2005, we reported net income of $148.4 million, or $3.04 per share. Net income increased in the current period by $172.8 million primarily due to an increase in operating income as a result of the gain of $231.2 million ($144.5 million, net of tax) recorded in 2006 related to the disposition of our offshore and certain south Louisiana properties as well as an increase in natural gas and oil production revenues. This increase is partially offset by an increase in total operating expenses of $41.0 million and an increase of $101.5 million in income tax expense. Operating income increased by $270.2 million compared to the prior year, from $258.7 million in 2005 to $528.9 million in 2006.
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Index to Financial Statements
Natural Gas Production Revenues
Our average total company realized natural gas production sales price for 2006, including the realized impact of derivative instruments, was $7.13 per Mcf compared to $6.74 per Mcf for the prior year. These prices include the realized impact of derivative instruments, which increased these prices by $0.35 per Mcf in 2006 and reduced these prices by $1.33 per Mcf in 2005. The following table excludes the unrealized gain from the change in derivative fair value of $1.1 million for the year ended December 31, 2005. There was no unrealized impact from the change in derivative fair value for the year ended December 31, 2006. These unrealized changes in fair value have been included in Natural Gas Production Revenues in the Consolidated Statement of Operations.
Year Ended December 31, | Variance | |||||||||||||
| 2006 | 2005 | Amount | Percent | |||||||||||
Natural Gas Production(Mmcf) | ||||||||||||||
East | 23,542 | 21,435 | 2,107 | 10 | % | |||||||||
Gulf Coast | 29,973 | 28,071 | 1,902 | 7 | % | |||||||||
West | 23,633 | 23,224 | 409 | 2 | % | |||||||||
Canada | 2,574 | 1,149 | 1,425 | 124 | % | |||||||||
Total Company | 79,722 | 73,879 | 5,843 | 8 | % | |||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
East | $ | 7.99 | $ | 8.02 | $ | (0.03 | ) | 0 | % | |||||
Gulf Coast | $ | 7.37 | $ | 6.38 | $ | 0.99 | 16 | % | ||||||
West | $ | 6.05 | $ | 6.00 | $ | 0.05 | 1 | % | ||||||
Canada | $ | 6.18 | $ | 6.79 | $ | (0.61 | ) | (9 | %) | |||||
Total Company | $ | 7.13 | $ | 6.74 | $ | 0.39 | 6 | % | ||||||
Natural Gas Production Revenue(In thousands) | ||||||||||||||
East | $ | 188,111 | $ | 171,902 | $ | 16,209 | 9 | % | ||||||
Gulf Coast | 221,020 | 179,061 | 41,959 | 23 | % | |||||||||
West | 143,058 | 139,298 | 3,760 | 3 | % | |||||||||
Canada | 15,908 | 7,802 | 8,106 | 104 | % | |||||||||
Total Company | $ | 568,097 | $ | 498,063 | $ | 70,034 | 14 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue(In thousands) | ||||||||||||||
East | $ | (692 | ) | |||||||||||
Gulf Coast | 29,822 | |||||||||||||
West | 1,189 | |||||||||||||
Canada | (1,572 | ) | ||||||||||||
Total Company | $ | 28,747 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue(In thousands) | ||||||||||||||
East | $ | 16,901 | ||||||||||||
Gulf Coast | 12,137 | |||||||||||||
West | 2,571 | |||||||||||||
Canada | 9,678 | |||||||||||||
Total Company | $ | 41,287 | ||||||||||||
The increase in Natural Gas Production Revenue is due to the increase in natural gas sales production and, to a lesser extent, the increase in realized natural gas prices. Production increased in all regions and prices were up in the Gulf Coast and West. The increase in the total realized natural gas price and production resulted in a net revenue increase of $70.0 million, excluding the unrealized impact of derivative instruments. This growth primarily resulted from our 2005 and 2006 drilling programs, which focused on projects in basins traditionally known for gas development, including the East region, the Minden field in the Gulf Coast and Canada. This natural gas production increase includes the effects of the divestiture of our offshore and certain south Louisiana properties. For the year ended December 31, 2006, natural gas volumes from the properties sold in the third quarter 2006 disposition were 9,037 Mmcf and natural gas revenues from those properties were approximately $70.5 million.
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Index to Financial Statements
Brokered Natural Gas Revenue and Cost
Year Ended December 31, | Variance | |||||||||||||||
| 2006 | 2005 | Amount | Percent | |||||||||||||
Sales Price($/Mcf) | $ | 8.14 | $ | 9.14 | $ | (1.00 | ) | (11 | %) | |||||||
Volume Brokered (Mmcf) | 11,502 | 10,793 | 709 | 7 | % | |||||||||||
Brokered Natural Gas Revenues(In thousands) | $ | 93,651 | $ | 98,605 | ||||||||||||
Purchase Price($/Mcf) | $ | 7.25 | $ | 8.08 | $ | (0.83 | ) | (10 | %) | |||||||
Volume Brokered(Mmcf) | 11,502 | 10,793 | 709 | 7 | % | |||||||||||
Brokered Natural Gas Cost(In thousands) | $ | 83,375 | $ | 87,183 | �� | |||||||||||
Brokered Natural Gas Margin(In thousands) | $ | 10,276 | $ | 11,422 | $ | (1,146 | ) | (10 | %) | |||||||
(In thousands) | ||||||||||||||||
Sales Price Variance Impact on Revenue | $ | (11,434 | ) | |||||||||||||
Volume Variance Impact on Revenue | 6,480 | |||||||||||||||
| $ | (4,954 | ) | ||||||||||||||
(In thousands) | ||||||||||||||||
Purchase Price Variance Impact on Purchases | $ | 9,537 | ||||||||||||||
Volume Variance Impact on Purchases | (5,729 | ) | ||||||||||||||
| $ | 3,808 | |||||||||||||||
The decreased brokered natural gas margin of $1.1 million was driven by a decrease in sales price that outpaced the decrease in purchase cost, offset in part by an increase in volume.
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Index to Financial Statements
Crude Oil and Condensate Revenues
Our average total company realized crude oil sales price for 2006 was $65.03 per Bbl. There was no realized impact of crude oil derivative instruments in 2006. Our average total company realized crude oil sales price was $44.19 per Bbl for 2005, including the realized impact of derivative instruments, which reduced the price by $9.93 per Bbl. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million for the year ended December 31, 2005. There was no unrealized impact from the change in derivative fair value for the year ended December 31, 2006. These unrealized changes in fair value have been included in Crude Oil and Condensate Revenues in the Consolidated Statement of Operations.
Year Ended December 31, | Variance | |||||||||||||
| 2006 | 2005 | Amount | Percent | |||||||||||
Crude Oil Production(Mbbl) | ||||||||||||||
East | 24 | 27 | (3 | ) | (11 | %) | ||||||||
Gulf Coast | 1,160 | 1,528 | (368 | ) | (24 | %) | ||||||||
West | 209 | 166 | 43 | 26 | % | |||||||||
Canada | 12 | 18 | (6 | ) | (33 | %) | ||||||||
Total Company | 1,405 | 1,739 | (334 | ) | (19 | %) | ||||||||
Crude Oil Sales Price($/Bbl) | ||||||||||||||
East | $ | 62.03 | $ | 53.84 | $ | 8.19 | 15 | % | ||||||
Gulf Coast | $ | 65.44 | $ | 42.81 | $ | 22.63 | 53 | % | ||||||
West | $ | 63.36 | $ | 55.37 | $ | 7.99 | 14 | % | ||||||
Canada | $ | 60.55 | $ | 43.39 | $ | 17.16 | 40 | % | ||||||
Total Company | $ | 65.03 | $ | 44.19 | $ | 20.84 | 47 | % | ||||||
Crude Oil Revenue(In thousands) | ||||||||||||||
East | $ | 1,474 | $ | 1,463 | $ | 11 | 1 | % | ||||||
Gulf Coast | 75,894 | 65,427 | 10,467 | 16 | % | |||||||||
West | 13,253 | 9,155 | 4,098 | 45 | % | |||||||||
Canada | 759 | 791 | (32 | ) | (4 | %) | ||||||||
Total Company | $ | 91,380 | $ | 76,836 | $ | 14,544 | 19 | % | ||||||
Price Variance Impact on Crude Oil Revenue(In thousands) | ||||||||||||||
East | $ | 195 | ||||||||||||
Gulf Coast | 26,242 | |||||||||||||
West | 1,672 | |||||||||||||
Canada | 198 | |||||||||||||
Total Company | $ | 28,307 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue(In thousands) | ||||||||||||||
East | $ | (184 | ) | |||||||||||
Gulf Coast | (15,775 | ) | ||||||||||||
West | 2,426 | |||||||||||||
Canada | (230 | ) | ||||||||||||
Total Company | $ | (13,763 | ) | |||||||||||
The increase in the realized crude oil price offset by the decline in production resulted in a net revenue increase of $14.5 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of decreased Gulf Coast production from the sale of properties in the third quarter of 2006 and the continued natural decline of the CL&F lease in south Louisiana, which was part of the sale. For the year ended December 31, 2006, crude oil and condensate volumes from the properties sold in the third quarter disposition were 707 Mbbl and crude oil and condensate revenues from those properties were approximately $47.4 million.
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Index to Financial Statements
Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
| Year Ended December 31, | ||||||||||||||
| 2006 | 2005 | |||||||||||||
(In thousands) | Realized | Unrealized | Realized | Unrealized | ||||||||||
Operating Revenues - Increase/(Decrease) to Revenue | ||||||||||||||
Cash Flow Hedges | ||||||||||||||
Natural Gas Production | $ | 28,266 | $ | — | $ | (98,223 | ) | $ | 1,114 | |||||
Crude Oil | — | — | (2,430 | ) | (6 | ) | ||||||||
Total Cash Flow Hedges | 28,266 | — | (100,653 | ) | 1,108 | |||||||||
Other Derivative Financial Instruments | ||||||||||||||
Crude Oil | — | — | (14,842 | ) | 5,518 | |||||||||
Total Other Derivative Financial Instruments | — | — | (14,842 | ) | 5,518 | |||||||||
| $ | 28,266 | $ | — | $ | (115,495 | ) | $ | 6,626 | ||||||
We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.
Other Operating Revenues
Other operating revenues increased by $6.2 million from 2005 to 2006. This change was primarily a result of an increase in revenues from net profits interest that originated in 2006 as well as a decrease in our payout liability associated with a favorable legal ruling in the first quarter of 2006, which correspondingly increased other revenues, and favorable settlements of state severance tax audits. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year period.
Operating Expenses
Total costs and expenses from operations increased by $41.0 million for the year ended December 31, 2006 compared to the year ended December 31, 2005. The primary reasons for this fluctuation were as follows:
Depreciation, Depletion and Amortization increased by $20.5 million in 2006. This was primarily due to increased production during 2006, an increase in finding costs and an increase in the DD&A rate associated with one field in East Texas as well as the commencement of offshore production in late 2005.
General and Administrative expense increased by $20.5 million in 2006. This increase was primarily due to increased stock compensation costs of $11.6 million. During 2006, performance share and restricted stock amortization expense increased by $9.6 million and $0.7 million, respectively, primarily due to new grants issued in 2006 and changes in the accounting for the value of performance shares. During 2006, expense related to SARs, which were granted for the first time in 2006, and stock options, which were being expensed in 2006 due to the adoption of SFAS No. 123(R), increased by $1.3 million in total. In addition, there were increases in salaries and incentive compensation related to employee bonuses over the prior year as well as reserves for litigation expenses.
Exploration expense decreased by $12.4 million in 2006, primarily as a result of decreased dry hole expense of $12.2 million, mainly as a result of a decrease in the Gulf Coast attributable to a more successful drilling program in 2006 compared to 2005 and, to a lesser extent, better success in Canada, partially offset by increased dry hole expense in the West region. In addition, geological and geophysical expenses were down by $1.9 million. Partially offsetting this overall decrease was an increase in employee expenses for salaries and benefits of approximately $1.2 million for employees in the exploration division as well as increased delay rental expenses of $0.6 million.
Direct Operations expense in 2006 increased by $13.0 million over 2005. This was primarily the result of an increase over the prior year in incentive compensation and personnel related charges, insurance costs, and outside operated properties expense mainly from increases in the Gulf Coast region, largely from repairs related to a plant damaged by the hurricanes that occurred in 2005 and also, to a lesser extent, in the West region. Additional increases occurred in disposal costs, compressor expenses, and treating and pipeline costs. Partially offsetting these increases were decreased workover charges and outside operated plant operations expenses.
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Index to Financial Statements
Impairment of Oil and Gas Properties increased by $3.9 million as a result of an impairment recorded in 2006 for a marginally productive gas well in Colorado County, Texas in the Gulf Coast region compared to no impairments of oil and gas properties in 2005. Further analysis of this impairment is discussed in Note 2 of the Notes to the Consolidated Financial Statements.
Brokered Natural Gas Cost decreased by $3.8 million from 2005 to 2006. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.
Interest Expense, Net
Interest expense, net decreased by $3.4 million due to lower borrowings on our 7.19% fixed rate debt and increased interest on our short term investments as well as the commencement of regulatory interest capitalization on our pipeline in the East region, offset partially by higher average credit facility borrowings as well as an increasing interest rate environment. Weighted average borrowings based on daily balances were approximately $61 million during 2006 compared to $32 million during 2005. In addition, the weighted average effective interest rate on the credit facility increased to 7.9% during 2006 from 6.9% during the prior year.
Income Tax Expense
Income tax expense increased by $101.5 million due to a comparable increase in our pre-tax income, primarily as a result of the gain on the sale of assets recorded in the third quarter of 2006. The effective tax rates for 2006 and 2005 were 37.1% and 37.2%, respectively.
2005 and 2004 Compared
We reported net income for the year ended December 31, 2005 of $148.4 million, or $3.04 per share. During 2004, we reported net income of $88.4 million, or $1.81 per share. Operating income increased by $98.0 million compared to the prior year, from $160.7 million to $258.7 million. The increase in operating income from 2004 to 2005 was principally due to an increase in natural gas and oil production revenues partially offset by an increase in total operating expenses. Net income increased from 2004 to 2005 by $60.0 million due to an increase in operating income partially offset by an increase of $37.6 million in income tax expense.
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Index to Financial Statements
Natural Gas Production Revenues
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.74 per Mcf compared to $5.20 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments, which reduced these prices by $1.33 per Mcf in 2005 and $0.76 per Mcf in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $1.1 million and $0.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Consolidated Statement of Operations.
| Year Ended December 31, | Variance | Year Ended December 31, | Variance | |||||||||||||||||||||||||
| 2005 | 2004 | Amount | Percent | 2005 | 2004 | Amount | Percent | |||||||||||||||||||||
Natural Gas Production (Mmcf) | ||||||||||||||||||||||||||||
East | 21,435 | 19,442 | 1,993 | 10 | % | |||||||||||||||||||||||
Gulf Coast | 28,071 | 31,358 | (3,287 | ) | (10 | )% | 28,071 | 31,358 | (3,287 | ) | (10 | %) | ||||||||||||||||
West | 23,224 | 21,866 | 1,358 | 6 | % | 23,224 | 21,866 | 1,358 | 6 | % | ||||||||||||||||||
East | 21,435 | 19,442 | 1,993 | 10 | % | |||||||||||||||||||||||
Canada | 1,149 | 167 | 982 | 588 | % | 1,149 | 167 | 982 | 588 | % | ||||||||||||||||||
Total Company | 73,879 | 72,833 | 1,046 | 1 | % | 73,879 | 72,833 | 1,046 | 1 | % | ||||||||||||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||||||||||||||||
East | $ | 8.02 | $ | 5.60 | $ | 2.42 | 43 | % | ||||||||||||||||||||
Gulf Coast | $ | 6.38 | $ | 5.27 | $ | 1.11 | 21 | % | $ | 6.38 | $ | 5.27 | $ | 1.11 | 21 | % | ||||||||||||
West | $ | 6.00 | $ | 4.75 | $ | 1.25 | 26 | % | $ | 6.00 | $ | 4.75 | $ | 1.25 | 26 | % | ||||||||||||
East | $ | 8.02 | $ | 5.60 | $ | 2.42 | 43 | % | ||||||||||||||||||||
Canada | $ | 6.79 | $ | 4.69 | $ | 2.10 | 45 | % | ||||||||||||||||||||
Total Company | $ | 6.74 | $ | 5.20 | $ | 1.54 | 30 | % | ||||||||||||||||||||
Natural Gas Production Revenue (in thousands) | ||||||||||||||||||||||||||||
Gulf Coast | $ | 179,061 | $ | 165,177 | $ | 13,884 | 8 | % | ||||||||||||||||||||
West | 139,298 | 103,851 | 35,447 | 34 | % | |||||||||||||||||||||||
East | 171,902 | 108,935 | 62,967 | 58 | % | |||||||||||||||||||||||
Canada | 7,802 | 784 | 7,018 | 895 | % | $ | 6.79 | $ | 4.69 | $ | 2.10 | 45 | % | |||||||||||||||
Total Company | $ | 498,063 | $ | 378,747 | $ | 119,316 | 32 | % | $ | 6.74 | $ | 5.20 | $ | 1.54 | 30 | % | ||||||||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Natural Gas Production Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | 171,902 | $ | 108,935 | 62,967 | 58 | % | |||||||||||||||||||||
Gulf Coast | $ | 31,200 | 179,061 | 165,177 | 13,884 | 8 | % | |||||||||||||||||||||
West | 28,997 | 139,298 | 103,851 | 35,447 | 34 | % | ||||||||||||||||||||||
East | 51,798 | |||||||||||||||||||||||||||
Canada | 2,414 | 7,802 | 784 | 7,018 | 895 | % | ||||||||||||||||||||||
Total Company | $ | 114,409 | $ | 498,063 | $ | 378,747 | $ | 119,316 | 32 | % | ||||||||||||||||||
Volume Variance Impact on Natural Gas Production Revenue (in thousands) | ||||||||||||||||||||||||||||
Price Variance Impact on Natural Gas Production Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | 51,798 | ||||||||||||||||||||||||||
Gulf Coast | $ | (17,317 | ) | 31,200 | ||||||||||||||||||||||||
West | 6,448 | 28,997 | ||||||||||||||||||||||||||
East | 11,170 | |||||||||||||||||||||||||||
Canada | 4,606 | 2,414 | ||||||||||||||||||||||||||
Total Company | $ | 4,907 | $ | 114,409 | ||||||||||||||||||||||||
Volume Variance Impact on Natural Gas Production Revenue (In thousands) | ||||||||||||||||||||||||||||
East | $ | 11,170 | ||||||||||||||||||||||||||
Gulf Coast | (17,317 | ) | ||||||||||||||||||||||||||
West | 6,448 | |||||||||||||||||||||||||||
Canada | 4,606 | |||||||||||||||||||||||||||
Total Company | $ | 4,907 | ||||||||||||||||||||||||||
The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the slight increase in production was due to the successful drilling programs in the East, West and Canada. Partially offsetting this was the decrease in the Gulf Coast production. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $119.3 million.
- 49 -
Index to Financial Statements
Brokered Natural Gas Revenue and Cost
| Year Ended December 31, | Variance | |||||||||||||
| 2005 | 2004 | Amount | Percent | |||||||||||
Sales Price ($/Mcf) | $ | 9.14 | $ | 6.56 | $ | 2.58 | 39 | % | ||||||
Volume Brokered (Mmcf) | 10,793 | 12,876 | (2,083 | ) | (16 | )% | ||||||||
Brokered Natural Gas Revenues (in thousands) | $ | 98,605 | $ | 84,416 | ||||||||||
Purchase Price ($/Mcf) | $ | 8.08 | $ | 5.84 | $ | 2.24 | 38 | % | ||||||
Volume Brokered (Mmcf) | 10,793 | 12,876 | (2,083 | ) | (16 | )% | ||||||||
Brokered Natural Gas Cost (in thousands) | $ | 87,183 | $ | 75,217 | ||||||||||
Brokered Natural Gas Margin (in thousands) | $ | 11,422 | $ | 9,199 | $ | 2,223 | 24 | % | ||||||
(in thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 27,852 | ||||||||||||
Volume Variance Impact on Revenue | (13,664 | ) | ||||||||||||
| $ | 14,188 | |||||||||||||
(in thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (24,130 | ) | |||||||||||
Volume Variance Impact on Purchases | 12,165 | |||||||||||||
| $ | (11,965 | ) | ||||||||||||
Year Ended December 31, | ||||||||||||||
| Variance | ||||||||||||||
| 2005 | 2004 | Amount | Percent | |||||||||||
Sales Price($/Mcf) | $ | 9.14 | $ | 6.56 | $ | 2.58 | 39 | % | ||||||
Volume Brokered (Mmcf) | 10,793 | 12,876 | (2,083 | ) | (16 | %) | ||||||||
Brokered Natural Gas Revenues(In thousands) | $ | 98,605 | $ | 84,416 | ||||||||||
Purchase Price($/Mcf) | $ | 8.08 | $ | 5.84 | $ | 2.24 | 38 | % | ||||||
Volume Brokered(Mmcf) | 10,793 | 12,876 | (2,083 | ) | (16 | %) | ||||||||
Brokered Natural Gas Cost(In thousands) | $ | 87,183 | $ | 75,217 | ||||||||||
Brokered Natural Gas Margin(In thousands) | $ | 11,422 | $ | 9,199 | $ | 2,223 | 24 | % | ||||||
(In thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 27,852 | ||||||||||||
Volume Variance Impact on Revenue | (13,664 | ) | ||||||||||||
| $ | 14,188 | |||||||||||||
(In thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (24,130 | ) | |||||||||||
Volume Variance Impact on Purchases | 12,165 | |||||||||||||
| $ | (11,965 | ) | ||||||||||||
The increased brokered natural gas margin of $2.2 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.
- 50 -
Index to Financial Statements
Crude Oil and Condensate Revenues
Our average total company realized crude oil sales price for 2005, including the realized impact of derivative instruments, was $44.19 per Bbl compared to $31.55 per Bbl for 2004. These prices include the realized impact of derivative instruments, which reduced these prices by $9.93 per Bbl in 2005 and $8.98 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million and the unrealized loss from the change in derivative fair value of $2.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Consolidated Statement of Operations.
| Year Ended December 31, | Variance | Year Ended December 31, | Variance | |||||||||||||||||||||||||
| 2005 | 2004 | Amount | Percent | 2005 | 2004 | Amount | Percent | |||||||||||||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||||||||||||||||
East | 27 | 27 | — | — | ||||||||||||||||||||||||
Gulf Coast | 1,528 | 1,805 | (277 | ) | (15 | )% | 1,528 | 1,805 | (277 | ) | (15 | %) | ||||||||||||||||
West | 166 | 159 | 7 | 4 | % | 166 | 159 | 7 | 4 | % | ||||||||||||||||||
East | 27 | 27 | — | — | ||||||||||||||||||||||||
Canada | 18 | 4 | 14 | 350 | % | 18 | 4 | 14 | 350 | % | ||||||||||||||||||
Total Company | 1,739 | 1,995 | (256 | ) | (13 | )% | 1,739 | 1,995 | (256 | ) | (13 | %) | ||||||||||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||||||||||||||||
East | $ | 53.84 | $ | 38.28 | $ | 15.56 | 41 | % | ||||||||||||||||||||
Gulf Coast | $ | 42.81 | $ | 30.67 | $ | 12.14 | 40 | % | $ | 42.81 | $ | 30.67 | $ | 12.14 | 40 | % | ||||||||||||
West | $ | 55.37 | $ | 40.29 | $ | 15.08 | 37 | % | $ | 55.37 | $ | 40.29 | $ | 15.08 | 37 | % | ||||||||||||
East | $ | 53.84 | $ | 38.28 | $ | 15.56 | 41 | % | ||||||||||||||||||||
Canada | $ | 43.39 | $ | 37.93 | $ | 5.46 | 14 | % | $ | 43.39 | $ | 37.93 | $ | 5.46 | 14 | % | ||||||||||||
Total Company | $ | 44.19 | $ | 31.55 | $ | 12.64 | 40 | % | $ | 44.19 | $ | 31.55 | $ | 12.64 | 40 | % | ||||||||||||
Crude Oil Revenue (in thousands) | ||||||||||||||||||||||||||||
Crude Oil Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | 1,463 | $ | 1,049 | $ | 414 | 39 | % | ||||||||||||||||||||
Gulf Coast | $ | 65,427 | $ | 55,357 | $ | 10,070 | 18 | % | 65,427 | 55,357 | 10,070 | 18 | % | |||||||||||||||
West | 9,155 | 6,404 | 2,751 | 43 | % | 9,155 | 6,404 | 2,751 | 43 | % | ||||||||||||||||||
East | 1,463 | 1,049 | 414 | 39 | % | |||||||||||||||||||||||
Canada | 791 | 129 | 662 | 513 | % | 791 | 129 | 662 | 513 | % | ||||||||||||||||||
Total Company | $ | 76,836 | $ | 62,939 | $ | 13,897 | 22 | % | $ | 76,836 | $ | 62,939 | $ | 13,897 | 22 | % | ||||||||||||
Price Variance Impact on Crude Oil Revenue (in thousands) | ||||||||||||||||||||||||||||
Price Variance Impact on Crude Oil Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | 423 | ||||||||||||||||||||||||||
Gulf Coast | $ | 18,547 | 18,547 | |||||||||||||||||||||||||
West | 2,496 | 2,496 | ||||||||||||||||||||||||||
East | 423 | |||||||||||||||||||||||||||
Canada | 100 | 100 | ||||||||||||||||||||||||||
Total Company | $ | 21,566 | $ | 21,566 | ||||||||||||||||||||||||
Volume Variance Impact on Crude Oil Revenue (in thousands) | ||||||||||||||||||||||||||||
Volume Variance Impact on Crude Oil Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | — | ||||||||||||||||||||||||||
Gulf Coast | $ | (8,492 | ) | (8,492 | ) | |||||||||||||||||||||||
West | 299 | 299 | ||||||||||||||||||||||||||
East | — | |||||||||||||||||||||||||||
Canada | 524 | 524 | ||||||||||||||||||||||||||
Total Company | $ | (7,669 | ) | $ | (7,669 | ) | ||||||||||||||||||||||
The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $13.9 million. The decrease in oil production is primarily the result of the decrease in the Gulf Coast region production due to the continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease, one of our largest areas of offshore oil production.
- 51 -
Index to Financial Statements
Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||||||||||||||||||||
| Realized | Unrealized | Realized | Unrealized | |||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
(In thousands) | Realized | Unrealized | Realized | Unrealized | ||||||||||||||||||||||||||||
Operating Revenues - Increase/(Decrease) to Revenue | ||||||||||||||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||||||||||||||
Natural Gas Production | $ | (98,223 | ) | $ | 1,114 | $ | (54,564 | ) | $ | 137 | $ | (98,223 | ) | $ | 1,114 | $ | (54,564 | ) | $ | 137 | ||||||||||||
Crude Oil | (2,430 | ) | (6 | ) | — | 6 | (2,430 | ) | (6 | ) | — | 6 | ||||||||||||||||||||
Total Cash Flow Hedges | (100,653 | ) | 1,108 | (54,564 | ) | 143 | (100,653 | ) | 1,108 | (54,564 | ) | 143 | ||||||||||||||||||||
Other Derivative Financial Instruments | ||||||||||||||||||||||||||||||||
Natural Gas Production | — | — | (444 | ) | 777 | — | — | (444 | ) | 777 | ||||||||||||||||||||||
Crude Oil | (14,842 | ) | 5,518 | (17,908 | ) | (2,923 | ) | (14,842 | ) | 5,518 | (17,908 | ) | (2,923 | ) | ||||||||||||||||||
Total Other Derivative Financial Instruments | (14,842 | ) | 5,518 | (18,352 | ) | (2,146 | ) | (14,842 | ) | 5,518 | (18,352 | ) | (2,146 | ) | ||||||||||||||||||
| $ | (115,495 | ) | $ | 6,626 | $ | (72,916 | ) | $ | (2,003 | ) | $ | (115,495 | ) | $ | 6,626 | $ | (72,916 | ) | $ | (2,003 | ) | |||||||||||
We are exposed to market risk to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.
Other Operating Revenues
Other operating revenues decreased $3.6 million. This change was primarily a result of an increase in our payout liability associated with the reduction of our interest due to customary reversionary interest owned by others, which correspondingly decreased other operating revenues. In addition, our revenues from net profits interest declined over the prior year. This revenue variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year.
Operating Expenses
Total costs and expenses from operations increased $54.5 million for the year ended December 31, 2005 compared to the year ended December 31, 2004. The primary reasons for this fluctuation are as follows:
Exploration expense increased $13.7 million in 2005, primarily as a result of increased dry hole expenses partially offset by decreased spending on geological and geophysical expenses. During 2005, we spent $6.8 million less on geological and geophysical activities but incurred an additional $18.9 million in dry hole expense. In addition, we spent an additional $0.8 million on delay rentals. The increase in dry hole expense is mainly due to expenses incurred in the Gulf Coast and, to a smaller extent, in Canada and the West.
Taxes Other Than Income increased by $13.3 million from 2004 compared to 2005, primarily due to increased production taxes as a result of increased commodity prices. Additionally, ad valorem and franchise taxes were higher compared to the prior year.
Brokered Natural Gas Cost increased by $12.0 million from 2004 to 2005. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.
Direct Operations expense increased by $8.2 million. This is primarily the result of increased expenses for outside operated properties and workovers. In addition, there were increases over the prior year in maintenance charges, equipment expenses and employee related expenses.
Depreciation, Depletion and Amortization increased by $5.1 million in 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production in the East and West regions.
- 52 -
Index to Financial Statements
Impairment of Oil and Gas Properties decreased by $3.5 million as we incurred no impairment expense in the current year. The costs incurred in the prior year related to a field in south Louisiana. Further analysis of this impairment is discussed in Note 2 of the Notes to the Consolidated Financial Statements.
Impairment of Unproved Properties increased $2.8 million over the prior year. This is due to increased amortization related to unproved property additions both offshore and onshore, including an increase in our Canadian additions.
General and Administrative expense increased by $2.9 million in 2005. This increase is primarily due to increased stock compensation expense relating to performance share awards, increased professional services fees and higher employee related expenses. Partially offsetting these increases was a decrease in miscellaneous expenses, primarily due to the reversal of the reserve attributable to litigation that was settled in the 2005 period.
Interest Expense, Net
Interest expense, net increased $0.1 million. Interest expense related to borrowings under our revolving credit facility was higher in the current year due to higher average borrowings. AverageWeighted average borrowings based on month enddaily balances for the 2005 year were approximately $130$32 million during 2005 compared to approximately $95$10 million in the prior year.during 2004. In addition, the effective interest rate on the credit facility increased to 6.9% during 2005 from 4.2% during the prior year. Partially offsetting this was an increase in interest income on our short-term investments.
Income Tax Expense
Income tax expense increased $37.6 million due to an increase in our pre-tax net income.
The effective tax rates for 2005 and 2004 were 37.2% and 2003 Compared
We reported net income for the year ended December 31, 2004 of $88.4 million, or $1.81 per share. During 2003, we reported net income of $21.1 million, or $0.44 per share. Operating income increased by $94.1 million compared to the prior year, from $66.6 million to $160.7 million. The increase in net income and operating income was principally due to decreased operating expenses from 2003 to 2004 related to the decrease in impairments of oil and gas properties of $90.3 million related to the loss in 2003 of a reversionary interest in the Kurten field. In addition, the increases in operating income and net income were due to an increase in our realized natural gas and crude oil prices.
Natural Gas Production Revenues
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.20 per Mcf compared to $4.51 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.76 per Mcf in 2004 and $0.68 per Mcf in 2003. The following table excludes the unrealized gain from the change in derivative fair value of $0.9 million and the unrealized loss of $1.5 million for the years ended December 31, 2004 and 2003,36.2%, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.
Natural Gas Production (Mmcf) Gulf Coast West East Canada Total Company Natural Gas Production Sales Price ($/Mcf) Gulf Coast West East Canada Total Company Natural Gas Production Revenue (in thousands) Gulf Coast West East Canada Total Company Price Variance Impact on Natural Gas Production Revenue (in thousands) Gulf Coast West East Canada Total Company Volume Variance Impact on Natural Gas Production Revenue (in thousands) Gulf Coast West East Canada Total Company Year Ended
December 31, Variance 2004 2003 Amount Percent 31,358 29,550 1,808 6 % 21,866 23,776 (1,910 ) (8 )% 19,442 18,580 862 5 % 167 — 167 — 72,833 71,906 927 1 % $ 5.27 $ 4.78 $ 0.49 10 % $ 4.75 $ 3.67 $ 1.08 29 % $ 5.60 $ 5.15 $ 0.45 9 % $ 4.69 $ — $ 4.69 — $ 5.20 $ 4.51 $ 0.69 15 % $ 165,177 $ 141,107 $ 24,070 17 % 103,851 87,245 16,606 19 % 108,935 95,672 13,263 14 % 784 — 784 — $ 378,747 $ 324,024 $ 54,723 17 % $ 15,434 23,613 8,828 784 $ 48,659 $ 8,635 (7,009 ) 4,438 — $ 6,064
The increase in natural gas production revenues was mainly a result of increased sales prices as well as the increase in overall production. Natural gas production was up slightly from the prior year and production revenues also increased from 2003. Natural gas production increased slightly in all regions except the West region, where the decline in production was due to lower capital spending in 2003 and continued natural decline. The increases in both sales price and production resulted in an increase in natural gas production revenues of $54.7 million.
Brokered Natural Gas Revenue and Cost
| Year Ended December 31, | Variance | |||||||||||||
| 2004 | 2003 | Amount | Percent | |||||||||||
Sales Price ($/Mcf) | $ | 6.56 | $ | 5.16 | $ | 1.40 | 27 | % | ||||||
Volume Brokered (Mmcf) | 12,876 | 18,557 | (5,681 | ) | (31 | )% | ||||||||
Brokered Natural Gas Revenues (in thousands) | $ | 84,416 | $ | 95,754 | ||||||||||
Purchase Price ($/Mcf) | $ | 5.84 | $ | 4.64 | $ | 1.20 | 26 | % | ||||||
Volume Brokered (Mmcf) | 12,876 | 18,557 | (5,681 | ) | (31 | )% | ||||||||
Brokered Natural Gas Cost (in thousands) | $ | 75,217 | $ | 86,104 | ||||||||||
Brokered Natural Gas Margin (in thousands) | $ | 9,199 | $ | 9,650 | $ | (451 | ) | (5 | )% | |||||
(in thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 18,026 | ||||||||||||
Volume Variance Impact on Revenue | (29,363 | ) | ||||||||||||
| $ | (11,337 | ) | ||||||||||||
(in thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (15,451 | ) | |||||||||||
Volume Variance Impact on Purchases | 26,338 | |||||||||||||
| $ | 10,887 | |||||||||||||
The decrease in brokered natural gas revenues of $11.3 million combined with the decline in brokered natural gas cost of $10.9 million resulted in a decrease to the brokered natural gas margin of $0.5 million.
Crude Oil and Condensate Revenues
Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.55 per Bbl compared to $29.55 per Bbl for 2003. These prices include the realized impact of derivative instruments, which reduced these prices by $8.98 per Bbl in 2004 and $1.41 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million and $1.9 million for the years ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.
| Year Ended December 31, | Variance | |||||||||||||
| 2004 | 2003 | Amount | Percent | |||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||
Gulf Coast | 1,805 | 2,591 | (786 | ) | (30 | )% | ||||||||
West | 159 | 188 | (29 | ) | (15 | )% | ||||||||
East | 27 | 27 | — | — | ||||||||||
Canada | 4 | — | 4 | — | ||||||||||
Total Company | 1,995 | 2,806 | (811 | ) | (29 | %) | ||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||
Gulf Coast | $ | 30.67 | $ | 29.48 | $ | 1.19 | 4 | % | ||||||
West | $ | 40.29 | $ | 30.11 | $ | 10.18 | 34 | % | ||||||
East | $ | 38.28 | $ | 32.65 | $ | 5.63 | 17 | % | ||||||
Canada | $ | 37.93 | $ | — | $ | 37.93 | — | |||||||
Total Company | $ | 31.55 | $ | 29.55 | $ | 2.00 | 7 | % | ||||||
Crude Oil Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | 55,357 | $ | 76,375 | $ | (21,018 | ) | (28 | %) | |||||
West | 6,404 | 5,675 | 729 | 13 | % | |||||||||
East | 1,049 | 870 | 179 | 21 | % | |||||||||
Canada | 129 | — | 129 | — | ||||||||||
Total Company | $ | 62,939 | $ | 82,920 | $ | (19,981 | ) | (24 | %) | |||||
Price Variance Impact on Crude Oil Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | 2,151 | ||||||||||||
West | 1,604 | |||||||||||||
East | 179 | |||||||||||||
Canada | 129 | |||||||||||||
Total Company | $ | 4,063 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | (23,169 | ) | |||||||||||
West | (875 | ) | ||||||||||||
East | — | |||||||||||||
Canada | — | |||||||||||||
Total Company | $ | (24,044 | ) | |||||||||||
The decline in crude oil production is due to emphasis on natural gas in the Gulf Coast drilling program, along with the natural decline of existing production in south Louisiana. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $20.0 million.
Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
| Year Ended December 31, | ||||||||||||||||
| 2004 | 2003 | |||||||||||||||
| Realized | Unrealized | Realized | Unrealized | |||||||||||||
| (In thousands) | ||||||||||||||||
Operating Revenues - Increase/(Decrease) to Revenue | ||||||||||||||||
Cash Flow Hedges | ||||||||||||||||
Natural Gas Production | $ | (54,564 | ) | $ | 137 | $ | (48,829 | ) | $ | (691 | ) | |||||
Crude Oil | — | 6 | (2,973 | ) | 32 | |||||||||||
Total Cash Flow Hedges | (54,564 | ) | 143 | (51,802 | ) | (659 | ) | |||||||||
Other Derivative Financial Instruments | ||||||||||||||||
Natural Gas Production | (444 | ) | 777 | — | (777 | ) | ||||||||||
Crude Oil | (17,908 | ) | (2,923 | ) | (990 | ) | (1,911 | ) | ||||||||
Total Other Derivative Financial Instruments | (18,352 | ) | (2,146 | ) | (990 | ) | (2,688 | ) | ||||||||
| $ | (72,916 | ) | $ | (2,003 | ) | $ | (52,792 | ) | $ | (3,347 | ) | |||||
We are exposed to market risk to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.
Other Operating Revenues
Other operating revenues decreased $3.7 million. This change was primarily a result of decreases in natural gas transportation revenue and natural gas liquid revenue for the year ended December 31, 2004.
Operating Expenses
Total costs and expenses from operations decreased $85.3 million for the year ended December 31, 2004 compared to the year ended December 31, 2003. The primary reasons for this fluctuation are as follows:
Interest Expense, Net
Interest expense decreased $1.7 million. This variance is due to a lower average level of outstanding debt on the revolving credit facility offset somewhat by an increase in Prime rates. Average daily borrowings under the revolving credit facility during the year were $0.5 million in 2004 which is a decrease from $0.7 million in 2003. Our other remaining debt is at fixed interest rates.
Income Tax Expense
Income tax expense increased $35.2 million due to an increase in our pre-tax net income.
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Derivative Instruments and Hedging Activity
Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 1011 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Under our revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2005,2006, we had nine20 cash flow hedges open: eight19 natural gas price collar arrangements and one crude oil price collar arrangement. At December 31, 2005, a $20.72006, an $82.0 million ($12.951.2 million, net of tax) unrealized lossgain was recorded to Accumulated Other Comprehensive Income, along with a $22.4an $82.0 million short-term derivative liability and a $1.7 million short-term derivative receivable, which is shown in Other Current Assets on the Balance Sheet.receivable. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate.
Assuming no change in commodity prices, after December 31, 20052006 we would expect to reclassify to the Consolidated Statement of Operations, over the next 12 months, $12.9$51.2 million in after-tax chargesincome associated with commodity hedges. This reclassification represents the net liabilityshort-term receivable associated with open positions currently not reflected in earnings at December 31, 20052006 related to anticipated 20062007 production.
Hedges on Production
- Swaps
From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2005, natural gas price swaps covered 20,557 Mmcf, or 28% of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.
At December 31, 2005, we had no open natural gas price swap contracts covering 2006 production.
From time to time, we enter into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2005, we did not have any of these types of arrangements.53 -
Index to Financial Statements
Hedges on Production - Options
From time to time, we enter into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During 2005,2006, natural gas price collars covered 15,15727,179 Mmcf of our gas production, or 21%34% of our gas production with a weighted average floor of $5.59$8.25 per Mcf and a weighted average ceiling of $8.61$12.74 per Mcf. During 2005,2006, an oil price collar covered 365 Mbbl of our crude oil production, or 21%26% of our crude oil production with a weightedan average floor of $40.00$50.00 per Mbbl and a weightedan average ceiling of $50.50$76.00 per Mbbl.
At December 31, 2005,2006, we had open natural gas price collar contracts covering our 20062007 production as follows:
| Natural Gas Price Collars | |||||||||
Contract Period | Volume in Mmcf | Weighted Average Ceiling / Floor | Net Unrealized (In thousands) | ||||||
As of December 31, 2005 | |||||||||
First Quarter 2006 | 6,702 | $ | 12.74 / $8.25 | ||||||
Second Quarter 2006 | 6,776 | 12.74 / 8.25 | |||||||
Third Quarter 2006 | 6,850 | 12.74 / 8.25 | |||||||
Fourth Quarter 2006 | 6,851 | 12.74 / 8.25 | |||||||
Full Year 2006 | 27,179 | $ | 12.74 / $8.25 | $ | (20,425 | ) | |||
| Natural Gas Price Collars | ||||||||
Contract Period | Volume in Mmcf | Weighted Average | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2006 | ||||||||
First Quarter 2007 | 10,487 | $ | 12.19 / $8.99 | |||||
Second Quarter 2007 | 10,604 | 12.19 / 8.99 | ||||||
Third Quarter 2007 | 10,721 | 12.19 / 8.99 | ||||||
Fourth Quarter 2007 | 10,721 | 12.19 / 8.99 | ||||||
Full Year 2007 | 42,533 | $ | 12.19 / $8.99 | $ | 81,393 | |||
At December 31, 2005,2006, we had one open crude oil price collar contract covering our 20062007 production as follows:
| Crude Oil Price Collar | |||||||||
Contract Period | Volume in Mbbl | Weighted Average Ceiling / Floor | Net Unrealized (In thousands) | ||||||
As of December 31, 2005 | |||||||||
First Quarter 2006 | 90 | $ | 76.00 / $50.00 | ||||||
Second Quarter 2006 | 91 | 76.00 / 50.00 | |||||||
Third Quarter 2006 | 92 | 76.00 / 50.00 | |||||||
Fourth Quarter 2006 | 92 | 76.00 / 50.00 | |||||||
Full Year 2006 | 365 | $ | 76.00 / $50.00 | $ | (317 | ) | |||
| �� | |||||||||
| Crude Oil Price Collar | ||||||||
Contract Period | Volume Mbbl | Average Ceiling / Floor (per Bbl) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2006 | ||||||||
First Quarter 2007 | 90 | $ | 80.00 / $60.00 | |||||
Second Quarter 2007 | 91 | 80.00 / 60.00 | ||||||
Third Quarter 2007 | 92 | 80.00 / 60.00 | ||||||
Fourth Quarter 2007 | 92 | 80.00 / 60.00 | ||||||
Full Year 2007 | 365 | $ | 80.00 / $60.00 | $ | 589 | |||
We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.
The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.
- 54 -
Index to Financial Statements
Fair Market Value of Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” and does not impact our financial position, results of operations or cash flows.
Long-Term Debt
| December 31, 2005 | December 31, 2004 | December 31, 2006 | December 31, 2005 | |||||||||||||||||||||||||
(In thousands) | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||||||||||
Debt | ||||||||||||||||||||||||||||
Long-Term Debt | ||||||||||||||||||||||||||||
7.19% Notes | $ | 60,000 | $ | 62,938 | $ | 80,000 | $ | 87,770 | $ | 60,000 | $ | 61,749 | $ | 80,000 | $ | 83,295 | ||||||||||||
7.26% Notes | 75,000 | 81,713 | 75,000 | 85,849 | 75,000 | 80,335 | 75,000 | 81,713 | ||||||||||||||||||||
7.36% Notes | 75,000 | 83,990 | 75,000 | 87,111 | 75,000 | 82,025 | 75,000 | 83,990 | ||||||||||||||||||||
7.46% Notes | 20,000 | 23,083 | 20,000 | 23,804 | 20,000 | 22,547 | 20,000 | 23,083 | ||||||||||||||||||||
Credit Facility | 90,000 | 90,000 | — | — | 10,000 | 10,000 | 90,000 | 90,000 | ||||||||||||||||||||
Current Maturities | ||||||||||||||||||||||||||||
7.19% Notes | (20,000 | ) | (20,299 | ) | (20,000 | ) | (20,357 | ) | ||||||||||||||||||||
Long-Term Debt, excluding Current Maturities | $ | 220,000 | $ | 236,357 | $ | 320,000 | $ | 341,724 | ||||||||||||||||||||
| $ | 320,000 | $ | 341,724 | $ | 250,000 | $ | 284,534 | |||||||||||||||||||||
- 55 -
Index to Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
- 56 -
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:
We have completed integrated audits of Cabot Oil & Gas Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements2006 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 20052006 and 2004,2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20052006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 11Notes 1 and 5 to the consolidated financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting158 “Employers’ Accounting for Asset Retirement Obligations”Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” As discussed in Notes 1 and 10 to the consolidated financial statements, effective January 1, 2003.2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share Based Payment (revised 2004).”
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 20052006 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005,2006, based on criteria established inInternal Control – Integrated Framework issued by the COSO. The Company’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 opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes 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 consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
- 57 -
Index to Financial Statements
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
| /s/ PricewaterhouseCoopers LLP | ||
Houston, Texas February 28, 2007 | ||
Houston, Texas
March6, 2006- 58 -
Index to Financial Statements
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||||||
OPERATING REVENUES | |||||||||||||||||||||
Natural Gas Production | $ | 499,177 | $ | 379,661 | $ | 322,556 | $ | 568,097 | $ | 499,177 | $ | 379,661 | |||||||||
Brokered Natural Gas | 98,605 | 84,416 | 95,816 | 93,651 | 98,605 | 84,416 | |||||||||||||||
Crude Oil and Condensate | 82,348 | 60,022 | 81,040 | 91,380 | 82,348 | 60,022 | |||||||||||||||
Other | 2,667 | 6,309 | 9,979 | 8,860 | 2,667 | 6,309 | |||||||||||||||
| 682,797 | 530,408 | 509,391 | 761,988 | 682,797 | 530,408 | ||||||||||||||||
OPERATING EXPENSES | |||||||||||||||||||||
Brokered Natural Gas Cost | 87,183 | 75,217 | 86,162 | 83,375 | 87,183 | 75,217 | |||||||||||||||
Direct Operations - Field and Pipeline | 61,750 | 53,581 | 50,399 | 74,790 | 61,750 | 53,581 | |||||||||||||||
Exploration | 61,840 | 48,130 | 58,119 | 49,397 | 61,840 | 48,130 | |||||||||||||||
Depreciation, Depletion and Amortization | 108,458 | 103,343 | 94,903 | 128,975 | 108,458 | 103,343 | |||||||||||||||
Impairment of Unproved Properties | 12,966 | 10,145 | 9,348 | 11,117 | 12,966 | 10,145 | |||||||||||||||
Impairment of Oil & Gas Properties (Note 2) | — | 3,458 | 93,796 | 3,886 | — | 3,458 | |||||||||||||||
General and Administrative | 37,650 | 34,735 | 25,112 | 58,168 | 37,650 | 34,735 | |||||||||||||||
Taxes Other Than Income | 54,293 | 41,022 | 37,138 | 55,351 | 54,293 | 41,022 | |||||||||||||||
| 424,140 | 369,631 | 454,977 | 465,059 | 424,140 | 369,631 | ||||||||||||||||
Gain / (Loss) on Sale of Assets | 74 | (124 | ) | 12,173 | 232,017 | 74 | (124 | ) | |||||||||||||
INCOME FROM OPERATIONS | 258,731 | 160,653 | 66,587 | 528,946 | 258,731 | 160,653 | |||||||||||||||
Interest Expense and Other | 22,497 | 22,029 | 23,545 | 18,441 | 22,497 | 22,029 | |||||||||||||||
Income Before Income Taxes and Cumulative Effect of Accounting Change | 236,234 | 138,624 | 43,042 | ||||||||||||||||||
Income Before Income Taxes | 510,505 | 236,234 | 138,624 | ||||||||||||||||||
Income Tax Expense | 87,789 | 50,246 | 15,063 | 189,330 | 87,789 | 50,246 | |||||||||||||||
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE | 148,445 | 88,378 | 27,979 | ||||||||||||||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 11) | — | — | (6,847 | ) | |||||||||||||||||
NET INCOME | $ | 148,445 | $ | 88,378 | $ | 21,132 | $ | 321,175 | $ | 148,445 | $ | 88,378 | |||||||||
Basic Earnings Per Share - Before Accounting Change | $ | 3.04 | $ | 1.81 | $ | 0.58 | |||||||||||||||
Diluted Earnings Per Share - Before Accounting Change | $ | 2.99 | $ | 1.79 | $ | 0.58 | |||||||||||||||
Basic Loss Per Share - Accounting Change | $ | — | $ | — | $ | (0.14 | ) | ||||||||||||||
Diluted Loss Per Share - Accounting Change | $ | — | $ | — | $ | (0.14 | ) | ||||||||||||||
Basic Earnings Per Share | $ | 3.04 | $ | 1.81 | $ | 0.44 | $ | 6.64 | $ | 3.04 | $ | 1.81 | |||||||||
Diluted Earnings Per Share | $ | 2.99 | $ | 1.79 | $ | 0.44 | $ | 6.51 | $ | 2.99 | $ | 1.79 | |||||||||
| — | |||||||||||||||||||||
Weighted Average Common Shares Outstanding | 48,856 | 48,733 | 48,074 | 48,402 | 48,856 | 48,733 | |||||||||||||||
Diluted Common Shares (Note 12) | 49,725 | 49,339 | 48,435 | ||||||||||||||||||
Diluted Common Shares (Note 13) | 49,300 | 49,725 | 49,339 | ||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements
CONSOLIDATED BALANCE SHEET
(In thousands, except share amounts)
| December 31, | December 31, | |||||||||||||||
| 2005 | 2004 | 2006 | 2005 | |||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and Cash Equivalents | $ | 10,626 | $ | 10,026 | $ | 41,854 | $ | 10,626 | ||||||||
Accounts Receivable | 168,248 | 125,754 | ||||||||||||||
Accounts Receivable, Net | 116,546 | 156,009 | ||||||||||||||
Income Taxes Receivable | 24,512 | 12,239 | ||||||||||||||
Inventories | 24,616 | 24,049 | 32,997 | 24,616 | ||||||||||||
Deferred Income Taxes | 15,674 | 21,345 | 9,386 | 15,674 | ||||||||||||
Derivative Contracts | 81,982 | 1,736 | ||||||||||||||
Other | 11,148 | 13,505 | 8,405 | 9,412 | ||||||||||||
Total Current Assets | 230,312 | 194,679 | 315,682 | 230,312 | ||||||||||||
Properties and Equipment, Net (Successful Efforts Method) | 1,238,055 | 994,081 | 1,480,201 | 1,238,055 | ||||||||||||
Deferred Income Taxes | 19,587 | 14,855 | 30,912 | 19,587 | ||||||||||||
Other Assets | 7,416 | 7,341 | 7,696 | 7,416 | ||||||||||||
| $ | 1,495,370 | $ | 1,210,956 | $ | 1,834,491 | $ | 1,495,370 | |||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Accounts Payable | $ | 140,006 | $ | 104,969 | $ | 147,680 | $ | 140,006 | ||||||||
Current Portion of Long-Term Debt | 20,000 | 20,000 | 20,000 | 20,000 | ||||||||||||
Deferred Income Taxes | 941 | 944 | 31,962 | 941 | ||||||||||||
Derivative Contracts | 22,478 | 38,368 | — | 22,478 | ||||||||||||
Income Taxes Payable | 9,282 | 41 | ||||||||||||||
Accrued Liabilities | 35,159 | 32,608 | 42,103 | 35,118 | ||||||||||||
Total Current Liabilities | 218,584 | 196,889 | 251,027 | 218,584 | ||||||||||||
Long-Term Debt | 320,000 | 250,000 | ||||||||||||||
Long-Term Liability for Pension Benefits (Note 5) | 7,219 | 5,904 | ||||||||||||||
Long-Term Liability for Postretirement Benefits (Note 5) | 18,204 | 6,517 | ||||||||||||||
Long-Term Debt (Note 4) | 220,000 | 320,000 | ||||||||||||||
Deferred Income Taxes | 289,381 | 247,376 | 347,430 | 289,381 | ||||||||||||
Other Liabilities | 67,194 | 61,029 | 45,413 | 54,773 | ||||||||||||
Commitments and Contingencies (Note 7) | ||||||||||||||||
Stockholders’ Equity | ||||||||||||||||
Common Stock: | ||||||||||||||||
Authorized — 80,000,000 Shares of $.10 Par Value Issued — 50,081,983 Shares and 49,680,915 Shares in 2005 and 2004, respectively | 5,008 | 4,968 | ||||||||||||||
Authorized — 120,000,000 and 80,000,000 Shares of $.10 Par Value in 2006 and 2005, respectively | ||||||||||||||||
Issued — 50,709,110 Shares and 50,081,983 Shares in 2006 and 2005, respectively | 5,071 | 5,008 | ||||||||||||||
Additional Paid-in Capital | 397,349 | 380,125 | 423,066 | 397,349 | ||||||||||||
Retained Earnings | 252,167 | 110,935 | 565,591 | 252,167 | ||||||||||||
Accumulated Other Comprehensive Loss | (15,115 | ) | (20,351 | ) | ||||||||||||
Accumulated Other Comprehensive Income / (Loss) (Note 14) | 37,160 | (15,115 | ) | |||||||||||||
Less Treasury Stock, at Cost: | ||||||||||||||||
1,513,850 and 1,061,550 Shares in 2005 and 2004, respectively | (39,198 | ) | (20,015 | ) | ||||||||||||
2,602,350 and 1,513,850 Shares in 2006 and 2005, respectively | (85,690 | ) | (39,198 | ) | ||||||||||||
Total Stockholders’ Equity | 600,211 | 455,662 | 945,198 | 600,211 | ||||||||||||
| $ | 1,495,370 | $ | 1,210,956 | $ | 1,834,491 | $ | 1,495,370 | |||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Index to Financial Statements
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | |||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||||||||||
Net Income | $ | 148,445 | $ | 88,378 | $ | 21,132 | $ | 321,175 | $ | 148,445 | $ | 88,378 | ||||||||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||||||||||||||
Cumulative Effect of Accounting Change | — | — | 6,847 | |||||||||||||||||||||
Depreciation, Depletion and Amortization | 108,458 | 103,343 | 94,903 | 128,975 | 108,458 | 103,343 | ||||||||||||||||||
Impairment of Unproved Properties | 12,966 | 10,145 | 9,348 | 11,117 | 12,966 | 10,145 | ||||||||||||||||||
Impairment of Oil & Gas Properties | — | 3,458 | 93,796 | 3,886 | — | 3,458 | ||||||||||||||||||
Deferred Income Tax Expense | 39,628 | 31,769 | (9,837 | ) | 52,011 | 39,628 | 31,769 | |||||||||||||||||
(Gain) / Loss on Sale of Assets | (74 | ) | 124 | (12,173 | ) | (232,017 | ) | (74 | ) | 124 | ||||||||||||||
Exploration Expense | 61,840 | 48,130 | 58,119 | 49,397 | 61,840 | 48,130 | ||||||||||||||||||
Unrealized Change in Derivative Fair Value | (6,626 | ) | 2,003 | 3,347 | ||||||||||||||||||||
Performance Share Compensation | 3,357 | 3,429 | — | |||||||||||||||||||||
Unrealized (Gain) / Loss on Derivatives | — | (6,626 | ) | 2,003 | ||||||||||||||||||||
Stock-Based Compensation Expense and Other | 6,446 | 3,475 | 885 | 21,271 | 9,803 | 6,904 | ||||||||||||||||||
Changes in Assets and Liabilities: | ||||||||||||||||||||||||
Accounts Receivable | (42,494 | ) | (39,404 | ) | (17,397 | ) | 39,463 | (43,938 | ) | (50,200 | ) | |||||||||||||
Income Taxes Receivable | (11,198 | ) | 1,444 | 10,796 | ||||||||||||||||||||
Inventories | (567 | ) | (5,808 | ) | (2,989 | ) | (8,381 | ) | (567 | ) | (5,808 | ) | ||||||||||||
Other Current Assets | 1,188 | 3,255 | (9,208 | ) | 1,007 | 1,188 | 3,255 | |||||||||||||||||
Other Assets | (192 | ) | (491 | ) | 163 | (733 | ) | (192 | ) | (491 | ) | |||||||||||||
Accounts Payable and Accrued Liabilities | 29,803 | 17,231 | 7,041 | (29,694 | ) | 26,147 | 17,254 | |||||||||||||||||
Income Taxes Payable | 18,398 | 3,656 | (23 | ) | ||||||||||||||||||||
Other Liabilities | 2,382 | 3,985 | (2,339 | ) | 1,912 | 2,382 | 3,985 | |||||||||||||||||
Stock-Based Compensation Tax Benefit | (9,485 | ) | — | — | ||||||||||||||||||||
Net Cash Provided by Operating Activities | 364,560 | 273,022 | 241,638 | 357,104 | 364,560 | 273,022 | ||||||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||||||||||
Capital Expenditures | (351,306 | ) | (207,346 | ) | (122,018 | ) | (467,430 | ) | (351,306 | ) | (207,346 | ) | ||||||||||||
Proceeds from Sale of Assets | 996 | 119 | 28,281 | 329,474 | 996 | 119 | ||||||||||||||||||
Exploration Expense | (61,840 | ) | (48,130 | ) | (58,119 | ) | (49,397 | ) | (61,840 | ) | (48,130 | ) | ||||||||||||
Net Cash Used by Investing Activities | (412,150 | ) | (255,357 | ) | (151,856 | ) | ||||||||||||||||||
Net Cash Used in Investing Activities | (187,353 | ) | (412,150 | ) | (255,357 | ) | ||||||||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||||||||||
Increase in Debt | 265,000 | 187,000 | 248,655 | 205,000 | 265,000 | 187,000 | ||||||||||||||||||
Decrease in Debt | (195,000 | ) | (187,000 | ) | (341,000 | ) | (305,000 | ) | (195,000 | ) | (187,000 | ) | ||||||||||||
Sale of Common Stock Proceeds | 4,586 | 12,474 | 6,728 | 6,235 | 4,586 | 12,474 | ||||||||||||||||||
Stock-Based Compensation Tax Benefit | 9,485 | — | — | |||||||||||||||||||||
Purchase of Treasury Stock | (19,183 | ) | (15,631 | ) | — | (46,492 | ) | (19,183 | ) | (15,631 | ) | |||||||||||||
Dividends Paid | (7,213 | ) | (5,206 | ) | (5,043 | ) | (7,751 | ) | (7,213 | ) | (5,206 | ) | ||||||||||||
Net Cash Provided / (Used) by Financing Activities | 48,190 | (8,363 | ) | (90,660 | ) | |||||||||||||||||||
Net Cash (Used in) / Provided by Financing Activities | (138,523 | ) | 48,190 | (8,363 | ) | |||||||||||||||||||
Net Increase / (Decrease) in Cash and Cash Equivalents | 600 | 9,302 | (878 | ) | ||||||||||||||||||||
Net Increase in Cash and Cash Equivalents | 31,228 | 600 | 9,302 | |||||||||||||||||||||
Cash and Cash Equivalents, Beginning of Period | 10,026 | 724 | 1,602 | 10,626 | 10,026 | 724 | ||||||||||||||||||
Cash and Cash Equivalents, End of Period | $ | 10,626 | $ | 10,026 | $ | 724 | $ | 41,854 | $ | 10,626 | $ | 10,026 | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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Index to Financial Statements
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)
| Common Shares | Stock Par | Treaury Shares | Treasury Stock | Paid-In Capital | Accumulated (Loss) | Retained Earnings | Total | |||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2002 | 48,200 | $ | 4,820 | 454 | $ | (4,384 | ) | $ | 351,486 | $ | (12,939 | ) | $ | 11,674 | $ | 350,657 | ||||||||||||||||||||||||||||||||||||
Net Income | 21,132 | 21,132 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Exercise of Stock Options | 517 | 52 | 7,716 | 7,768 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (5,043 | ) | (5,043 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Loss | (10,196 | ) | (10,196 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Stock Grant Vesting | 90 | 9 | 870 | 879 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Common Shares | Stock Par | Treasury Shares | Treasury Stock | Paid-In Capital | Accumulated Other Comprehensive Income (Loss)(1) | Retained Earnings | Total | |||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2003 | 48,807 | $ | 4,881 | 454 | $ | (4,384 | ) | $ | 360,072 | $ | (23,135 | ) | $ | 27,763 | $ | 365,197 | 48,807 | $ | 4,881 | 454 | $ | (4,384 | ) | $ | 360,072 | $ | (23,135 | ) | $ | 27,763 | $ | 365,197 | ||||||||||||||||||||
Net Income | 88,378 | 88,378 | 88,378 | 88,378 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exercise of Stock Options | 794 | 79 | 15,034 | 15,113 | 794 | 79 | 12,392 | 12,471 | ||||||||||||||||||||||||||||||||||||||||||||
Purchase of Treasury Stock | 608 | (15,631 | ) | (15,631 | ) | 608 | (15,631 | ) | (15,631 | ) | ||||||||||||||||||||||||||||||||||||||||||
Performance Share Awards | 2,394 | 2,394 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Stock Grant Vesting | 80 | 8 | 2,625 | 2,633 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (5,206 | ) | (5,206 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Tax Benefit of Stock-Based Compensation | 2,642 | 2,642 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Stock Amortization and Vesting | 80 | 8 | 5,019 | 5,027 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.107 per Share | (5,206 | ) | (5,206 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 2,784 | 2,784 | 2,784 | 2,784 | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2004 | 49,681 | $ | 4,968 | 1,062 | $ | (20,015 | ) | $ | 380,125 | $ | (20,351 | ) | $ | 110,935 | $ | 455,662 | 49,681 | $ | 4,968 | 1,062 | $ | (20,015 | ) | $ | 380,125 | $ | (20,351 | ) | $ | 110,935 | $ | 455,662 | ||||||||||||||||||||
Net Income | 148,445 | 148,445 | 148,445 | 148,445 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exercise of Stock Options | 300 | 30 | 8,217 | 8,247 | 300 | 30 | 4,555 | 4,585 | ||||||||||||||||||||||||||||||||||||||||||||
Purchase of Treasury Stock | 452 | (19,183 | ) | (19,183 | ) | 452 | (19,183 | ) | (19,183 | ) | ||||||||||||||||||||||||||||||||||||||||||
Performance Share Awards | 4,147 | 4,147 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Stock Grant Vesting | 101 | 10 | 4,860 | 4,870 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (7,213 | ) | (7,213 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Tax Benefit of Stock-Based Compensation | 3,662 | 3,662 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Stock Amortization and Vesting | 101 | 10 | 9,007 | 9,017 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.147 per Share | (7,213 | ) | (7,213 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 5,236 | 5,236 | 5,236 | 5,236 | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2005 | 50,082 | $ | 5,008 | 1,514 | $ | (39,198 | ) | $ | 397,349 | $ | (15,115 | ) | $ | 252,167 | $ | 600,211 | 50,082 | $ | 5,008 | 1,514 | $ | (39,198 | ) | $ | 397,349 | $ | (15,115 | ) | $ | 252,167 | $ | 600,211 | ||||||||||||||||||||
Net Income | 321,175 | 321,175 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Exercise of Stock Options | 438 | 44 | 6,171 | 6,215 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchase of Treasury Stock | 1,088 | (46,492 | ) | (46,492 | ) | |||||||||||||||||||||||||||||||||||||||||||||||
Tax Benefit of Stock-Based Compensation | 9,485 | 9,485 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Stock Amortization and Vesting | 189 | 19 | 10,061 | 10,080 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (7,751 | ) | (7,751 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of Adoption of SFAS No. 158 | (14,079 | ) | (14,079 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | 66,354 | 66,354 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2006 | 50,709 | $ | 5,071 | 2,602 | $ | (85,690 | ) | $ | 423,066 | $ | 37,160 | $ | 565,591 | $ | 945,198 | |||||||||||||||||||||||||||||||||||||
(1) | For further details on the components of Accumulated Other Comprehensive Income and Loss, refer to Note 14 of the Notes to the Consolidated Financial Statements |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Net Income | $ | 148,445 | $ | 88,378 | $ | 21,132 | ||||||
Other Comprehensive Income / (Loss) | ||||||||||||
Reclassification Adjustment for Settled Contracts | 100,653 | 53,516 | 47,926 | |||||||||
Changes in Fair Value of Hedge Positions | (92,559 | ) | (48,494 | ) | (63,014 | ) | ||||||
Minimum Pension Liability | (205 | ) | (1,404 | ) | (1,333 | ) | ||||||
Foreign Currency Translation Adjustment | 808 | 662 | (5 | ) | ||||||||
Deferred Income Tax | (3,461 | )(1) | (1,496 | )(2) | 6,230 | (3) | ||||||
Total Other Comprehensive Income / (Loss) | 5,236 | 2,784 | (10,196 | ) | ||||||||
Comprehensive Income | $ | 153,681 | $ | 91,162 | $ | 10,936 | ||||||
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Net Income | $ | 321,175 | $ | 148,445 | $ | 88,378 | ||||||
Other Comprehensive Income, net of taxes | ||||||||||||
Reclassification Adjustment for Settled Contracts, net of taxes of $10,686, ($38,404) and ($20,394), respectively | (17,580 | ) | 62,249 | 33,122 | ||||||||
Changes in Fair Value of Hedge Positions, net of taxes of ($49,311), $35,293 and $18,486, respectively | 81,679 | (57,266 | ) | (30,008 | ) | |||||||
Minimum Pension Liability, net of taxes of ($1,848), $77 and $535, respectively | 3,081 | (128 | ) | (869 | ) | |||||||
Foreign Currency Translation Adjustment, net of taxes of $507, ($427) and ($123), respectively | (826 | ) | 381 | 539 | ||||||||
Total Other Comprehensive Income | 66,354 | 5,236 | 2,784 | |||||||||
Comprehensive Income | $ | 387,529 | $ | 153,681 | $ | 91,162 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
| 1. | Summary of Significant Accounting Policies |
Basis of Presentation and Nature of Operations
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil explorationdevelopment, exploitation and exploitation,exploration, exclusively within the continental United States and Canada. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. The Company’s program is designed to be disciplined and balanced with a focus on achieving strong financial returns.
The consolidated financial statements contain the accounts of the Company and its majority-owned subsidiaries after eliminating all significant intercompany balances and transactions. Certain prior year amounts have been reclassified to conform to the current year presentation.
On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.
Recently Issued Accounting Pronouncements
In March 2005,February 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in Statement of Financial Accounting Standards (SFAS) No. 143,155, “Accounting for Asset Retirement Obligations.Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” A conditional asset retirement obligation is defined as an asset retirement activitySFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in whichSFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the timing and/or method of settlementexemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are dependent on future events that may be outside the controlaccounted for in a similar fashion, regardless of the Company.instrument’s form. The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as it does not currently hold any hybrid financial instruments.
In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” FIN No. 47 states48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN No. 48 provides additional guidance on measuring the amount of the uncertain tax position. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and disclosure of these uncertain tax positions. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company is completing its evaluation of the impact of the adoption of FIN No. 48 and believes that the impact will not have a company must recordmaterial effect on its financial position, results of operations or cash flows.
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Index to Financial Statements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a liability when incurredformal framework for conditional asset retirement obligations if themeasuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles (GAAP) to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value of the obligation is reasonably estimable. This Interpretationmeasurements are prescribed, and SFAS No. 157 is intended to provide more information about long-lived assets, more information about futurecodify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating what impact SFAS No. 157 may have on its financial position, results of operations or cash outflowsflows.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for these obligationsDefined Benefit Pension and more consistentOther Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires recognition of these liabilities. FINthe funded status of a benefit plan in the balance sheet and the recognition through other comprehensive income of gains, losses, prior service costs and credits, net of tax, arising during the period but not included as a component of periodic benefit cost. In addition, the measurement date of plan assets and obligations must be as of a company’s balance sheet date. Additional disclosures in the notes to the financial statements are required and guidance is prescribed regarding the selection of discount rates to be used in measuring the benefit obligation. For public companies, the effective date of SFAS No. 47158 is as of the end of the fiscal year ending after December 15, 2006. The effective date of the new measurement date provision is for fiscal years ending after December 15, 2005.2008; however, the Company’s measurement date is currently its balance sheet date, so no change will be required. The Company’sincremental effect of SFAS No. 158, as discussed in Note 5 of the Notes to the Consolidated Financial Statements, was an increase to total long-term liabilities of $21.7 million, an increase to current liabilities of $0.6 million, an increase to total assets of $8.2 million and a decrease to total stockholders’ equity of $14.1 million based on actuarial reports as of December 31, 2006.
In September 2006, the SEC Staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. The Company has adopted the provisions of SAB No. 108 and there was no impact to its financial position, results of operations and cash flows were not impacted by this Interpretation, since all asset retirement obligations are currently recorded.
On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For the Company’s disclosures, refer to Note 2 of the Notes to the Consolidated Financial Statements.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoptionresult of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company plans to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact the Company’s operating results, nor will there be any impact on future cash flows. See “Stock-Based Compensation” below for further information.
In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).
In November 2005, the FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS No. 123(R)
which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).
In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a company. Under SFAS No. 123(R), it is required that options and similar instruments be classified as liabilities if the entity can be required under any circumstances to settle the instrument in cash or other assets. Under the FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS No. 123(R). The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).pronouncement.
Inventories
Inventories are comprised of natural gas and oil in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of cost or market. Natural gas and oil in storage isare valued at average cost. Tubular goods and well equipment isare valued at historical cost.
Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of the natural gas imbalance is included in inventory in the consolidated balance sheet.
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Index to Financial Statements
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process which relies on interpretations of available geologic, geophysic, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense.
In the absence of a determination as to whether the reserves that have been found can be classified as proved, the costs of drilling such an exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed
to be impaired, and its costs are charged to expense. Its costs can, however, continue to be capitalized if a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility.
The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. In 2003, the Company recorded impairments related to the loss of a reversionary interest in its Kurten fieldDuring 2006 and a field in the East region. These impairments totaled $93.8 million. During 2004, the Company recorded total impairments of $3.9 million and $3.5 million.million, respectively. During 2005, the Company did not record any impairments.
Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and impaired over a period that is based on the average holding period for such properties and the Company’sCompany's experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are amortized over 12 to 25 years, gathering and compression equipment is amortized over 10 years and storage equipment and facilities are amortized over 10 to 16 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 years.
Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the disposition of certain assets during 2006.
Revenue Recognition and Gas Imbalances
The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties.
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Index to Financial Statements
Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in accounts payable in the consolidated balance sheet if the Company’sCompany's excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties. See Note 3 of the Notes to the Consolidated Financial Statements for the Company’s wellhead gas imbalances.
Brokered Natural Gas Margin
The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions.transactions with separate counterparties. The Company realized $10.3 million, $11.4 million $9.2 million, and $9.7$9.2 million of brokered natural gas margin in 2006, 2005 2004, and 2003,2004, respectively.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.
Accounts Payable
This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts, as a component of Accounts Payable on the Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 20052006 and 20042005 as sufficient cash was available for offset.
Allowance for Doubtful Accounts
The Company records an allowance for doubtful accounts for receivables that the Company feels may be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against the accounts receivable line on the Balance Sheet, was $5.6$4.6 million and $5.3$5.6 million at December 31, 20052006 and 2004,2005, respectively.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its inventories, production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge would beare recognized currently in the results of operations.
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Index to Financial Statements
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 1011 of the Notes to the Consolidated Financial Statements for further discussion.
Stock Based Compensation
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123(R), “Share Based Payment (revised 2004),” which replaces the provisions of Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees” and SFAS No. 123, “Accounting for Stock-Based Compensation,” (as amended). The Company accountselected the modified prospective transition method for adoption, and accordingly, no adjustments to prior period financial statements were made. Upon adoption, the Company recorded a cumulative effect charge totaling $0.6 million ($0.4 million, net of tax), which is included within General and Administrative Expenses in the Consolidated Statement of Operations due to its immateriality. Adoption of SFAS No. 123(R) increased income from operations and income before income taxes by approximately $1.3 million and increased net income by approximately $0.8 million for the year ended December 31, 2006. In addition, the tax benefit for stock-based compensation of $9.5 million for 2006 is now included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows.
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board OpinionAPB No. 25, “Accounting for Stock Issued to Employees.”25. Under the intrinsic value based method, the Company records no compensation expense was recorded for stock options granted when the exercise price for options granted iswas equal to or greater than the fair value of the Company’s common stock on the date of the grant.
SFAS No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”, outlines a fair value based method of accounting for stock options or similar equity instruments.
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split See Note 10 of the Company’s common stock effective March 31, 2005.
| Year Ended December 31, | |||||||||
| (In thousands, except per share amounts) | 2005 | 2004 | 2003 | ||||||
Net Income, as reported | $ | 148,445 | $ | 88,378 | $ | 21,132 | |||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income | 967 | 1,571 | 1,950 | ||||||
Pro forma Net Income | $ | 147,478 | $ | 86,807 | $ | 19,182 | |||
Earnings per Share: | |||||||||
Basic - as reported | $ | 3.04 | $ | 1.81 | $ | 0.44 | |||
Basic - pro forma | $ | 3.02 | $ | 1.78 | $ | 0.40 | |||
Diluted - as reported | $ | 2.99 | $ | 1.79 | $ | 0.44 | |||
Diluted - pro forma | $ | 2.97 | $ | 1.76 | $ | 0.40 | |||
Weighted Average Common Shares Outstanding | 48,856 | 48,733 | 48,074 | ||||||
Diluted Common Shares | 49,725 | 49,339 | 48,435 | ||||||
The fair value of stock options included inNotes to the pro forma resultsConsolidated Financial Statements for each of the three years is not necessarily indicative of future effects on net income and earnings per share. As of January 1, 2006, the Company will adopt SFAS No. 123(R), as discussed above in the “Recently Issued Accounting Pronouncements” section.
On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 2004 Incentive Plan.
The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in April 2006 and April 2007, respectively. The decision to accelerate the vesting of these unvested options, which the Company believed to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on the Company’s results of operations or cash flows in 2005. The acceleration of vesting is expected to reduce the Company’s compensation expense related to these options by approximately $0.2 million for 2006.
The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.disclosure.
| Year Ended December 31, | |||||||||||
| (In thousands, except per share amounts) | 2005 | 2004 | 2003 | ||||||||
Compensation Expense in Net Income, as reported(1) | $ | 5,965 | $ | 4,043 | $ | 1,001 | |||||
Weighted Average Value per Option Granted During the Period (2) (3) | $ | — | $ | 11.31 | $ | 6.77 | |||||
Assumptions (3) | |||||||||||
Stock Price Volatility | — | 38.4 | % | 35.3 | % | ||||||
Risk Free Rate of Return | — | 3.3 | % | 2.5 | % | ||||||
Dividend Rate (per year) | $ | 0.147 | $ | 0.107 | $ | 0.107 | |||||
Expected Term (in years) | 4 | 4 | 4 | ||||||||
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2005,2006 and 2004,2005, the cash and cash equivalents are primarily concentrated in two financial institutions. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.
Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
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Index to Financial Statements
Use of Estimates
In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, pension and postretirement obligations and deferred income taxes. Actual results could differ from those estimates.
2. Properties and Equipment
| 2. | Properties and Equipment |
Properties and equipment are comprised of the following:
| December 31, | December 31, | |||||||||||||||
| (In thousands) | 2005 | 2004 | 2006 | 2005 | ||||||||||||
Unproved Oil and Gas Properties | $ | 107,787 | $ | 94,795 | $ | 114,108 | $ | 107,787 | ||||||||
Proved Oil and Gas Properties | 1,970,407 | 1,646,841 | 2,109,045 | 1,970,407 | ||||||||||||
Gathering and Pipeline Systems | 178,876 | 160,951 | 205,473 | 178,876 | ||||||||||||
Land, Building and Improvements | 4,892 | 4,860 | 4,976 | 4,892 | ||||||||||||
Other | 33,077 | 31,261 | 34,067 | 33,077 | ||||||||||||
| 2,295,039 | 1,938,708 | 2,467,669 | 2,295,039 | |||||||||||||
Accumulated Depreciation, Depletion and Amortization | (1,056,984 | ) | (944,627 | ) | (987,468 | ) | (1,056,984 | ) | ||||||||
| $ | 1,238,055 | $ | 994,081 | $ | 1,480,201 | $ | 1,238,055 | |||||||||
As ofOn January 1, 2005, the Company adopted FSPFASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs.” Upon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the FSP. For further details onThe provisions require that, in order for costs to be capitalized, a sufficient quantity of reserves must be discovered in the provisionswell to justify its completion as a producing well and that sufficient progress has been made in assessing the well’s economic and operating feasibility. If both of this FSP, see Note 1 ofthese requirements are not met, the Notes to the Consolidated Financial Statements.costs should be expensed. The following table reflects the net changes in capitalized exploratory well costs during 2006, 2005 2004 and 2003.2004.
| December 31, | December 31, | |||||||||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||||||||
Beginning balance at January 1 | $ | 8,591 | $ | 3,681 | $ | 3,757 | $ | 6,132 | $ | 8,591 | $ | 3,681 | ||||||||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 6,132 | 8,591 | 3,681 | 8,317 | 6,132 | 8,591 | ||||||||||||||||||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (1,069 | ) | (3,395 | ) | (2,881 | ) | (5,926 | ) | (1,069 | ) | (3,395 | ) | ||||||||||||
Capitalized exploratory well costs charged to expense | (7,522 | ) | (286 | ) | (876 | ) | (95 | ) | (7,522 | ) | (286 | ) | ||||||||||||
Ending balance at December 31 | $ | 6,132 | $ | 8,591 | $ | 3,681 | $ | 8,428 | $ | 6,132 | $ | 8,591 | ||||||||||||
At December 31, 2006, the Company had four projects that had exploratory well costs that were capitalized for a period greater than one year. At December 31, 2005 and 2004, the Company did not have any projects that have been capitalized for a period greater than one year.
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Index to Financial Statements
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
| December 31, | December 31, | |||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 6,132 | $ | 8,591 | $ | 3,681 | $ | 8,317 | $ | 6,132 | $ | 8,591 | ||||||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | — | — | — | 111 | — | — | ||||||||||||
Balance at December 31 | $ | 6,132 | $ | 8,591 | $ | 3,681 | $ | 8,428 | $ | 6,132 | $ | 8,591 | ||||||
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | — | — | — | 4 | — | — | ||||||||||||
At December 31, 2005 and 2003,2006, the Company had notwo wells that had completedwhere the drilling andwas complete, but a determination of whether proved reserves existed could not be made.
Included in the December 31, 2006 amount of exploratory well costs that have been capitalized for a period greater than one year are $0.1 million of costs that have been capitalized since 2005. This amount relates to three projects comprised of preliminary costs incurred in the preparation of well sites where drilling has not commenced as of December 31, 2006. In addition, there is another well that completed drilling in January 2007 and is awaiting completion results before confirmation of proved reserves can be made in the first quarter of 2007.
At December 31, 2005, the Company had no wells that had completed drilling where a determination of whether proved reserves existed could not be made.
At December 31, 2004, the Company had 3three wells that had completed drilling andwhere a determination of whether proved reserves existed could not be made. One well was in the Rocky Mountains area and reached total depth in November 2004. It could not be completed due to the Bureau of Land Management stipulation which prohibited activity until the summer of 2005. Two wells in Canada completed drilling in October and December 2004. These wells were awaiting completion or sidetracking which was anticipated to commence by May 2005. Additional operations were performed on each of these wells, and all were determined to be unsuccessful. In 2005, $8.0 million was charged to expense for these wells, which was made up of $3.1 million for the Rocky Mountains area well and $4.9 million for the two wells in Canada.
During 2006, the Company recorded an impairment of $3.9 million. The impairment was recorded on a marginally productive gas well in Colorado County, Texas in the Gulf Coast region. During 2005, the Company did not record any impairments. During 2004, the Company recorded an impairment of $3.5 million. The impairment was recorded on a two-well field in south Louisiana and was due to production performance issues related to water encroachment. ThisThese impairment charge wascharges were recorded due to the capitalized costcosts of the fieldfields exceeding the future undiscounted cash flows. This charge isThese charges were reflected in the operating results of the Company and waswere measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field.
As part
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Index to Financial Statements
Disposition of Assets
On September 29, 2006, the Company substantially completed the sale of its offshore portfolio and certain south Louisiana properties to Phoenix Exploration Company LP (Phoenix) for a gross sales price of $340.0 million. The properties sold included proved reserves of approximately 98 Bcfe, as of the 2001 Cody acquisition, we acquired an interestAugust 1, 2006 effective date, including 68 Bcfe of proved reserves recorded as of December 31, 2005 and had average daily production for the first nine months of 2006 of 47.4 Mmcfe.
Pursuant to the asset purchase agreement for the sale, dated August 25, 2006, the gross sales price was offset by the net cash flow from operation of the properties from August 1, 2006 through the closing date and other purchase price adjustments. The net proceeds from the sale were used to add funding to the Company’s capital program, repurchase shares of common stock, repay outstanding debt under the revolving credit facility and pay taxes related to the transaction. Also pursuant to the agreement, the Company entered into certain commodity price swaps on behalf of Phoenix. At closing on September 29, 2006, these derivative instruments were assigned to Phoenix, and the Company was released from all rights and obligations with respect thereto. There was no ultimate impact on the Company’s financial statements due to the existence of these swaps.
Through December 31, 2006, the Company had received approximately $327.5 million in certain oilnet proceeds from the sale, which reflects the $340.0 million gross sales price, reduced by purchase price adjustments of $4.0 million as well as amounts attributable to consents and gas propertiespreferential rights expected to be settled in the Kurten field, as general partnerfirst quarter of a partnership and as an operator. We had approximately a 25% interest2007 of $8.5 million. A net gain of $231.2 million ($144.5 million, net of tax) was recorded in the field, includingConsolidated Statement of Operations for the year ended December 31, 2006, calculated as follows:
(In millions) | ||||
Cash Proceeds | $ | 327.5 | ||
Less: | ||||
Remaining purchase price adjustments | 11.1 | |||
Carrying value of properties sold | 104.2 | |||
Asset retirement obligation of properties sold | (23.9 | ) | ||
Deferred gain | 4.4 | |||
Transaction costs | 0.5 | |||
Pre-tax gain | $ | 231.2 | ||
The net impact of the purchase price adjustments will be reflected in cash flows from investing activities when such settlements are made. In addition, a one percent interestgain of approximately $12 million is expected to be recognized in the partnership. Under the partnership agreement, we had the right to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the additionfirst quarter of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.
Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. In2007 in connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, the Company was required to test the field for recoverability in accordance with SFAS No. 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an impairment charge in 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.
During 2003 the Company divestedclosing of certain non-strategic assets. The primary assets sold included properties in Pennsylvaniaproperty sales to Phoenix for which third party consents (including deferred amounts) had not been obtained as of December 31, 2006 and sales to other parties that were sold for $16.1 million, and resulted in aexercised their contractual preferential rights. This gain of $6.9 million. Additionally, the Company divested of a water treatment facility in the amount of $3.4 million, which resulted in a gain of $2.5 million.will be subject to customary purchase price adjustments.
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3. ADDITIONAL BALANCE SHEET INFORMATION
Index to Financial Statements
| 3. | Additional Balance Sheet Information |
Certain balance sheet amounts are comprised of the following:
| December 31, | December 31, | |||||||||||||||
| (In thousands) | 2005 | 2004 | 2006 | 2005 | ||||||||||||
Accounts Receivable | ||||||||||||||||
Trade Accounts | $ | 147,016 | $ | 105,378 | $ | 102,023 | $ | 147,016 | ||||||||
Joint Interest Accounts | 14,319 | 13,554 | 18,574 | 14,319 | ||||||||||||
Current Income Tax Receivable | 12,239 | 10,796 | ||||||||||||||
Other Accounts | 315 | 1,312 | 501 | 315 | ||||||||||||
| 173,889 | 131,040 | 121,098 | 161,650 | |||||||||||||
Allowance for Doubtful Accounts | (5,641 | ) | (5,286 | ) | (4,552 | ) | (5,641 | ) | ||||||||
| $ | 168,248 | $ | 125,754 | $ | 116,546 | $ | 156,009 | |||||||||
Inventories | ||||||||||||||||
Natural Gas and Oil in Storage | $ | 18,279 | $ | 17,631 | $ | 22,717 | $ | 18,279 | ||||||||
Tubular Goods and Well Equipment | 7,161 | 6,387 | 7,680 | 7,161 | ||||||||||||
Pipeline Imbalances | (824 | ) | 31 | 2,600 | (824 | ) | ||||||||||
| $ | 24,616 | $ | 24,049 | $ | 32,997 | $ | 24,616 | |||||||||
Other Current Assets | ||||||||||||||||
Derivative Contracts | $ | 1,736 | $ | 2,906 | ||||||||||||
Drilling Advances | 2,169 | 6,180 | $ | 651 | $ | 2,169 | ||||||||||
Prepaid Balances | 6,939 | 4,173 | 7,416 | 6,939 | ||||||||||||
Other Accounts | 304 | 246 | 338 | 304 | ||||||||||||
| $ | 11,148 | $ | 13,505 | $ | 8,405 | $ | 9,412 | |||||||||
Accounts Payable | ||||||||||||||||
Trade Accounts | $ | 18,227 | $ | 12,808 | $ | 28,569 | $ | 18,227 | ||||||||
Natural Gas Purchases | 12,208 | 8,669 | 8,356 | 12,208 | ||||||||||||
Royalty and Other Owners | 49,312 | 35,369 | 37,230 | 49,312 | ||||||||||||
Capital Costs | 37,489 | 26,203 | 59,524 | 37,489 | ||||||||||||
Taxes Other Than Income | 10,329 | 5,634 | 4,805 | 10,329 | ||||||||||||
Drilling Advances | 5,760 | 7,102 | 1,506 | 5,760 | ||||||||||||
Wellhead Gas Imbalances | 2,175 | 1,991 | 2,288 | 2,175 | ||||||||||||
Other Accounts | 4,506 | 7,193 | 5,402 | 4,506 | ||||||||||||
| $ | 140,006 | $ | 104,969 | $ | 147,680 | $ | 140,006 | |||||||||
Accrued Liabilities | ||||||||||||||||
Employee Benefits | $ | 9,020 | $ | 10,123 | $ | 13,575 | $ | 7,316 | ||||||||
Current Liability for Pension Benefits | 67 | 1,204 | ||||||||||||||
Current Liability for Postretirement Benefits | 577 | 500 | ||||||||||||||
Taxes Other Than Income | 16,188 | 14,191 | 15,696 | 16,188 | ||||||||||||
Interest Payable | 6,818 | 6,569 | 5,995 | 6,818 | ||||||||||||
Other Accounts | 3,133 | 1,725 | 6,193 | 3,092 | ||||||||||||
| $ | 35,159 | $ | 32,608 | $ | 42,103 | $ | 35,118 | |||||||||
Other Liabilities | ||||||||||||||||
Postretirement Benefits Other Than Pension | $ | 6,517 | $ | 4,717 | ||||||||||||
Accrued Pension Cost | 5,904 | 5,089 | ||||||||||||||
Rabbi Trust Deferred Compensation Plan | 4,883 | 4,199 | $ | 6,077 | $ | 4,883 | ||||||||||
Accrued Plugging and Abandonment Liability | 42,991 | 40,375 | 22,655 | 42,991 | ||||||||||||
Other Accounts | 6,899 | 6,649 | 16,681 | 6,899 | ||||||||||||
| $ | 67,194 | $ | 61,029 | $ | 45,413 | $ | 54,773 | |||||||||
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4. Debt and Credit Agreements
Index to Financial Statements
| 4. | Debt and Credit Agreements |
7.19% Notes
In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005, and the2005. The Company made its firstthe required $20 million payment duringpayments in both 2006 and 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
7.33% Weighted Average Fixed Rate Notes
To partially fund the cash portion of the acquisition of Cody Company in AugustIn July 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001.transaction. Prior to the determination of the Note’s interest rates, the Company entered into a treasury lock in order to reduce the risk of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that is being amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of the Notes have bullet maturities and were issued in three separate tranches as follows:
| Principal | Term | Maturity Date | Coupon | |||||||
Tranche 1 | $ | 75,000,000 | 10-year | July 2011 | 7.26 | % | ||||
Tranche 2 | $ | 75,000,000 | 12-year | July 2013 | 7.36 | % | ||||
Tranche 3 | $ | 20,000,000 | 15-year | July 2016 | 7.46 | % | ||||
The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.
Revolving Credit Agreement
On December 10, 2004, the Company amended its Revolving Credit Agreement (credit facility) with a group of nine banks. The credit facility allows for borrowings of $250 million, of which $10 million and $90 million waswere outstanding at December 31, 2005.2006 and 2005, respectively. The credit facility can be expanded up to $350 million, either with the existing banks or new banks. ThisThe credit facility is unsecured. The term of the credit facility expires in December 2009. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months either to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixth of the excess during each of the six months.
Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness is 50% or greater, greater than 75% or greater than 90% of the Company’sCompany's debt limit of $530 million, which can be expanded up to $630$610 million, as shown below.below:
| Debt Percentage | ||||||||||||
| Lower than 50% | 50% or higher but not exceeding 75% | Higher than 75% but not exceeding 90% | Higher than 90% | |||||||||
Euro-Dollar margin | 1.000 | % | 1.250 | % | 1.500 | % | 1.750 | % | ||||
Base Rate margin | 0.000 | % | 0.000 | % | 0.250 | % | 0.500 | % | ||||
The Company’s effective interest rates for the credit facility induring the years ended December 31, 2006, 2005 and 2004 were 7.9%, 6.9% and 2003 were 6.9%, 4.2% and 1.9%, respectively. As of December 31, 2005,2006, the weighted average interest rate on the Company’s credit facility was 7.25%8.25%. As of December 31, 2004, the Company had no borrowings outstanding on its credit facility. The credit facility provides for a commitment fee on the unused available balance at an annual rate of one-quarter of 1%. The credit facility also contains various customary restrictions, which include the following:
| (a) | Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. |
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Index to Financial Statements
| (b) | Prohibition on the merger or sale of all, or substantially all, of the |
The Company was in compliance in all material respects with allits covenants contained in its various debt agreements at December 31, 20052006 and 20042005 and during the years then ended.
5. Employee Benefit Plans
| 5. | Employee Benefit Plans |
Pension Plan
The Company has aan underfunded non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly fixed income investments and equity securities. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan. The measurement date used to measure pension benefit amounts is December 31, 2005.
The Company has aan unfunded non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded.
Components of Net Periodic Benefit Cost
Net periodic pension cost of the Company during the last three years is comprised of the following:
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Qualified | ||||||||||||
Current Year Service Cost | $ | 2,485 | $ | 1,619 | $ | 1,481 | ||||||
Interest Cost | 1,896 | 1,697 | 1,515 | |||||||||
Expected Return on Plan Assets | (1,507 | ) | (1,474 | ) | (999 | ) | ||||||
Amortization of Prior Service Cost | 99 | 88 | 88 | |||||||||
Recognized Net Actuarial Loss | 921 | 383 | 415 | |||||||||
Net Periodic Pension Cost | $ | 3,894 | $ | 2,313 | $ | 2,500 | ||||||
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Non-Qualified | ||||||||||||
Current Year Service Cost | $ | (682 | ) | $ | 395 | $ | 280 | |||||
Interest Cost | 85 | 381 | 163 | |||||||||
Amortization of Prior Service Cost | 77 | 77 | 77 | |||||||||
Recognized Net Actuarial (Gain) / Loss | (22 | ) | 428 | 187 | ||||||||
Net Periodic Pension (Income) / Cost | $ | (542 | ) | $ | 1,281 | $ | 707 | |||||
Obligations and Funded Status
The following table illustratesfunded status represents the funded statusdifference between the projected benefit obligation of the Company’s qualified and non-qualified pension plans and the fair value of the qualified pension plan’s assets at December 31:31.
| 2005 | 2004 | |||||||||||||||
| (In thousands) | Qualified | Non-Qualified | Qualified | Non-Qualified | ||||||||||||
Actuarial Present Value of: | ||||||||||||||||
Accumulated Benefit Obligation | $ | 29,669 | $ | 1,204 | $ | 23,181 | $ | 3,579 | ||||||||
Projected Benefit Obligation | $ | 39,449 | $ | 1,762 | $ | 29,809 | $ | 6,257 | ||||||||
Fair Value of Plan Assets | 23,765 | — | 18,092 | — | ||||||||||||
Projected Benefit Obligation in Excess of Plan Assets | 15,684 | 1,762 | 11,717 | 6,257 | ||||||||||||
Unrecognized Net Actuarial Loss | (14,899 | ) | (498 | ) | (9,846 | ) | (4,374 | ) | ||||||||
Unrecognized Prior Service Cost | (269 | ) | (245 | ) | (248 | ) | (322 | ) | ||||||||
Adjustment to Recognize Minimum Liability | 5,388 | 185 | 3,466 | 2,018 | ||||||||||||
Accrued Pension Cost | $ | 5,904 | $ | 1,204 | $ | 5,089 | $ | 3,579 | ||||||||
The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans duringand the last three years is explained as follows:
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Beginning of Year | $ | 36,066 | $ | 33,547 | $ | 26,042 | ||||||
Service Cost | 1,803 | 2,014 | 1,761 | |||||||||
Interest Cost | 1,981 | 2,078 | 1,678 | |||||||||
Actuarial Loss | 1,852 | 1,798 | 4,679 | |||||||||
Plan Amendments | 120 | — | — | |||||||||
Benefits Paid | (611 | ) | (3,371 | ) | (613 | ) | ||||||
End of Year | $ | 41,211 | $ | 36,066 | $ | 33,547 | ||||||
The change in the Company’s qualified plan assets at fair value of the Company’s pension plan during the last three years is explainedare as follows:
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||||||||
Beginning of Year | $ | 18,092 | $ | 18,683 | $ | 10,279 | ||||||||||||||||||
Change in Benefit Obligation | ||||||||||||||||||||||||
Benefit Obligation at Beginning of Year | $ | 41,211 | $ | 36,066 | $ | 33,547 | ||||||||||||||||||
Service Cost | 2,720 | 1,803 | 2,014 | |||||||||||||||||||||
Interest Cost | 2,333 | 1,981 | 2,078 | |||||||||||||||||||||
Actuarial Loss | 5 | 1,852 | 1,798 | |||||||||||||||||||||
Plan Amendments | (3 | ) | 120 | — | ||||||||||||||||||||
Benefits Paid | (791 | ) | (611 | ) | (3,371 | ) | ||||||||||||||||||
Benefit Obligation at End of Year | 45,475 | 41,211 | 36,066 | |||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||
Fair Value of Plan Assets at Beginning of Year | 23,765 | 18,092 | 18,683 | |||||||||||||||||||||
Actual Return on Plan Assets | 1,544 | 957 | 2,446 | 3,587 | 1,544 | 957 | ||||||||||||||||||
Employer Contribution | 5,000 | 2,000 | 6,735 | |||||||||||||||||||||
Employer Contributions | 12,008 | 5,000 | 2,000 | |||||||||||||||||||||
Benefits Paid | (611 | ) | (3,371 | ) | (613 | ) | (791 | ) | (611 | ) | (3,371 | ) | ||||||||||||
Expenses Paid | (260 | ) | (177 | ) | (164 | ) | (380 | ) | (260 | ) | (177 | ) | ||||||||||||
End of Year | $ | 23,765 | $ | 18,092 | $ | 18,683 | ||||||||||||||||||
Fair Value of Plan Assets at End of Year | 38,189 | 23,765 | 18,092 | |||||||||||||||||||||
Funded Status at End of Year | $ | (7,286 | ) | $ | (17,446 | ) | $ | (17,974 | ) | |||||||||||||||
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The reconciliation
Index to Financial Statements
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet at December 31 consist of the combined funded statusfollowing:
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Long-Term Assets | $ | — | $ | 454 | $ | 570 | ||||||
Current Liabilities | (67 | ) | (1,204 | ) | (3,579 | ) | ||||||
Long-Term Liabilities | (7,219 | ) | (5,904 | ) | (5,089 | ) | ||||||
| $ | (7,286 | ) | $ | (6,654 | ) | $ | (8,098 | ) | ||||
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income at December 31 consist of the Company’sfollowing:
(In thousands) | 2006 | 2005 | 2004 | ||||||||
Prior Service Cost | $ | 336 | $ | — | $ | — | |||||
Net Actuarial Loss | 12,946 | — | — | ||||||||
Minimum Pension Liability | — | (5,119 | ) | (4,914 | ) | ||||||
| $ | 13,282 | $ | (5,119 | ) | $ | (4,914 | ) | ||||
The estimated prior service cost and net loss for the qualified defined benefit pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are approximately $0.1 million and $0.7 million, respectively.
The estimated prior service cost and net loss for the defined benefit non-qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are approximately $0.1 million each.
The combined accumulated benefit obligation for both pension plans was $34.8 million, $30.9 million and $26.8 million at the end of the last three years is explained as follows:December 31, 2006, 2005 and 2004, respectively.
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Funded Status(1) | $ | 17,446 | $ | 17,974 | $ | 14,864 | ||||||
Unrecognized Net Actuarial Loss | (15,397 | ) | (14,220 | ) | (12,540 | ) | ||||||
Unrecognized Net Prior Service Cost | (514 | ) | (570 | ) | (735 | ) | ||||||
Net Amount Recognized | $ | 1,535 | $ | 3,184 | $ | 1,589 | ||||||
Accrued Benefit Liability - Qualified Plan | $ | 5,904 | $ | 5,089 | $ | 2,664 | ||||||
Accrued Benefit Liability - Non-Qualified Plan | 1,204 | 3,579 | 3,171 | |||||||||
Intangible Asset | (454 | ) | (570 | ) | (735 | ) | ||||||
Accumulated Other Comprehensive Income | (5,119 | ) | (4,914 | ) | (3,511 | ) | ||||||
Net Amount Recognized | $ | 1,535 | $ | 3,184 | $ | 1,589 | ||||||
Additional InformationComponents of Net Periodic Benefit Cost
The amounts included in Other Comprehensive Income as a result of increases in the minimum liability of the Company’s pension plans are as follows as of December 31:Qualified Pension Plan
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Qualified Plan | $ | 1,900 | $ | 2,199 | $ | (870 | ) | |||||
Non-Qualified Plan | (1,695 | ) | (795 | ) | 2,203 | |||||||
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Qualified Components of Net Periodic Benefit Cost | ||||||||||||
Current Year Service Cost | $ | 2,518 | $ | 2,485 | $ | 1,619 | ||||||
Interest Cost | 2,211 | 1,896 | 1,697 | |||||||||
Expected Return on Plan Assets | (1,962 | ) | (1,507 | ) | (1,474 | ) | ||||||
Amortization of Prior Service Cost | 98 | 99 | 88 | |||||||||
Amortization of Net Loss | 1,125 | 921 | 383 | |||||||||
Net Periodic Pension Cost | $ | 3,990 | $ | 3,894 | $ | 2,313 | ||||||
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Index to Financial Statements
Non-Qualified Pension Plan
(In thousands) | 2006 | 2005 | 2004 | |||||||
Non-Qualified Components of Net Periodic Benefit Cost | ||||||||||
Current Year Service Cost | $ | 203 | $ | (682 | ) | $ | 395 | |||
Interest Cost | 122 | 85 | 381 | |||||||
Amortization of Prior Service Cost | 77 | 77 | 77 | |||||||
Amortization of Net Loss / (Gain) | 85 | (22 | ) | 428 | ||||||
Net Periodic Pension Cost / (Income) | $ | 487 | $ | (542 | ) | $ | 1,281 | |||
Assumptions
AssumptionsWeighted-average assumptions used to determine projected pension benefit obligations areat December 31 were as follows:
| 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | |||||||||||||
Discount Rate | 5.50 | % | 5.75 | % | 6.25 | % | 5.75 | % | 5.50 | % | 5.75 | % | ||||||
Rate of Compensation Increase | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | ||||||
AssumptionsWeighted-average assumptions used to determine net periodic pension costs at December 31 are as follows:
| 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | |||||||||||||
Discount Rate | 5.75 | % | 6.25 | % | 6.50 | % | 5.50 | % | 5.75 | % | 6.25 | % | ||||||
Expected Long-Term Return on Plan Assets | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | ||||||
Rate of Compensation Increase | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | 4.00 | % | ||||||
The long-term expected rate of return on plan assets used in 2005,2006, as shown above, is eight percent. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. One of the plan objectives is that performance of the equity portion of the pension plan exceed the Standard and Poors’ 500 Index by a minimum of two percent annually over the long term. The Company also seeks to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In the Company’s pension calculations, the Company has used eight percent as the expected long-term return on plan assets for 2006, 2005 and 2004. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company’s actual asset allocation and liability duration, which has been determined to be approximately 16 years. This model uses historical data for the period of 1926-2003 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that the Company expects to achieve over 50 percent of the time, is approximately nine percent. The Company expects to achieve a minimum 6.4% annual real rate of return on the total portfolio over the long term at least 75 percent of the time. In addition, the actual rate of return on plan assets annualized over the past ten years is approximately six percent. The Company believes that the eight percent chosen is a reasonable estimate based on its actual results.
- 76 -
Index to Financial Statements
Plan Assets
At December 31, 20052006 and 2004,2005, the non-qualified pension plan did not have plan assets. The plan assets of the Company’s qualified pension plan at December 31, 20052006 and 2004,2005, by asset category are as follows:
| 2005 | 2004 | |||||||||||
| (In thousands) | Amount | Percent | Amount | Percent | ||||||||
Equity securities | $ | 19,556 | 82 | % | $ | 13,934 | 77 | % | ||||
Debt securities | 840 | 4 | % | 3,226 | 18 | % | ||||||
Other(1) | 3,369 | 14 | % | 932 | 5 | % | ||||||
Total | $ | 23,765 | �� | 100 | % | $ | 18,092 | 100 | % | |||
| 2006 | 2005 | |||||||||||
(In thousands) | Amount | Percent | Amount | Percent | ||||||||
Equity securities | $ | 27,124 | 71 | % | $ | 19,556 | 82 | % | ||||
Debt securities | 10,605 | 28 | % | 840 | 4 | % | ||||||
Other(1) | 460 | 1 | % | 3,369 | 14 | % | ||||||
Total | $ | 38,189 | 100 | % | $ | 23,765 | 100 | % | ||||
(1) | Primarily consists of cash and cash equivalents. |
The Company’s investment strategy for benefit plan assets is to invest in funds to maximize the return over the long-term, subject to an appropriate level of risk. Additionally, the objective is for each class of investments to outperform its representative benchmark over the long term. The Company generally targets a portfolio of assets utilizing equity securities, debt securities and cash equivalents that are within a range of approximately 60%50% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of the portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be invested in money market investments up to 20%. One percent of the portfolio is invested in short-term funds at the designated bank to meet the cash flow needs of the plan. No prohibited investments, including direct or indirect investments in commodities, commodity futures, derivatives, short sales, real estate investment trusts, letter stock, restricted stock or other private placements, are allowed without prior committee approval.
Cash Flows
Contributions
The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. In 20052006, the Company did not have any required minimum funding obligations; however, it chose to fund $5$12 million into the qualified plan. In 20062007, the Company does not have any required minimum funding obligations for the qualified pension plan. The Company will fund less than $0.1 million, as shown below, for the non-qualified pension plan. Currently, management has not determined if any discretionary funding will be made in 2006.2007.
Estimated Future Benefit Payments
The following estimated benefit payments under the Company’s qualified and non-qualified pension plans, which reflect expected future service, as appropriate, are expected to be paid as follows:
| (In thousands) | Qualified | Non-Qualified | Total | Qualified | Non-Qualified | Total | ||||||||||||
2006 | $ | 828 | $ | 42 | $ | 870 | ||||||||||||
2007 | 848 | 54 | 902 | $ | 960 | $ | 73 | $ | 1,033 | |||||||||
2008 | 916 | 74 | 990 | 1,030 | 102 | 1,132 | ||||||||||||
2009 | 1,106 | 85 | 1,191 | 1,306 | 128 | 1,434 | ||||||||||||
2010 | 1,256 | 176 | 1,432 | 1,345 | 237 | 1,582 | ||||||||||||
Years 2011 - 2015 | 10,878 | 1,418 | 12,296 | |||||||||||||||
2011 | 1,537 | 167 | 1,704 | |||||||||||||||
Years 2012 - 2016 | 13,451 | 1,991 | 15,442 | |||||||||||||||
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Index to Financial Statements
Postretirement Benefits Other than Pensions
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. The life insurance plans were non-contributory. As of January 1, 2006, the Company no longer provides postretirement life insurance coverage. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 244 retirees and their dependants at the end of 2006 and 245 retirees and their dependants at the end of 2005 and 251 retirees and their dependants at the end of 2004. The measurement date used to measure postretirement benefits other than pensions is December 31, 2005.
When the Company adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension”, in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the Transition Obligation,transition obligation, over a period of 20 years, or $0.8 million per year which is included in the annual expense of the plan. Included in the amortization benefit of the unrecognized transition obligation amount below are the effects of plan amendments during 1996, 2000 and 2004. TheAs a result of the adoption of SFAS No. 158, the remaining unamortized balance at December 31, 2006 of $3.2 million is $3.9 million whichnow recognized in accumulated other comprehensive income. Additionally, a portion of this amount will be amortized overand reclassified from the next six years.
Components of Net Periodic Benefit Cost
Postretirement benefit costs recognized duringbalance sheet to the last three years areincome statement as follows:expense each year.
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Current Year Service Cost | $ | 675 | $ | 671 | $ | 265 | ||||||
Interest Cost | 605 | 784 | 385 | |||||||||
Recognized Net Actuarial Gain | (79 | ) | (59 | ) | (155 | ) | ||||||
Amortization of Prior Service Cost | 910 | 1,211 | — | |||||||||
Amortization of Net Obligation at Transition | 648 | 662 | 662 | |||||||||
Total Postretirement Benefit Cost | $ | 2,759 | $ | 3,269 | $ | 1,157 | ||||||
Obligations and Funded Status
The funded status represents the difference between the projected benefit obligation of the Company’s postretirement benefit obligationplan and the fair value of plan assets at December 31, 2005, 2004 and 200331. As the postretirement plan does not have any plan assets, the funded status is comprisedequal to the amount of the following:December 31 projected benefit obligation.
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Beginning of Year (1) | $ | 14,101 | $ | 6,181 | $ | 6,185 | ||||||
Service Cost | 675 | 671 | 265 | |||||||||
Interest Cost | 605 | 784 | 386 | |||||||||
Amendments | (1,434 | ) | 6,901 | — | ||||||||
Actuarial (Gain) / Loss | (876 | ) | 864 | 221 | ||||||||
Benefits Paid | (1,278 | ) | (1,300 | ) | (876 | ) | ||||||
End of Year(1) | $ | 11,793 | $ | 14,101 | $ | 6,181 | ||||||
The change in the accumulatedCompany’s postretirement benefit obligation during the last three years, as well as the funded status at the end of the last three years, is presented as follows:
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Fair Value of Plan Assets | $ | — | $ | — | $ | — | ||||||
Funded Status | 11,793 | 14,101 | 6,181 | |||||||||
Unrecognized Net Gain | 2,475 | 814 | 1,736 | |||||||||
Unrecognized Net Prior Service Cost | (3,366 | ) | (5,691 | ) | — | |||||||
Unrecognized Net Transition Obligation | (3,888 | ) | (4,631 | ) | (5,293 | ) | ||||||
Accrued Postretirement Benefit Liability | $ | 7,014 | $ | 4,593 | $ | 2,624 | ||||||
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Change in Benefit Obligation | ||||||||||||
Benefit Obligation at Beginning of Year | $ | 11,793 | $ | 14,101 | $ | 6,181 | ||||||
Service Cost | 789 | 675 | 671 | |||||||||
Interest Cost | 877 | 605 | 784 | |||||||||
Actuarial Loss / (Gain) | 6,337 | (876 | ) | 864 | ||||||||
Plan Amendments | (153 | ) | (1,434 | ) | 6,901 | |||||||
Benefits Paid | (862 | ) | (1,278 | ) | (1,300 | ) | ||||||
Benefit Obligation at End of Year | 18,781 | 11,793 | 14,101 | |||||||||
Change in Plan Assets | ||||||||||||
Fair Value of Plan Assets at End of Year | N/A | N/A | N/A | |||||||||
Funded Status at End of Year | $ | (18,781 | ) | $ | (11,793 | ) | $ | (14,101 | ) | |||
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet at December 31 consist of the following:
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Current Liabilities | $ | (577 | ) | $ | (500 | ) | $ | (500 | ) | |||
Long-Term Liabilities | (18,204 | ) | (6,514 | ) | (4,093 | ) | ||||||
| $ | (18,781 | ) | $ | (7,014 | ) | $ | (4,593 | ) | ||||
- 78 -
Index to Financial Statements
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:
(In thousands) | 2006 | 2005 | 2004 | ||||
Transition Obligation | $ | 3,159 | N/A | N/A | |||
Prior Service Cost | 2,570 | N/A | N/A | ||||
Net Actuarial Loss | 3,705 | N/A | N/A | ||||
| $ | 9,434 | N/A | N/A | ||||
The estimated net obligation at transition, prior service cost and net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year are $0.6 million, $1.0 million and $0.2 million, respectively.
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Components of Net Periodic Postretirement Benefit Cost | ||||||||||||
Current Year Service Cost | $ | 789 | $ | 675 | $ | 671 | ||||||
Interest Cost | 877 | 605 | 784 | |||||||||
Amortization of Prior Service Cost | 952 | 910 | 1,211 | |||||||||
Amortization of Net Obligation at Transition | 632 | 648 | 662 | |||||||||
Amortization of Net Loss / (Gain) | 32 | (79 | ) | (59 | ) | |||||||
SFAS 106 Net Periodic Postretirement Cost | 3,282 | 2,759 | 3,269 | |||||||||
Recognized Curtailment Gain | (86 | ) | — | — | ||||||||
Recognized Loss Due to Special Term Benefits | — | 319 | — | |||||||||
SFAS 88 (Cost) / Income | (86 | ) | 319 | — | ||||||||
Total SFAS 106 and SFAS 88 Cost | $ | 3,196 | $ | 3,078 | $ | 3,269 | ||||||
- 79 -
Index to Financial Statements
Assumptions
Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:
| 2005 | 2004 | 2003 | |||||||
Discount Rate(1) | 5.50 | % | 5.75 | % | 6.25 | % | |||
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year | 9.00 | % | 10.00 | % | 8.00 | % | |||
Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate) | 5.00 | % | 5.00 | % | N/A | ||||
Year that the rate reaches the Ultimate Trend Rate | 2010 | 2009 | 2009 |
| 2006 | 2005 | 2004 | |||||||
Discount Rate(1) | 5.75 | % | 5.50 | % | 5.75 | % | |||
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year | 8.00 | % | 9.00 | % | 10.00 | % | |||
Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate) | 5.00 | % | 5.00 | % | 5.00 | % | |||
Year that the rate reaches the Ultimate Trend Rate | 2010 | 2010 | 2009 |
(1) | Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in2006, 2005 |
The health care cost trend rate used to measure the expected cost from 2000 to 2003 for medical benefits to retirees was 8%.eight percent. Provisions of the plan existing at that time would have prevented significant future increases in employer cost after 2000. During the years ended December 31, 2005 and 2004, the plan was amended in several areas effective January 1, 2006. As of January 1, 2006, coverage provided to participants age 65 and older will beis under a fully-insured arrangement which replaces the former self-funded plan. Benefits under this new arrangement are expected to be comparable to benefits under the self-funded plan. The Company subsidy will beis limited to 60% of the expected annual fully-insured premium.premium for participants age 65 and older. For all participants of anyunder age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, iswas limited to an aggregate annual amount not to exceed $648,000. This limit will increase by 3.5% annually thereafter. Additionally, in February 2005, the Company purchased individualprepaid the life insurance policies on a fully insured basispremiums for all retirees retiring before January 1, 2006.2006, eliminating all future premiums for retiree life insurance. Effective January 1, 2006, postretirementthe Company eliminated company paid retiree life insurance benefits will not be providedcoverage. Changes were made to new retirees.the life insurance product that is offered to employees allowing employees to continue coverage into retirement by paying the premiums directly to the life insurance provider.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| (In thousands) | 1-Percentage- Point Increase | 1-Percentage- Point Decrease | 1-Percentage- Point Increase | 1-Percentage- Point Decrease | ||||||||||
Effect on total of service and interest cost | $ | 12 | $ | (13 | ) | $ | 385 | $ | (306 | ) | ||||
Effect on postretirement benefit obligation | 131 | (147 | ) | 3,189 | (2,582 | ) | ||||||||
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Index to Financial Statements
Cash Flows
Contributions
The Company expects to contribute approximately $0.6 million to the postretirement benefit plan in 2006.2007.
Estimated Future Benefit Payments
The following estimated benefit payments under the Company’s postretirement plans, which reflect expected future service, as appropriate, are expected to be paid as follows:
| (In thousands) | |||
2006 | $ | 571 | |
2007 | 579 | ||
2008 | 580 | ||
2009 | 594 | ||
2010 | 616 | ||
Years 2011 - 2015 | 3,894 | ||
(In thousands) 2007 2008 2009 2010 2011 Years 2012 - 2016 $ 594 626 662 700 753 5,361
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introducesintroduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. As amended by the Company has amendedon January 1, 2006, the postretirement benefit plan to excludeexcludes prescription drug benefits to participants age 65 and older effective January 1, 2006, management believesolder. Due to this amendment, FSP willNo. 106-2 did not have an impact on operating results, financial position or cash flows of the Company.
Incremental Effect of Applying SFAS No. 158 to Pension and Postretirement Plans on Individual Line Items in the Balance Sheet
The table below illustrates the incremental effects of applying SFAS No. 158 to various individual balance sheet line items as of December 31, 2006. The column entitled “Before Application of SFAS No. 158” includes the effect of the additional minimum liability adjustment required for 2006.
(In thousands) | Before Application of SFAS No. 158 | Adjustments | After Application of SFAS No. 158 | ||||||||
Other Assets | $ | 7,864 | $ | (168 | ) | $ | 7,696 | ||||
Deferred Income Tax Asset (Non-Current) | 22,465 | 8,447 | 30,912 | ||||||||
Total Assets | 1,826,212 | 8,279 | 1,834,491 | ||||||||
Accrued Liabilities | 41,459 | 644 | 42,103 | ||||||||
Total Current Liabilities | 250,383 | 644 | 251,027 | ||||||||
Long-Term Liability for Pension Benefits | (5,639 | ) | 12,858 | 7,219 | |||||||
Long-Term Liability for Postretirement Benefits | 9,348 | 8,856 | 18,204 | ||||||||
Accumulated Other Comprehensive Income | 51,239 | (14,079 | ) | 37,160 | |||||||
Total Stockholders’ Equity | 959,277 | (14,079 | ) | 945,198 | |||||||
Total Liabilities and Stockholders’ Equity | 1,826,212 | 8,279 | 1,834,491 | ||||||||
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Index to Financial Statements
Savings Investment Plan
The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $1.6$1.8 million, $1.4$1.6 million and $1.4 million in 2006, 2005, 2004, and 2003,2004, respectively. The Company matches employee contributions dollar-for-dollar on the first 6%six percent of an employee’s pretax earnings. The Company’sCompany's common stock is an investment option within the SIP.
Deferred Compensation Plan
In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. If the employee’s base salary and bonus deferrals cause the employee to not receive the full 6%six percent company match to the Savings Investment Plan, the Company will make a contribution annually into the Deferred Compensation Plan to ensure that the employee receives a full matching contribution from the Company. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2005,2006, the balance in the Deferred Compensation Plan’s rabbi trust was $4.9$6.1 million.
The employee participants guide the diversification of trust assets. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of the Company’s stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company’s balance sheet as a component of Other Assets and the corresponding liability is recorded as a component of Other Liabilities.
There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Second, no shares of the Company’s stock are held in the trust.
The Company charged to expense plan contributions of less than $20,000 in each year presented.
6. Income Taxes
| 6. | Income Taxes |
Income tax expense (benefit) is summarized as follows:
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | |||||||||||||||
Current | |||||||||||||||||||||
Federal | $ | 42,976 | $ | 14,767 | $ | 22,826 | $ | 123,155 | $ | 42,976 | $ | 14,767 | |||||||||
State | 5,185 | 3,710 | 2,075 | 14,164 | 5,185 | 3,710 | |||||||||||||||
Total | 48,161 | 18,477 | 24,901 | 137,319 | 48,161 | 18,477 | |||||||||||||||
Deferred | |||||||||||||||||||||
Federal | 37,565 | 31,779 | (8,549 | ) | 49,911 | 37,565 | 31,779 | ||||||||||||||
State | 2,063 | (10 | ) | (1,289 | ) | 2,100 | 2,063 | (10 | ) | ||||||||||||
Total | 39,628 | 31,769 | (9,838 | ) | 52,011 | 39,628 | 31,769 | ||||||||||||||
Total Income Tax Expense | $ | 87,789 | $ | 50,246 | $ | 15,063 | $ | 189,330 | $ | 87,789 | $ | 50,246 | |||||||||
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Index to Financial Statements
Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:
| Year Ended December 31, | ||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % | ||||||
Computed “Expected” Federal Income Tax | $ | 82,682 | $ | 48,518 | $ | 15,065 | ||||||
State Income Tax, Net of Federal Income Tax Benefit | 7,030 | 4,353 | 1,334 | |||||||||
Other, Net | (1,923 | )(1) | (2,625 | )(2) | (1,336 | )(3) | ||||||
Total Income Tax Expense | $ | 87,789 | $ | 50,246 | $ | 15,063 | ||||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % | ||||||
Computed “Expected” Federal Income Tax | $ | 178,818 | $ | 82,682 | $ | 48,518 | ||||||
State Income Tax, Net of Federal Income Tax Benefit | 14,494 | 7,030 | 4,353 | |||||||||
Other, Net | (3,982 | )(1) | (1,923 | )(2) | (2,625 | )(3) | ||||||
Total Income Tax Expense | $ | 189,330 | $ | 87,789 | $ | 50,246 | ||||||
(1) | Other, Net includes credit adjustments of $2.3 million related to the qualified production activities deduction, $0.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $0.8 million related to the recognition of benefit for state statutory depletion in excess of basis, $2.6 million related to the reduction of the state statutory rate, and other permanent items. Other, Net also includes debit adjustments of $1.2 million related to excess compensation, $1.0 million related to performance shares, and other permanent items. |
(2) | Other, Net includes credit adjustments of $1.3 million related to the qualified production activities deduction, $0.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $1.0 million related to the recognition of benefit for state statutory depletion in excess of basis, $0.6 million related to the reduction of the state statutory rate and other permanent items. Other, Net also includes debit adjustments of $0.7 million related to excess compensation, $0.7 million related to Internal Revenue Service audit adjustments and other permanent items. |
(3) |
| Other, Net includes credit adjustments of $1.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $0.9 million related to the recognition of benefit for state statutory depletion in excess of basis, and other permanent items. |
The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:
| Year Ended December 31, | Year Ended December 31, | |||||||||||
| (In thousands) | 2005 | 2004 | 2006 | 2005 | ||||||||
Deferred Tax Liabilities | ||||||||||||
Property, Plant and Equipment | $ | 288,602 | $ | 246,962 | $ | 346,198 | $ | 288,602 | ||||
Items Accrued for Financial Reporting Purposes | 1,720 | 1,358 | 33,194 | 1,720 | ||||||||
Total | 290,322 | 248,320 | 379,392 | 290,322 | ||||||||
Deferred Tax Assets | ||||||||||||
Net Operating Loss Carryforwards | 2,591 | 2,045 | 1,281 | 2,591 | ||||||||
Items Accrued for Financial Reporting Purposes | 22,840 | 21,290 | 30,564 | 22,840 | ||||||||
Other Comprehensive Income | 9,830 | 12,865 | 8,453 | 9,830 | ||||||||
Total | 35,261 | 36,200 | 40,298 | 35,261 | ||||||||
Net Deferred Tax Liabilities | $ | 255,061 | $ | 212,120 | $ | 339,094 | $ | 255,061 | ||||
As of December 31, 2005,2006, the Company had a net operating loss carryforward of $50.3$25.5 million for state income tax reporting purposes, the majority of which will expire between 20132020 and 20252026 and none available for regular federal income tax purposes. It is expected that these deferred tax benefits will be utilized prior to their expiration.
7. Commitments and Contingencies
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Index to Financial Statements
| 7. | Commitments and Contingencies |
Firm Gas Transportation Agreements and Drilling Rig Commitments
The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East.East region. The remaining terms on these agreements range from 2less than one year to 2221 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company.
Future obligations under firm gas transportation agreements in effect at December 31, 20052006 are as follows:
| (In thousands) | ||||||
2006 | $ | 11,661 | ||||
2007 | 11,626 | $ | 9,864 | |||
2008 | 8,213 | 8,248 | ||||
2009 | 3,381 | 7,108 | ||||
2010 | 3,381 | 3,716 | ||||
2011 | 3,424 | |||||
Thereafter | 55,504 | 52,758 | ||||
| $ | 93,766 | $ | 85,118 | |||
Drilling Rig Commitments
The Company also has threeseven drilling rigs in the Gulf Coast that are under contract. Three existing drilling rigs are under contract that are not yet delivered and two existing rigswith rig providers in the Gulf Coast under contract through 2008.Coast. An additional four drilling rigs were built for rig providers for use by the Company, three of which were delivered in the fourth quarter of 2006. The fourth rig is expected to be delivered by April 2007. As of December 31, 2005,2006, the Company is obligated over the next 4four years to pay $104.3$120.3 million as follows:
| (In thousands) | |||
2006 | $ | 26,055 | |
2007 | 41,245 | ||
2008 | 27,340 | ||
2009 | 9,675 | ||
| $ | 104,315 | ||
Subsequent to December 31, 2005, the Company entered into an agreement for one additional drilling rig in the Gulf Coast. The total commitment over the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 million and $8.4 million will be paid out during the years 2006, 2007, 2008 and 2009, respectively.
(In thousands) 2007 2008 2009 2010 $ 54,382 41,127 22,502 2,250 $ 120,261
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s office in Houston runs for approximately fourthree more years. MostAll of the Company’sthese operating leases expire within the next five years, and some of these leases may be renewed. Rent expense under such arrangements totaled $10.7 million, $9.1 million $8.7 million, and $8.5$8.7 million for the years ended December 31, 2006, 2005, 2004, and 2003,2004, respectively.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 20052006 are as follows:
| (In thousands) | ||||||
2006 | $ | 4,876 | ||||
2007 | 4,633 | $ | 5,014 | |||
2008 | 4,541 | 4,785 | ||||
2009 | 3,207 | 3,469 | ||||
2010 | 489 | 710 | ||||
2011 | 98 | |||||
Thereafter | — | — | ||||
| $ | 17,746 | $ | 14,076 | |||
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Index to Financial Statements
Guarantees
On June 28, 2006, the Company announced the commencement of an offering under its Mineral, Royalty and Overriding Royalty Interest Plan. The Company assisted certain non-executive employees in obtaining loans to purchase interests offered under the plan by providing a guarantee of repayment should the non-executive employee fail to repay the loan. The repayment term for all of these loans is five years. The outstanding loan balances are approximately $0.3 million in the aggregate, and the fair value of these guarantees are immaterial to the Company’s financial statements. All loans are collateralized by the interests transferred to the employees in the producing properties.
Contingencies
The Company is a defendant in various legal proceedings arising in the normal course of ourits business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Wyoming Royalty Litigation
In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to the Company, the case was settled in September 2005 with no payment from the Company and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the reserve it had recorded regarding this case, which had an immaterial impact on the Company’s consolidated financial statements.
West Virginia Royalty Litigation
In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that itthe Company had taken improper deductions from the royalty and that it failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.
Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of athe case involving an unrelated party pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses.described below. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.
The West Virginia Supreme Court of Appeals issued a decision in 2006 in a case against another producer (the Tawney case) that raised some of the same issues as are raised in the Company’s case. This recent decision may negatively impact some of the defenses the Company has raised in its litigation with respect to the issue of deductibility of post-production expenses under certain leases, but it believes that in a significant number of leases the Company has lease language, factual distinctions and defenses that are not implicated by the ruling.
The Tawney case involves claims concerning the deductibility of post-production expenses and the failure to properly inform, issues shared with the Company’s case, but also involves additional claims not raised in its case. The most significant additional claims are related to sales under long-term, fixed-price agreements at prices considered significantly below market value, as well as claims for certain volume reductions and unmetered production. The Tawney case went to trial in January 2007, and the jury returned a verdict against the producer for $130 million in compensatory damages and $270 million in punitive damages. Judgment has not yet been entered in the Tawney case, and an appeal is expected. The Company is closely monitoring developments in the Tawney case, and it continues to investigate how this recent ruling may impact its defense of the case. The case against the Company has been re-activated to the docket and trial is set for August 13, 2007.
The Company is vigorously defending the case. A reserve has been established that management believes is adequate based on its estimate of the probable outcome of this case.
- 85 -
Index to Financial Statements
Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs’Plaintiffs' Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs filed their Third Amended Original Petition on February 21, 2006, which incorporated all prior supplemental petitions. Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, a subsidiary of the Company, acquired certain leases and wells in 1997 and 1998.
The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass and conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties arewere allowed to amend pleadings or add additional parties to the litigation. DuePlaintiffs did not join additional parties by the abatement deadline. Defendants, including the Company, re-urged its motion to dismiss, and on April 5, 2006, the Court granted the motion, dismissing the oil company defendants, without prejudice. Because all defendants were not dismissed at that time, the order dismissing the Company was not then final. A motion to finalize the proceedings in the trial court via severance of the dismissed defendants was filed April 25, 2006, and the remaining defendants moved to join the motions that led to the abatementdismissal of the case,Company. In 2006, the Court dismissed the claims. Plaintiffs have filed a Notice of Appeal. Although the record is not yet complete and, therefore, specific appellate deadlines have not been set, the Company has not hadexpects that, following briefing and oral argument, the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since Cody Energy, LLC acquired title is approximately $15.7 million, and thatappellate court will issue its decision by the carrying valueend of this property is approximately $33.6 million.
Although the investigation into this claim continues, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome2007 or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.early 2008.
Raymondville Area
In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.
The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. The defendants have filed a counter claim against the Company,Cody, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville area.Area.
Cody has signed a settlement agreement with certain of the defendants representing approximately 3%three percent of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest.
On July 12, 2006, Cody entered into a Purchase and Sale Agreement to acquire all of the defendant’s interest in the Raymondville Field. The agreement would make the summary judgment ruling by the trial judge a final order, dismiss, with prejudice, all pending counter claims filed by such defendant and remove the lien against Cody’s properties filed by such defendant. Cody completed the acquisition in the third quarter of 2006. The lien has filedbeen removed, the summary judgment has become a Motion for Reconsiderationfinal order and Opposition to Proposed Order. The Court has not yet made a decision on these two motions.all of the defendant’s claims have been dismissed.
- 86 -
Index to Financial Statements
Commitment and Contingency Reserves
The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $10.2$9.1 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
8. Cash Flow Information
| 8. | Cash Flow Information |
Cash paid for interest and income taxes is as follows:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||
Interest | $ | 17,366 | $ | 16,415 | $ | 18,298 | $ | 24,088 | $ | 17,366 | $ | 16,415 | ||||||
Income Taxes | 47,142 | 29,861 | 19,267 | 128,752 | 47,142 | 29,861 | ||||||||||||
The increase in cash paid for income taxes from 2005 to 2006 is primarily due to the December 2006 payment of approximately $102 million related to the sale of the Company’s offshore and certain south Louisiana assets.
The Company recorded benefits of $9.5 million, $3.7 million $2.6 million and $1.0$2.6 million for the years ended December 31, 2006, 2005 2004 and 2003,2004, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting.
9. Capital Stock
On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.
| 9. | Capital Stock |
Incentive Plans
On April 29, 2004, the 2004 Incentive Plan was approved by the shareholders. Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards, in addition to the automatic award of an option to purchase 15,000 shares of common stock on the date the non-employee directors first join the board of directors. A total of 2,550,000 shares of common stock may be issued under the 2004 Incentive Plan. In addition, shares remaining available for award under the 1994 Long-Term Incentive Plan and the Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (herein “Prior Plans”) were subsumed into the 2004 Incentive Plan (342,597 shares post-split). Under the 2004 Incentive Plan, no more than 900,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,500,000 shares may be issued pursuant to incentive stock options. Awards outstanding under the Prior Plans will remain outstanding in accordance with their original terms and conditions.
During
- 87 -
Index to Financial Statements
Stock Split
On February 28, 2005, the Company announced that the Board of Directors grantedhad declared a series of 110,200 performance share awards to the executives of the Company. These awards are earned based on the comparative performance3-for-2 split of the Company’s common stock measured against sixteen other companies in the Company’s peer group overform of a three year vesting period endingstock distribution. The stock dividend was distributed on
April 30, 2008. Depending March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the Company’s performance, employees may earn up to 100%closing price of the award in common stock on the record date. All common stock accounts and an additional 100% of the award in cash. The performance shares qualify for variable accounting, and accordingly, are recorded at their fair value with compensation expense recognized over the performance period.
During 2005, the Company granted 19,600 restricted stock unitsper share data have been retroactively adjusted to give effect to the non-employee Directors of the Company. These units immediately vest and will be paid out whenever the Director ceases to be a Director of the Company. For all restricted stock units, the Company recognized compensation expense equal to the market value3-for-2 split of the Company’s common stock onstock.
Increase in Authorized Shares
On May 4, 2006, the grant date of the respective awards.
Information regarding stock options under the Company’s 2004 Incentive Plan and the Prior Plans is summarized below:
| December 31, | ||||||
| 2005 | 2004 | 2003 | ||||
Shares Under Option at Beginning of Period | 1,217,534 | 2,024,252 | 1,931,744 | |||
Granted | — | 36,750 | 700,500 | |||
Exercised | 300,493 | 793,775 | 518,079 | |||
Surrendered or Expired | 3,693 | 49,693 | 89,913 | |||
Shares Under Option at End of Period | 913,348 | 1,217,534 | 2,024,252 | |||
Options Exercisable at End of Period | 895,848 | 565,994 | 767,579 | |||
For each of the three most recent years, the price range for outstanding options was $11.63 to $23.32 per share. The following tables provide more information about the options by exercise price and year.
Options with exercise prices between $11.63 and $15.00 per share:
| December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
Options Outstanding | |||||||||
Number of Options | 225,575 | 344,945 | 667,002 | ||||||
Weighted Average Exercise Price | $ | 12.84 | $ | 12.85 | $ | 12.81 | |||
Weighted Average Contractual Term (in years) | 1.1 | 2.0 | 2.6 | ||||||
Options Exercisable | |||||||||
Number of Options | 225,575 | 183,737 | 306,344 | ||||||
Weighted Average Exercise Price | $ | 12.84 | $ | 12.86 | $ | 12.69 | |||
Options with exercise prices between $15.01 and $23.32 per share:
| December 31, | |||||||||
| 2005 | 2004 | 2003 | |||||||
Options Outstanding | |||||||||
Number of Options | 687,773 | 872,589 | 1,357,250 | ||||||
Weighted Average Exercise Price | $ | 16.14 | $ | 16.16 | $ | 16.46 | |||
Weighted Average Contractual Term (in years) | 1.9 | 2.7 | 3.4 | ||||||
Options Exercisable | |||||||||
Number of Options | 670,273 | 382,257 | 461,235 | ||||||
Weighted Average Exercise Price | $ | 16.13 | $ | 16.29 | $ | 17.61 | |||
Dividend Restrictions
The Board of Directorsstockholders of the Company determinesapproved an increase in the amountauthorized number of future cash dividends, if any, to be declared and paid on theshares of common stock depending on, among other things,from 80 million to 120 million shares. The Company correspondingly increased the Company’s financial condition, fundsnumber of shares of Series A Junior Participating Preferred Stock reserved for issuance from operations,800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision.Preferred Stock Purchase Rights Plan described below.
Treasury Stock
In August 1998, the Company announced that its Board of Directors authorized the Company to repurchase up toof two million shares of outstandingthe Company’s common stock atin the open market prices.or in negotiated transactions. As a result of the 3-for-2 stock split of the Company’s common stock in March 2005, this figure has beenwas adjusted to three million shares. On October 26, 2006, the Company announced that its Board of Directors increased the number of shares of the Company’s common stock authorized for repurchase by an additional two million shares. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.
During the year ended December 31, 2005,2006, the Company repurchased 452,3001,088,500 shares with a weighted average price per share of $42.71 for a total cost of approximately $19.2$46.5 million. All of the repurchases occurred during the second and third quarters. The repurchased shares are held as treasury stock. Since the authorization date, the Company has repurchased 1,513,8502,602,350 shares, or 50%52% of the five million total shares authorized for repurchase at December 31, 2006, for a total cost of approximately $39.2$85.7 million. In 2005, the stock repurchase plan was funded from cash flow from operations. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.
Dividend Restrictions
The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision.
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’sCompany's outstanding common stock. Each right entitles the holder, other than the acquiring person or group, to purchase a fraction of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the common stock, each right entitles the holder to purchase common stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of common stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of
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Directors may opt to exchange one share of common stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’sCompany's assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 20052006 there were no shares of Junior Preferred Stock issued or outstanding.
The rights expire on January 21, 2010, and may be redeemed by the Company at any time before a person or group acquires beneficial ownership of 15% of the common stock.
The 3-for-2 split of the Company’s common stock was consummated in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. As a result of the 3-for-2 stock split, each share of common stock continues to include one right under the Company’sCompany's Preferred Stock Purchase Rights Plan, and each right now provides for the purchase, upon the occurrence of the conditions set forth in the plan, of two-thirds of one one-hundredth of a share of preferred stock at a purchase price of approximately $36.67 per two-thirds of one one-hundredth of a share. The redemption price of each right is now two-thirds of a cent. All common
| 10. | Stock-Based Compensation |
Adoption of SFAS No. 123(R)
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by APB No. 25. Under the intrinsic value based method, no compensation expense was recorded for stock accounts and per share data have been retroactively adjustedoptions granted when the exercise price for options granted was equal to give effect toor greater than the 3-for-2 splitfair value of the Company’s common stock.stock on the date of the grant.
Beginning January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123(R), which applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005. The Company recorded compensation expense based on the fair value of awards as described below. Additionally, compensation expense for the portion of the awards for which the requisite service period was not rendered that were outstanding at December 31, 2005 was or will be recognized as the requisite service is rendered on or after January 1, 2006.
Compensation expense charged against income for stock-based awards for the years ended December 31, 2006, 2005 and 2004 was $21.2 million, $9.6 million and $6.5 million, respectively, and is included in General and Administrative Expense in the Consolidated Statement of Operations. The primary reason for this increase was due to an increase in the liability component of the performance share awards as well as expense related to performance shares granted in 2006. In 2006, compensation expense included amortization of restricted stock grants, stock options, SARs, restricted stock units and performance shares at fair value. Compensation expense in 2005 only included amortization of restricted stock grants and compensation expense related to performance shares and restricted stock units. The $0.6 million ($0.4 million, net of tax) cumulative effect charge at adoption that was recorded in the first quarter of 2006 was due primarily to the recording of the liability component of the Company’s performance share awards at fair value, rather than intrinsic value. The Company recorded tax benefits related to stock-based compensation of $9.5 million, $3.7 million and $2.6 million for the years ended December 31, 2006, 2005 and 2004, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting.
Prior to the adoption of SFAS No. 123(R), the Company presented tax benefits resulting from tax deductions related to stock-based compensation as an operating cash flow. Under SFAS No. 123(R), the tax benefits resulting from tax deductions in excess of expense are reported as an operating cash outflow and a financing cash inflow. For the year ended December 31, 2006, $9.5 million was reported in these two separate line items in the Consolidated Statement of Cash Flows.
On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 2004 Incentive Plan.
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The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in April 2006 and April 2007, respectively. The decision to accelerate the vesting of these unvested options, which the Company believed to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on the Company’s results of operations or cash flows in 2005. The acceleration of vesting reduced the Company’s compensation expense related to these options by approximately $0.2 million for 2006.
During the third quarter of 2006, the Company adopted the provisions outlined under FSP FAS No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock awards using the APIC Pool concept. The Company was not required to adopt this provision until January 1, 2007, one year from the adoption of 123(R); however, it chose early adoption. The Company made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. The Company chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors.
The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS No. 123(R) to stock-based employee compensation during the years ended December 31, 2005 and 2004:
| Year Ended December 31, | ||||||||
(In thousands, except per share amounts) | 2005 | 2004 | ||||||
Net Income, as reported | $ | 148,445 | $ | 88,378 | ||||
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported | 5,965 | 4,043 | ||||||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income | (6,932 | ) | (5,614 | ) | ||||
Pro forma net income | $ | 147,478 | $ | 86,807 | ||||
Earnings per Share: | ||||||||
Basic - as reported | $ | 3.04 | $ | 1.81 | ||||
Basic - pro forma | $ | 3.02 | $ | 1.78 | ||||
Diluted - as reported | $ | 2.99 | $ | 1.79 | ||||
Diluted - pro forma | $ | 2.97 | $ | 1.76 | ||||
Share Count | 48,856 | 48,733 | ||||||
Diluted Share Count | 49,725 | 49,339 | ||||||
In September 2006, the SEC Staff issued a letter summarizing their views regarding the backdating of stock options. The letter discusses the date that is to be used as the measurement date for options in order to value the exercise price of stock options. It also discusses the documentation that should be available to support award grant dates. The Company reviewed its stock option granting practices and found no instances of backdating. Further, as required under the Company’s incentive plans, the stock option grant date is the date on which the Compensation Committee and/or Board of Directors approves the award. Company management is given no discretion to choose the grant date. The Company maintains Compensation Committee and/or Board of Directors minutes and other records to support the grant dates of its options.
10.Restricted Stock Awards
Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis for awards that vest one-third at each anniversary date over a three year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting
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tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of a three year service period, expense is recognized ratably using a straight-line expensing approach over three years. For all restricted stock awards, vesting is dependant upon the employees’ continued service with the Company, with the exception of employment terminations due to death, disability or retirement.
The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R). The Company used an annual forfeiture rate ranging from 0% to 3.3% based on the Company’s ten year history for this type of award to various employee groups.
The following table is a summary of restricted stock award activity for the year ended December 31, 2006:
Restricted Stock Awards | Shares | Weighted- Average Grant Date Fair Value per share | Weighted- Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) (1) | |||||||
Non-vested shares outstanding at December 31, 2005 | 588,465 | $ | 26.68 | ||||||||
Granted | 46,850 | 47.60 | |||||||||
Vested | (231,493 | ) | 21.76 | ||||||||
Forfeited | (5,000 | ) | 31.26 | ||||||||
Non-vested shares outstanding at December 31, 2006 | 398,822 | $ | 31.93 | 1.4 | $ | 24,189 | |||||
(1) | The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 2006 by the number of non-vested restricted stock awards outstanding. |
As shown in the table above, there were 46,850 restricted stock awards granted to employees during 2006. All of these awards were granted in the first quarter of 2006. These awards granted in 2006 vest over a three year service period on a graded-vesting schedule. During the year ended December 31, 2005, 327,623 restricted stock awards were granted with a weighted-average grant date fair value per share of $31.88. During the year ended December 31, 2004, 215,250 restricted stock awards were granted with a weighted-average grant date fair value per share of $23.75. The total fair value of shares vested during 2006, 2005 and 2004 was $5.0 million, $2.2 million and $2.0 million, respectively.
Compensation expense recorded for restricted stock awards for the years ended December 31, 2006, 2005 and 2004 was $6.1 million, $5.6 million and $3.1 million, respectively. Included in the 2006 expense was $0.6 million related to the expensing of the entire value of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2006 for all outstanding restricted stock awards was $4.3 million.
Restricted Stock Units
Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company. Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.
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The following table is a summary of restricted stock unit activity for the year ended December 31, 2006:
Restricted Stock Units | Shares | Weighted- Average Grant Date Fair Value per share | Aggregate Intrinsic Value (in thousands) (1) | ||||||
Outstanding at December 31, 2005 | 30,100 | $ | 31.30 | ||||||
Granted and fully vested | 17,220 | 50.82 | |||||||
Issued | (8,600 | ) | 31.30 | ||||||
Forfeited | — | — | |||||||
Outstanding at December 31, 2006 | 38,720 | $ | 39.98 | $ | 2,348 | ||||
(1) | The intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company’s stock on December 31, 2006 by the number of outstanding restricted stock units as of December 31, 2006. |
As shown in the table above, 17,220 restricted stock units were granted during 2006. During 2005, 19,600 restricted stock units were granted with a weighted-average grant date fair value per share of $35.58. During 2004, 10,500 restricted stock units were granted with a weighted-average grant date fair value per share of $23.32.
The compensation cost, which reflects the total fair value of these units, recorded entirely in the second quarter of 2006 was $0.9 million. Compensation expense recorded during the years ended December 31, 2005 and 2004 for restricted stock units was $0.7 million and $0.2 million, respectively.
Stock Options
Option awards are granted with an exercise price equal to the fair market price (defined as the average of the high and low trading prices of the Company’s stock on the date of grant) of the Company’s stock at the date of grant.
During the year ended December 31, 2006, 30,000 stock options, with an exercise price of $47.60 per share, were granted to two incoming non-employee directors of the Company. All of these stock options were granted in the first quarter of 2006. No stock options were granted in the year ended December 31, 2005. During 2004, 36,750 stock options were granted with an exercise price of $23.32 per share.
Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. Compensation expense recorded during 2006 for these stock options was $0.3 million. Since the Company had not yet adopted SFAS No. 123(R) as of December 31, 2005, stock options were not expensed through the Consolidated Statement of Operations during 2005 and 2004 and no compensation expense was recorded. Unamortized expense as of December 31, 2006 for all outstanding stock options was $0.2 million. The weighted average period over which this compensation will be recognized is approximately 2.2 years.
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The grant date fair value of a stock option is calculated by using a Black-Scholes model. The assumptions used in the Black-Scholes fair value calculation for stock options are as follows:
| Year Ended December 31, | |||||||||||
| 2006 | 2005 | 2004 | |||||||||
Weighted-Average Value per Option Granted | |||||||||||
During the Period (1) | $ | 14.65 | $ | — | $ | 7.54 | |||||
Assumptions | |||||||||||
Stock Price Volatility | 31.5 | % | — | 38.4 | % | ||||||
Risk Free Rate of Return | 4.6 | % | — | 3.3 | % | ||||||
Expected Dividend | 0.3 | % | — | 0.8 | % | ||||||
Expected Term (in years) | 4.0 | — | 4.0 | ||||||||
(1) | Calculated using the Black-Scholes fair value based method. |
The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term thorough the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the US Treasury (Nominal 10) within the expected term as measured on the grant date. The expected dividend percentage assumes that the Company will continue to pay a $0.04 per share dividend each quarter.
The following table is a summary of stock option activity for the years ended December 31, 2006, 2005 and 2004:
Stock Options | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | ||||||||||||
Outstanding at Beginning of Year | 913,348 | $ | 15.32 | 1,217,534 | $ | 15.22 | 2,024,252 | $ | 15.26 | |||||||||
Granted | 30,000 | 47.60 | — | — | 36,750 | 23.32 | ||||||||||||
Exercised | (438,473 | ) | 14.39 | (300,493 | ) | 14.92 | (793,775 | ) | 15.69 | |||||||||
Forfeited or Expired | (900 | ) | 18.20 | (3,693 | ) | 14.85 | (49,693 | ) | 14.25 | |||||||||
Outstanding at December 31(1) | 503,975 | $ | 18.05 | 913,348 | $ | 15.32 | 1,217,534 | $ | 15.22 | |||||||||
Options Exercisable at December 31(2) | 473,975 | $ | 16.18 | 895,848 | $ | 15.30 | 565,994 | $ | 15.18 | |||||||||
(1) | The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2006 was $21.5 million. The weighted-average remaining contractual term is 1.3 years. |
(2) | The aggregate intrinsic value of options exercisable at December 31, 2006 was $21.1 million. The weighted-average remaining contractual term is 1.1 years. |
The total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 was $17.7 million, $6.9 million and $5.8 million, respectively.
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At December 31, 2006, the exercise price range for outstanding options was $12.84 to $47.60 per share. The following tables provide more information about the options by exercise price.
Options with exercise prices between $12.84 and $15.00 per share:
Options Outstanding | |||
Number of Options | 7,350 | ||
Weighted Average Exercise Price | $ | 12.84 | |
Weighted Average Contractual Term (in years) | 0.1 | ||
Options Exercisable | |||
Number of Options | 7,350 | ||
Weighted Average Exercise Price | $ | 12.84 | |
Weighted Average Contractual Term (in years) | 0.1 | ||
Options with exercise prices between $15.01 and $30.00 per share:
Options Outstanding | |||
Number of Options | 466,625 | ||
Weighted Average Exercise Price | $ | 16.23 | |
Weighted Average Contractual Term (in years) | 1.1 | ||
Options Exercisable | |||
Number of Options | 466,625 | ||
Weighted Average Exercise Price | $ | 16.23 | |
Weighted Average Contractual Term (in years) | 1.1 | ||
Options with exercise prices between $30.01 and $47.60 per share:
Options Outstanding | |||
Number of Options | 30,000 | ||
Weighted Average Exercise Price | $ | 47.60 | |
Weighted Average Contractual Term (in years) | 4.2 | ||
None of the options with exercise prices between $30.01 and $47.60 were exercisable as of December 31, 2006.
Stock Appreciation Rights
On February 23, 2006, the Compensation Committee granted 132,800 SARs to employees. These awards allow the employee to receive any intrinsic value over the $47.60 grant date fair market value that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As of December 31, 2006, there were 132,800 SARs outstanding and none were exercisable. The aggregate intrinsic value of these awards was $1.7 million at December 31, 2006. As these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.
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The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:
| Year Ended December 31, 2006 | ||||
Weighted-Average Value per Stock Appreciation Right | ||||
Granted During the Period (1) | $ | 14.19 | ||
Assumptions | ||||
Stock Price Volatility | 31.6 | % | ||
Risk Free Rate of Return | 4.6 | % | ||
Expected Dividend | 0.3 | % | ||
Expected Term (in years) | 3.75 | |||
(1) | Calculated using the Black-Scholes fair value based method. |
Compensation expense recorded during the year ended December 31, 2006 for these SARs was $1.0 million. As no SARs were outstanding during 2005 and 2004, no compensation expense was recorded for this type of award. In addition, all SARs were unvested at December 31, 2006. Unamortized expense as of December 31, 2006 for all outstanding SARs was $0.9 million which will be recognized over the next 2.2 years.
Performance Share Awards
During 2006, the Compensation Committee granted two types of performance share awards to employees for a total of 142,750 performance shares. The performance period for both of these awards commenced January 1, 2006 and ends December 31, 2008. Certain of these awards, totaling 52,900 performance shares, are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year vesting performance period. Depending on the Company’s performance, employees may earn up to 100% of the award in common stock, and an additional 100% of the award in cash. A new type of award was granted to non-executive employees in 2006, for a total of 89,850 shares, which measures the Company’s performance based on internal metrics rather than a peer group. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal metric performance criteria that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at December 31, 2006, it is currently considered probable that these three criteria will be met.
Both of these types of awards vest at the end of a designated three year performance period. For all awards granted to employees before and after January 1, 2006, an annual forfeiture rate ranging from 0% to 5.0% was assumed based on the Company’s history for this type of award to various employee groups.
On December 31, 2006, the performance period ended for the performance shares awarded in 2004, which were based on total shareholder return. Due to the ranking of the Company compared to its peers in its predetermined peer group, 100% of the award, valued at $4.8 million based on the average of the high and low stock price on the grant date, is payable in 225,000 shares of common stock. An additional 33 percent, equal to one-third of the total value of the award, calculated by using the high and low stock price on December 29, 2006 multiplied by the number of performance shares earned, or $4.6 million, is payable in cash. These amounts were paid in January 2007. The calculation of the award payout was approved by the Compensation Committee on January 4, 2007, and the vesting of these shares will be reported in the first quarter of 2007.
For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fair value was measured based on the average of the high and low stock price of the Company on grant date and expense is amortized over the three year vesting period. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components
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were bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is being amortized on a straight-line basis over the vesting period of three years. The liability component was valued at each reporting period by using a Monte Carlo binomial model.
The three primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns and correlation in stock price movement. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for six-month and one, two and three year bonds and is set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date. Volatility was set equal to the annualized daily volatility measured over a historic four year period ending on the reporting date. A sample of correlation statistics were reviewed between the Company and its peers and the average ranged between 87% and 93%.
The following assumptions were used as of December 31, 2006 for the Monte Carlo model to value the liability components of the peer group measured performance share awards. The equity portion of the award granted in 2006 was valued on the date of grant using the Monte Carlo model and this portion was not marked to market.
| As of December 31, 2006 | |||
Risk Free Rate of Return | 4.8% - 4.9 | % | |
Stock Price Volatility | 32.6 | % | |
Correlation in stock price movement | 90 | % | |
Expected Dividend | 0.3 | % |
The Monte Carlo value per share for the liability for performance share awards at December 31, 2006 ranged from $20.26 to $52.36. The long-term liability, included in Other Liabilities in the Consolidated Balance Sheet, and short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, for performance share awards at December 31, 2006 was $3.9 million and $4.6 million, respectively.
The following table is a summary of performance share award activity for the year ended December 31, 2006:
Performance Share Awards | Shares | Weighted- per share (1) | Weighted- Average Remaining Contractual Term (in years) | Aggregate (in thousands) (2) | |||||||
Non-vested shares outstanding at December 31, 2005 | 346,150 | $ | 24.34 | ||||||||
Granted | 142,750 | 42.13 | |||||||||
Vested | (15,300 | ) | 25.17 | ||||||||
Forfeited (3) | (3,550 | ) | 33.26 | ||||||||
Non-vested shares outstanding at December 31, 2006 | 470,050 | $ | 29.65 | 1.7 | $ | 28,509 | |||||
(1) | The fair value figures in this table represent the fair value of the equity component of the performance share awards. |
(2) | The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 2006 by the number of non-vested performance share awards outstanding. |
(3) | These shares vested as a result of the death of one of the Company’s officers. |
During the year ended December 31, 2005, 110,200 performance share awards were granted with a grant date fair value per share of $30.43. During the year ended December 31, 2004, 252,750 performance share awards were granted with a grant date fair value per share of $21.49. No performance shares vested in 2005 or 2004. During 2005 and 2004, 8,700 and 8,100 performance shares, respectively, were forfeited.
Total unamortized compensation cost related to the equity component of performance shares at December 31, 2006 was $5.1 million and will be recognized over the next 1.7 years, computed by using the weighted average of the time
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in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity (including the cumulative effect) and liability components of performance share awards during the years ended December 31, 2006, 2005 and 2004 was $12.9 million, $3.3 million and $3.2 million, respectively.
11. Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” and does not impact the Company’s financial position, results of operations or cash flows.
Long-Term Debt
| December 31, 2005 | December 31, 2004 | December 31, 2006 | December 31, 2005 | |||||||||||||||||||||||||
| (In thousands) | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||||||||||
Debt | ||||||||||||||||||||||||||||
Long-Term Debt | ||||||||||||||||||||||||||||
7.19% Notes | $ | 60,000 | $ | 62,938 | $ | 80,000 | $ | 87,770 | $ | 60,000 | $ | 61,749 | $ | 80,000 | $ | 83,295 | ||||||||||||
7.26% Notes | 75,000 | 81,713 | 75,000 | 85,849 | 75,000 | 80,335 | 75,000 | 81,713 | ||||||||||||||||||||
7.36% Notes | 75,000 | 83,990 | 75,000 | 87,111 | 75,000 | 82,025 | 75,000 | 83,990 | ||||||||||||||||||||
7.46% Notes | 20,000 | 23,083 | 20,000 | 23,804 | 20,000 | 22,547 | 20,000 | 23,083 | ||||||||||||||||||||
Credit Facility | 90,000 | 90,000 | — | — | 10,000 | 10,000 | 90,000 | 90,000 | ||||||||||||||||||||
Current Maturities | ||||||||||||||||||||||||||||
7.19% Notes | (20,000 | ) | (20,299 | ) | (20,000 | ) | (20,357 | ) | ||||||||||||||||||||
Long-Term Debt, excluding Current Maturities | $ | 220,000 | $ | 236,357 | $ | 320,000 | $ | 341,724 | ||||||||||||||||||||
| $ | 320,000 | $ | 341,724 | $ | 250,000 | $ | 284,534 | |||||||||||||||||||||
The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year end market rate. The fair value of the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The credit facility approximates fair value because this instrument bears interest at rates based on current market rates.
Derivative Instruments and Hedging Activity
The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2005,2006, the Company had nine20 cash flow hedges open: eight19 natural gas price collar arrangements and one crude oil collar arrangement. At December 31, 2005, a $20.72006, an $82.0 million ($12.951.2 million, net of tax) unrealized lossgain was recorded toin Accumulated Other Comprehensive Income, along with a $22.4an $82.0 million short-term derivative liability and a $1.7 million short-term derivative receivable, which is shown in Other Current Assets on the Balance Sheet.receivable. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. During 2006, there was no ineffectiveness recorded in the Consolidated Statement of Operations. For the years ended December 31, 2005 and 2004, a $6.6 million gain and a $2.0 million loss were recorded as components of revenue, which reflected the ineffective portion of the change in fair value of derivatives designated as hedges and the change in the fair value of all other derivatives.
Assuming no change in commodity prices, after December 31, 20052006 the Company would expect to reclassify to the Consolidated Statement of Operations, over the next 12 months, $12.9$51.2 million in after-tax chargesincome associated with commodity hedges. This reclassification represents the net liabilityshort-term receivable associated with open positions currently not reflected in earnings at December 31, 20052006 related to anticipated 20062007 production.
Hedges on Production
- Swaps97 -
From time
Index to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2005, natural gas price swaps covered 20,557 Mmcf, or 28% of the Company’s gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.At December 31, 2005, the Company had no open natural gas price swap contracts covering 2006 production.
From time to time, the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2005, the Company did not have any of these types of arrangements.
Financial Statements
Hedges on Production - Options
From time to time, the Company enters into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below
the floor price, the counterparty pays the Company. During 2005,2006, natural gas price collars covered 15,15727,179 Mmcf of the Company’s gas production, or 21%34% of gas production with a weighted average floor of $5.59$8.25 per Mcf and a weighted average ceiling of $8.61$12.74 per Mcf. During 2005,2006, an oil price collar covered 365 Mbbl of the Company’s crude oil production, or 21%26% of crude oil production with a weightedan average floor of $40.00$50.00 per Mbbl and a weightedan average ceiling of $50.50$76.00 per Mbbl.
At December 31, 2005,2006, the Company had open natural gas price collar contracts covering its 20062007 production as follows:
| Natural Gas Price Collars | |||||||||
Contract Period | Volume in Mmcf | Weighted Ceiling / Floor | Net Unrealized (In thousands) | ||||||
As of December 31, 2005 | |||||||||
First Quarter 2006 | 6,702 | $ | 12.74 /$8.25 | ||||||
Second Quarter 2006 | 6,776 | 12.74 / 8.25 | |||||||
Third Quarter 2006 | 6,850 | 12.74 / 8.25 | |||||||
Fourth Quarter 2006 | 6,851 | 12.74 / 8.25 | |||||||
Full Year 2006 | 27,179 | $ | 12.74 /$8.25 | $ | (20,425 | ) | |||
| Natural Gas Price Collars | ||||||||
Contract Period | Volume in Mmcf | Weighted Average (per Mcf) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2006 | ||||||||
First Quarter 2007 | 10,487 | $12.19 / $8.99 | ||||||
Second Quarter 2007 | 10,604 | 12.19 / 8.99 | ||||||
Third Quarter 2007 | 10,721 | 12.19 / 8.99 | ||||||
Fourth Quarter 2007 | 10,721 | 12.19 / 8.99 | ||||||
Full Year 2007 | 42,533 | $ | 12.19 / $8.99 | $ | 81,393 | |||
At December 31, 2005,2006, the Company had one open crude oil price collar contract covering its 20062007 production as follows:
| Crude Oil Price Collar | |||||||||
Contract Period | Volume in Mbbl | Weighted Average Ceiling /Floor | Net (In thousands) | ||||||
As of December 31, 2005 | |||||||||
First Quarter 2006 | 90 | $ | 76.00 /$50.00 | ||||||
Second Quarter 2006 | 91 | 76.00 / 50.00 | |||||||
Third Quarter 2006 | 92 | 76.00 / 50.00 | |||||||
Fourth Quarter 2006 | 92 | 76.00 / 50.00 | |||||||
Full Year 2006 | 365 | $ | 76.00 /$50.00 | $ | (317 | ) | |||
| Crude Oil Price Collar | ||||||||
Contract Period | Volume in Mbbl | Average Ceiling / Floor (per Bbl) | Net Unrealized (In thousands) | |||||
As of December 31, 2006 | ||||||||
First Quarter 2007 | 90 | $80.00 / $60.00 | ||||||
Second Quarter 2007 | 91 | 80.00 / 60.00 | ||||||
Third Quarter 2007 | 92 | 80.00 / 60.00 | ||||||
Fourth Quarter 2007 | 92 | 80.00 / 60.00 | ||||||
Full Year 2007 | 365 | $ | 80.00 / $60.00 | $ | 589 | |||
The Company is exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.
Credit Risk
Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.
In 2006, no customer accounted for more than 10% of the Company’s total sales. In each of 2005 2004 and 2003,2004 approximately 11% of the Company’s total sales were made to one customercustomer.
11. Adoption of SFAS 143, “Accounting for Asset Retirement Obligations”
Effective January 1, 2003, the- 98 -
Index to Financial Statements
| 12. | Asset Retirement Obligations |
The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires thatrecords the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. The adoption of SFAS No. 143 resulted in an increase of total liabilities because additional retirement obligations are required to be recognized, an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived
asset and an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities willare also be recorded for meter stations, pipelines, processing plants and compressors. At December 31, 20052006, there arewere no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax charge for the cumulative effect of change in accounting principle, in January of 2003, of approximately $6.8 million ($11.0 million before tax) and recorded a retirement obligation of approximately $35.2 million. There was no impact on the Company’s cash flows as a result of adopting SFAS No. 143.
Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the years ended December 31, 2005, 20042006 and 20032005 was $1.4 million in each year and $1.7 million for the year ended December 31, 2004, and $2.1 million, respectively.was included within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.
The following table reflects the changes of the asset retirement obligations during the current period.
| (In thousands) | ||||||||
Carrying amount of asset retirement obligations at December 31, 2004 | $ | 40,375 | ||||||
Carrying amount of asset retirement obligations at December 31, 2005 | $ | 42,991 | ||||||
Liabilities added during the current period | 1,364 | 2,089 | ||||||
Liabilities settled during the current period | (110 | ) | ||||||
Liabilities settled and divested during the current period | (23,775 | ) | ||||||
Current period accretion expense | 1,419 | 1,350 | ||||||
Revisions to estimated cash flows | (57 | ) | ||||||
Carrying amount of asset retirement obligations at December 31, 2005 | $ | 42,991 | ||||||
Carrying amount of asset retirement obligations at December 31, 2006 | $ | 22,655 | ||||||
12. Earnings per Common Share
| 13. | Earnings per Common Share |
Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.exercised.
The following is a calculation of basic and diluted weighted average shares outstanding for the yearyears ended December 31, 2006, 2005 2004 and 2003:2004:
| December 31, | December 31, | |||||||||||
| 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | |||||||
Shares - basic | 48,856,491 | 48,732,504 | 48,074,496 | 48,401,642 | 48,856,491 | 48,732,504 | ||||||
Dilution effect of stock options and awards at end of period | 868,904 | 606,297 | 360,932 | 898,850 | 868,904 | 606,297 | ||||||
Shares - diluted | 49,725,395 | 49,338,801 | 48,435,428 | 49,300,492 | 49,725,395 | 49,338,801 | ||||||
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect | — | — | 1,448,666 | — | — | — | ||||||
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Index to Financial Statements
| 14. | Accumulated Other Comprehensive Income |
Changes in the components of accumulated other comprehensive income, net of taxes, for the years ended December 31, 2006, 2005 and 2004 were as follows:
Accumulated Other Comprehensive | Net Gains / (Losses) on Cash Flow Hedges | Defined Benefit Pension and Postretirement Plans | Foreign Currency Translation Adjustment | Total | ||||||||||||
Balance at December 31, 2003 | $ | (20,957 | ) | $ | (2,173 | ) | $ | (5 | ) | $ | (23,135 | ) | ||||
Net change in unrealized gains on cash flow hedges, net of taxes of ($1,908) | 3,114 | — | — | 3,114 | ||||||||||||
Net change in minimum pension liability, net of taxes of $535 | — | (869 | ) | — | (869 | ) | ||||||||||
Change in foreign currency translation adjustment, net of taxes of ($123) | — | — | 539 | 539 | ||||||||||||
Balance at December 31, 2004 | $ | (17,843 | ) | $ | (3,042 | ) | $ | 534 | $ | (20,351 | ) | |||||
Net change in unrealized gains on cash flow hedges, net of taxes of ($3,111) | 4,983 | — | — | 4,983 | ||||||||||||
Net change in minimum pension liability, net of taxes of $77 | — | (128 | ) | — | (128 | ) | ||||||||||
Change in foreign currency translation adjustment, net of taxes of ($427) | — | — | 381 | 381 | ||||||||||||
Balance at December 31, 2005 | $ | (12,860 | ) | $ | (3,170 | ) | $ | 915 | $ | (15,115 | ) | |||||
Net change in unrealized gains on cash flow hedges, net of taxes of ($38,625) | 64,099 | — | — | 64,099 | ||||||||||||
Net change in minimum pension liability, net of taxes of ($1,848) | — | 3,081 | — | 3,081 | ||||||||||||
Effect of adoption of SFAS No. 158, net of taxes of $8,447 | — | (14,079 | ) | — | (14,079 | ) | ||||||||||
Change in foreign currency translation adjustment, net of taxes of $507 | — | — | (826 | ) | (826 | ) | ||||||||||
Balance at December 31, 2006 | $ | 51,239 | $ | (14,168 | ) | $ | 89 | $ | 37,160 | |||||||
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Index to Financial Statements
| 15. | Subsequent Event-Stock Split |
On February 23, 2007 the Board of Directors declared a 2-for-1 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend will be distributed on March 30, 2007 to shareholders of record on March 16, 2007. The pro forma effect on the December 31, 2006 balance sheet is to reduce Additional Paid-in-Capital by $5.1 million and increase Common Stock by $5.1 million. Common shares outstanding, giving retroactive effect to the stock split at December 31, 2006 and 2005, would have been 96.2 million and 97.1 million, respectively. Weighted-average common shares outstanding, giving retroactive effect to the stock split at December 31, 2006, 2005 and 2004, would have been 96.8 million, 97.7 million and 97.5 million, respectively. Pro forma earnings per share, giving retroactive effect to the stock split are as follows:
| December 31, | |||||||||
| 2006 | 2005 | 2004 | |||||||
Basic Earnings per Share – as reported (pre-stock split) | $ | 6.64 | $ | 3.04 | $ | 1.81 | |||
Basic Earnings per Share – pro forma (post-stock split) | 3.32 | 1.52 | 0.91 | ||||||
Diluted Earnings per Share – as reported (pre-stock split) | 6.51 | 2.99 | 1.79 | ||||||
Diluted Earnings per Share – pro forma (post-stock split) | 3.26 | 1.49 | 0.90 | ||||||
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Index to Financial Statements
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
Estimates of proved and proved developed reserves at December 31, 2006, 2005, 2004, and 20032004 were based on studies performed by the Company’sCompany's petroleum engineering staff. The estimates were computed based on year end prices for oil, natural gas, and natural gas liquids. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 3, 2006,6, 2007, that based on their investigation and subject to the limitations described in their letter, they believe the results of those estimates and projections were reasonable in the aggregate.
No major discovery or other favorable or unfavorable event after December 31, 2005,2006, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following table illustrates the Company’s net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company’s engineering staff.
| Natural Gas | Natural Gas | |||||||||||||||||
| December 31, | December 31, | |||||||||||||||||
| (Millions of cubic feet) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||
Proved Reserves | ||||||||||||||||||
Beginning of Year | 1,134,081 | 1,069,484 | 1,060,959 | 1,262,096 | 1,134,081 | 1,069,484 | ||||||||||||
Revisions of Prior Estimates | (1,543 | ) | (7,850 | ) | (6,122 | ) | (17,675 | ) | (1,543 | ) | (7,850 | ) | ||||||
Extensions, Discoveries and Other Additions | 185,884 | 140,986 | 105,497 | 246,197 | 185,884 | 140,986 | ||||||||||||
Production | (73,879 | ) | (72,833 | ) | (71,906 | ) | (79,722 | ) | (73,879 | ) | (72,833 | ) | ||||||
Purchases of Reserves in Place | 17,567 | 5,384 | 1,590 | 1,946 | 17,567 | 5,384 | ||||||||||||
Sales of Reserves in Place | (14 | ) | (1,090 | ) | (20,534 | ) | (44,549 | ) | (14 | ) | (1,090 | ) | ||||||
End of Year | 1,262,096 | 1,134,081 | 1,069,484 | 1,368,293 | 1,262,096 | 1,134,081 | ||||||||||||
Proved Developed Reserves | 944,897 | 857,834 | 812,280 | 996,850 | 944,897 | 857,834 | ||||||||||||
Percentage of Reserves Developed | 74.9 | % | 75.6 | % | 76.0 | % | 72.9 | % | 74.9 | % | 75.6 | % | ||||||
Beginning of Year Revisions of Prior Estimates Extensions, Discoveries and Other Additions Production Purchases of Reserves in Place Sales of Reserves in Place End of Year Proved Developed Reserves Percentage of Reserves Developed Liquids December 31, (Thousands of barrels) 2005 2004 2003 Proved Reserves 11,384 12,103 18,393 1,073 185 307 334 1,074 1,723 (1,747 ) (2,002 ) (2,846 ) 419 24 — — — (5,474 ) 11,463 11,384 12,103 9,127 8,652 9,405 79.6 % 76.0 % 77.7 %
Index to Financial Statements
| Liquids | |||||||||
| December 31, | |||||||||
(Thousands of barrels) | 2006 | 2005 | 2004 | ||||||
Proved Reserves | |||||||||
Beginning of Year | 11,463 | 11,384 | 12,103 | ||||||
Revisions of Prior Estimates | 673 | 1,073 | 185 | ||||||
Extensions, Discoveries and Other Additions | 1,066 | 334 | 1,074 | ||||||
Production | (1,415 | ) | (1,747 | ) | (2,002 | ) | |||
Purchases of Reserves in Place | 38 | 419 | 24 | ||||||
Sales of Reserves in Place | (3,852 | ) | — | — | |||||
End of Year | 7,973 | 11,463 | 11,384 | ||||||
Proved Developed Reserves | 5,895 | 9,127 | 8,652 | ||||||
Percentage of Reserves Developed | 73.9 | % | 79.6 | % | 76.0 | % | |||
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.
| December 31, | December 31, | |||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities | $ | 2,290,147 | $ | 1,933,848 | $ | 1,732,236 | $ | 2,462,693 | $ | 2,290,147 | $ | 1,933,848 | ||||||
Aggregate Accumulated Depreciation, Depletion and Amortization | 1,052,654 | 940,447 | 837,060 | 983,079 | 1,052,654 | 940,447 | ||||||||||||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
| Year Ended December 31, | |||||||||
| (In thousands) | 2005 | 2004 | 2003 | ||||||
Property Acquisition Costs, Proved | $ | 73,127 | $ | 3,953 | $ | 1,524 | |||
Property Acquisition Costs, Unproved | 22,126 | 18,250 | 14,056 | ||||||
Exploration and Extension Well Costs(1) | 102,957 | 85,415 | 83,147 | ||||||
Development Costs | 208,124 | 136,311 | 77,006 | ||||||
Total Costs | $ | 406,334 | $ | 243,929 | $ | 175,733 | |||
| Year Ended December 31, | |||||||||
(In thousands) | 2006 | 2005 | 2004 | ||||||
Property Acquisition Costs, Proved | $ | 6,688 | $ | 73,127 | $ | 3,953 | |||
Property Acquisition Costs, Unproved | 42,551 | 22,126 | 18,250 | ||||||
Exploration and Extension Well Costs(1) | 109,525 | 102,957 | 85,415 | ||||||
Development Costs | 346,787 | 208,124 | 136,311 | ||||||
Total Costs | $ | 505,551 | $ | 406,334 | $ | 243,929 | |||
(1) | Includes administrative exploration costs of $13,486, $12,423 |
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Index to Financial Statements
Historical Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company’s oil and gas producing activities were as follows:
| Year Ended December 31, | |||||||||
| (In thousands) | 2005 | 2004 | 2003 | ||||||
Operating Revenues | $ | 581,849 | $ | 439,988 | $ | 404,503 | |||
Costs and Expenses | |||||||||
Production | 103,477 | 84,015 | 77,315 | ||||||
Other Operating | 30,120 | 27,787 | 20,090 | ||||||
Exploration(1) | 61,840 | 48,130 | 58,119 | ||||||
Depreciation, Depletion and Amortization | 119,122 | 114,906 | 195,659 | ||||||
Total Costs and Expenses | 314,559 | 274,838 | 351,183 | ||||||
Income Before Income Taxes | 267,290 | 165,150 | 53,320 | ||||||
Provision for Income Taxes | 100,353 | 60,361 | 18,662 | ||||||
Results of Operations | $ | 166,937 | $ | 104,789 | $ | 34,658 | |||
| Year Ended December 31, | |||||||||
(In thousands) | 2006 | 2005 | 2004 | ||||||
Operating Revenues | $ | 659,884 | $ | 581,849 | $ | 439,988 | |||
Costs and Expenses | |||||||||
Production | 115,786 | 103,477 | 84,015 | ||||||
Other Operating | 46,212 | 30,120 | 27,787 | ||||||
Exploration(1) | 49,397 | 61,840 | 48,130 | ||||||
Depreciation, Depletion and Amortization | 139,207 | 119,122 | 114,906 | ||||||
Total Costs and Expenses | 350,602 | 314,559 | 274,838 | ||||||
Income Before Income Taxes | 309,282 | 267,290 | 165,150 | ||||||
Provision for Income Taxes | 113,355 | 100,353 | 60,361 | ||||||
Results of Operations | $ | 195,927 | $ | 166,937 | $ | 104,789 | |||
(1) | Includes administrative exploration costs of $13,486, $12,423 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing SFAS No. 69,“Disclosures about Oil and Gas Producing Activities”, procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
Future costs and selling prices will probably differ from those required to be used in these calculations.
Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.
Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.
Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying year end oil and gas prices to the estimated future production of year end proved reserves.
The average prices related to proved reserves at December 31, 2006, 2005, 2004, and 20032004 for natural gas ($ per Mcf) were $5.54, $9.53 $6.26 and $5.96,$6.26, respectively, and for oil ($ per Bbl) were $59.50, $58.48 $41.24 and $30.94,$41.24, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS No. 69 requires the use of a 10% discount rate.
Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
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Index to Financial Statements
Standardized Measure is as follows:
| Year Ended December 31, | ||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | |||||||||
Future Cash Inflows | $ | 12,700,390 | $ | 7,561,728 | $ | 6,742,214 | ||||||
Future Production Costs | (2,271,917 | ) | (1,577,787 | ) | (1,390,398 | ) | ||||||
Future Development Costs | (536,333 | ) | (396,431 | ) | (310,923 | ) | ||||||
Future Income Tax Expenses | (3,588,877 | ) | (2,009,644 | ) | (1,800,519 | ) | ||||||
Future Net Cash Flows | 6,303,263 | 3,577,866 | 3,240,374 | |||||||||
10% Annual Discount for Estimated Timing of Cash Flows | (3,652,030 | ) | (1,997,509 | ) | (1,760,966 | ) | ||||||
Standardized Measure of Discounted Future Net Cash Flows(1) | $ | 2,651,233 | $ | 1,580,357 | $ | 1,479,408 | ||||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2006 | 2005 | 2004 | |||||||||
Future Cash Inflows | $ | 8,054,737 | $ | 12,700,390 | $ | 7,561,728 | ||||||
Future Production Costs | (2,000,993 | ) | (2,271,917 | ) | (1,577,787 | ) | ||||||
Future Development Costs | (688,955 | ) | (536,333 | ) | (396,431 | ) | ||||||
Future Income Tax Expenses | (1,763,458 | ) | (3,588,877 | ) | (2,009,644 | ) | ||||||
Future Net Cash Flows | 3,601,331 | 6,303,263 | 3,577,866 | |||||||||
10% Annual Discount for Estimated Timing of Cash Flows | (2,125,081 | ) | (3,652,030 | ) | (1,997,509 | ) | ||||||
Standardized Measure of Discounted Future Net Cash Flows(1) | $ | 1,476,250 | $ | 2,651,233 | $ | 1,580,357 | ||||||
(1) | The standardized measures of discounted future net cash flows before taxes were $2,010,228, $4,001,769 and $2,358,430 |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| (In thousands) | 2005 | 2004 | 2003 | 2006 | 2005 | 2004 | ||||||||||||||||||
Beginning of Year | $ | 1,580,357 | $ | 1,479,408 | $ | 1,255,353 | $ | 2,651,233 | $ | 1,580,357 | $ | 1,479,408 | ||||||||||||
Discoveries and Extensions, Net of Related Future Costs | 494,773 | 321,026 | 235,079 | 278,258 | 494,773 | 321,026 | ||||||||||||||||||
Net Changes in Prices and Production Costs | 1,278,303 | (17,976 | ) | 475,026 | (1,843,272 | ) | 1,278,303 | (17,976 | ) | |||||||||||||||
Accretion of Discount | 235,843 | 219,604 | 171,590 | 400,177 | 235,843 | 219,604 | ||||||||||||||||||
Revisions of Previous Quantity Estimates, Timing and Other | (49,550 | ) | (46,115 | ) | (35,691 | ) | (106,253 | ) | (49,550 | ) | (46,115 | ) | ||||||||||||
Development Costs Incurred | 61,802 | 32,940 | 27,529 | 85,993 | 61,802 | 32,940 | ||||||||||||||||||
Sales and Transfers, Net of Production Costs | (471,638 | ) | (357,939 | ) | (330,800 | ) | (544,650 | ) | (471,638 | ) | (357,939 | ) | ||||||||||||
Net Purchases (Sales) of Reserves in Place | 91,180 | 10,853 | (62,596 | ) | (261,795 | ) | 91,180 | 10,853 | ||||||||||||||||
Net Change in Income Taxes | (569,837 | ) | (61,444 | ) | (256,082 | ) | 816,559 | (569,837 | ) | (61,444 | ) | |||||||||||||
End of Year | $ | 2,651,233 | $ | 1,580,357 | $ | 1,479,408 | $ | 1,476,250 | $ | 2,651,233 | $ | 1,580,357 | ||||||||||||
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Index to Financial Statements
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
| (In thousands, except per share amounts) | First | Second | Third | Fourth | Total | ||||||||||
2005 | |||||||||||||||
Operating Revenues | $ | 144,074 | $ | 151,884 | $ | 161,757 | $ | 225,082 | $ | 682,797 | |||||
Impairment of Oil and Gas Properties (1) | — | — | — | — | — | ||||||||||
Operating Income | 38,044 | 61,722 | 59,023 | 99,942 | 258,731 | ||||||||||
Net Income | 20,762 | 35,422 | 33,756 | 58,505 | 148,445 | ||||||||||
Basic Earnings per Share (2) | 0.43 | 0.72 | 0.69 | 1.20 | 3.04 | ||||||||||
Diluted Earnings per Share (2) | 0.42 | 0.71 | 0.68 | 1.18 | 2.99 | ||||||||||
2004 | |||||||||||||||
Operating Revenues | $ | 136,604 | $ | 119,742 | $ | 119,423 | $ | 154,639 | $ | 530,408 | |||||
Impairment of Oil and Gas Properties (1) | — | — | 3,458 | — | 3,458 | ||||||||||
Operating Income | 36,090 | 36,439 | 34,278 | 53,846 | 160,653 | ||||||||||
Net Income | 19,011 | 19,318 | 17,822 | 32,227 | 88,378 | ||||||||||
Basic Earnings per Share (2) | 0.39 | 0.40 | 0.37 | 0.66 | 1.81 | ||||||||||
Diluted Earnings per Share (2) | 0.39 | 0.39 | 0.36 | 0.65 | 1.79 | ||||||||||
(In thousands, except per share amounts) | First | Second | Third | Fourth | Total | ||||||||||
2006 | |||||||||||||||
Operating Revenues | $ | 214,768 | $ | 190,794 | $ | 184,744 | $ | 171,682 | $ | 761,988 | |||||
Impairment of Oil and Gas Properties(1) | — | — | — | 3,886 | 3,886 | ||||||||||
Operating Income(2) (3) | 91,224 | 77,881 | 304,746 | 55,095 | 528,946 | ||||||||||
Net Income(2) | 53,165 | 46,864 | 189,020 | 32,126 | 321,175 | ||||||||||
Basic Earnings per Share | 1.09 | 0.96 | 3.92 | 0.67 | 6.64 | ||||||||||
Diluted Earnings per Share | 1.08 | 0.94 | 3.84 | 0.66 | 6.51 | ||||||||||
2005 | |||||||||||||||
Operating Revenues | $ | 144,074 | $ | 151,884 | $ | 161,757 | $ | 225,082 | $ | 682,797 | |||||
Impairment of Oil and Gas Properties(1) | — | — | — | — | — | ||||||||||
Operating Income | 38,044 | 61,722 | 59,023 | 99,942 | 258,731 | ||||||||||
Net Income | 20,762 | 35,422 | 33,756 | 58,505 | 148,445 | ||||||||||
Basic Earnings per Share | 0.43 | 0.72 | 0.69 | 1.20 | 3.04 | ||||||||||
Diluted Earnings per Share | 0.42 | 0.71 | 0.68 | 1.18 | 2.99 | ||||||||||
(1) | For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements. |
(2) |
|
(3) | Included in Operating Income in the first quarter is the cumulative effect loss of $0.4 million, previously reported in a separate line item below Operating Income. Due to immateriality for year end reporting purposes, this amount was reclassified to the General and Administrative Expense component of Operating Income in the Consolidated Statement of Operations. |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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Index to Financial Statements
ITEM 9A. CONTROLS AND PROCEDURES
| ITEM 9A. | CONTROLS AND PROCEDURES |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting
As of the end of December 31, 2005,2006, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’sCompany's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’sCompany's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act.
There were no significant changes in the Company’s internal control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation’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. 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.
Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005.2006. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2005,2006, the Company’s internal control over financial reporting is effective based on those criteria.
Cabot Oil & Gas Corporation’s independent registered public accounting firm has audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20052006 as stated in their report entitled “Report of Independent Registered Public Accounting Firm” which appears herein.
| ITEM 9B. | OTHER INFORMATION |
None.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information under the captions “Election of Directors”, “Audit Committee” and “Code of Business Conduct” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20062007 annual stockholders’ meeting are incorporated by reference.meeting. In addition, the information set forth under the caption “Business—Other“Business-Other Business Matters—CorporateMatters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this item.Item.
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Index to Financial Statements
ITEM 11. EXECUTIVE COMPENSATION
| ITEM 11. | EXECUTIVE COMPENSATION |
The information under the caption “Executive Compensation” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20062007 annual stockholders’ meeting is incorporated by reference.meeting.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The information under the captions “Beneficial Ownership of Over Five Percent of Common Stock”, “Beneficial Ownership of Directors and Executive Officers”, and “Equity Compensation Plan Information” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20062007 annual stockholders’ meeting aremeeting.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information required by this Item is incorporated by reference.reference to the Company’s definitive Proxy Statement in connection with the 2007 annual stockholders’ meeting.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The information under the caption “Fees Billedrequired by Independent Public Accountants for Services in 2005 and 2004” inthis Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20062007 annual stockholders’ meeting is incorporated by reference.meeting.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
A. INDEX
1. Consolidated Financial Statements
| 1. | Consolidated Financial Statements |
See Index on page 53.56.
2. Financial Statement Schedules
| 2. | Financial Statement Schedules |
None.
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3. Exhibits
Index to Financial Statements
| 3. | Exhibits |
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
Exhibit | Description | |||
3.1 | Certificate of Incorporation of the Company (Registration Statement No. 33-32553). | |||
3.2 | Amended and Restated Bylaws of the Company amended September 6, 2001 (Form 10-K for 2001). | |||
3.3 | Certificate of Amendment of Certificate of Incorporation (Form 8-K for July | |||
3.4 | Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July | |||
3.5 | Certificate of Amendment of Certificate of Incorporation (Form 8-K for June 1, 2006). | |||
3.6 | Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for June 1, 2006). | |||
4.1 | Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553). | |||
4.2 | Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994). | |||
4.3 | Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). | |||
| (a) | Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). | |||
| (b) | Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000). | |||
4.4 | Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). | |||
4.5 | Amended and Restated Credit Agreement dated as of May 30, 1995, among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein (Form 10-K for 1995). | |||
| (a) | Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995). | |||
| (b) | Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996). | |||
4.6 | Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997). | |||
4.7 | Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001). | |||
4.8 | Credit Agreement dated as of October 28, 2002 among the Company, the Banks Parties Hereto and Fleet National Bank, as administrative agent (Form 10-Q for the quarter ended September 30, 2002). | |||
| (a) | Amendment No. 1 to Credit Agreement dated December 10, 2004 (Form 10-K for 2004). | |||
*10.1 | Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2001). | |||
*10.2 | ||||
|
| |||
| Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991). | ||||
* | 1990 Non-employee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990). | |||
| (a) | First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994). | |||
| (b) | Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995). | |||
* | Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001) | |||
* | Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001). | |||
* | Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997). | |||
* | Deferred Compensation Plan of the Company as Amended September 1, 2001 (Form 10-K for 2001). | |||
10.8 | Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001). | |||
10.9 | Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998). | |||
10.10 | Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998). | |||
* | Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001). | |||
* | 2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004). | |||
| (a) First Amendment to the 2004 Incentive Plan effective February 23, 2007. | ||||
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Index to Financial Statements
Exhibit | Description | |||
* | 2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004). | |||
* | 2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form | |||
| 8-K for February 10, 2005). | ||||
* | Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005). | |||
* | 2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005). | |||
* | Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005). | |||
| (a) | First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005). | |||
| (b) | Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005). | |||
| (c) | Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005). | |||
*10.18 | Forms of Award Agreements for Executive Officers under 2004 Incentive Plan. | |||
| (a) Form of Restricted Stock Award Agreement. | ||||
| (b) Form of Stock Appreciation Rights Award Agreement. | ||||
| (c) Form of Performance Share Award Agreement. | ||||
10.19 | Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365). | |||
| (a) Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365). | ||||
| (b) Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365). | ||||
10.20 | Purchase and Sale Agreement dated August 25, 2006 between Cabot Oil & Gas Corporation, a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (Form 8-K for September 29, 2006). | |||
*10.21 | Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006). | |||
*10.22 | Savings Investment Plan of the Company, as amended and restated effective January 1, 2006. | |||
*10.23 | Pension Plan of the Company, as amended and restated effective January 1, 2006. | |||
14.1 | Amendment of Code of Business Conduct (as amended on July 28, 2005 to revise Section III. F. relating to | |||
| Transactions in Securities and Article V. relating to Safety, Health and the Environment) (Form 10-Q for the quarter ended June 30, 2005). | ||||
21.1 | Subsidiaries of Cabot Oil & Gas Corporation. | |||
23.1 | Consent of PricewaterhouseCoopers LLP. | |||
23.2 | Consent of Miller and Lents, Ltd. | |||
31.1 | 302 Certification – Chairman, President and Chief Executive Officer. | |||
| |||
| 302 Certification – Vice President and Chief Financial Officer. | |||
32.1 | 906 Certification. | ||
99.1 | Miller and Lents, Ltd. Review Letter. | ||
| * | Compensatory plan, contract or arrangement. |
- 110 -
Index to Financial Statements
SIGNATURES
Pursuant to the requirements of Section 13 and 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, in the City of Houston, State of Texas, on the6th 28th of March 2006.February 2007.
CABOT OIL & GAS CORPORATION | ||
By: | /s/ Dan O. Dinges | |
| Dan O. Dinges | ||
| Chairman, President and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Dan O. Dinges Dan O. Dinges | Chairman, President and Chief Executive Officer (Principal Executive Officer) | |||
/s/ Scott C. Schroeder Scott C. Schroeder | Vice President and Chief Financial Officer (Principal Financial Officer) | |||
/s/ Henry C. Smyth Henry C. Smyth | Vice President, Controller and Treasurer (Principal Accounting Officer) | |||
| ||||
/s/ John G. L. Cabot John G. L. Cabot | Director | |||
/s/ David M. Carmichael David M. Carmichael | Director | |||
/s/ James G. Floyd James G. Floyd | Director | |||
/s/ Robert L. Keiser Robert L. Keiser | Director | |||
/s/ Robert Kelley Robert Kelley | Director | |||
| ||||
/s/ P. Dexter Peacock P. Dexter Peacock | Director | |||
/s/ William P. Vititoe William P. Vititoe | Director | |||
99- 111 -