Part II
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with Item 6, Selected Financial Data, and the Consolidated Financial Statements at Item 15(a). Unless otherwise indicated, throughout this discussion the term “Mcfe” refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Overview
Our business is to produce and sell natural gas, natural gas liquids and crude oil from our predominantly southwestern and central U.S. properties, most of which we operate. Because our gathering, processing and marketing functions are ancillary to and dependent upon our production of natural gas, natural gas liquids and crude oil, we have determined that our business comprises only one industry segment.
In 2007, we achieved the following record financial and operating results:
- Average daily gas production was 1.46 Bcf, a 23% increase from 2006, average daily oil production was 47,047 Bbls, a 4% increase from 2006, and average daily natural gas liquids production was 13,545 Bbls, a 14% increase from 2006.
- Year-end proved reserves were 11.29 Tcfe, a 32% increase from year-end 2006.
- Cash flow from operating activities was $3.6 billion, a 27% increase from 2006.
- Year-end stockholders’ equity was $7.9 billion, a 35% increase from year-end 2006.
We achieve production and proved reserve growth primarily through acquisitions of both producing and unproved properties, followed by low-risk development generally funded by cash flow from operating activities. Funding sources for our acquisitions include proceeds from sales of public and private equity and debt, bank or commercial paper borrowings and cash flow from operating activities. During 2007, we acquired $3.2 billion of proved properties with proved reserves of 1.3 Tcf of natural gas, 2.7 million Bbls of natural gas liquids and 11.3 million Bbls of oil, as well as $831 million of unproved properties.
In a trend that began in 2004 and accelerated during 2005 and the first half of 2006, commodity prices for natural gas, natural gas liquids and oil increased significantly (see “Significant Events, Transactions and Conditions — Product Prices”). The higher prices have led to increased activity in the industry and, consequently, rising costs. Drilling rig counts are at levels not seen since the last boom in the early 1980s and labor to run the rigs is in short supply. This was further aggravated by the damage in the Gulf of Mexico as a result of the August and September 2005 hurricanes. These cost trends have put pressure not only on our operating costs but also our capital costs. With the increased activity, there is also increased demand for oil and gas properties which has resulted in higher acquisition prices. While prices for natural gas have been relatively flat since the second half of 2006, oil prices in the second half of 2007 began to increase significantly. The leveling off of natural gas prices has resulted in slowing cost inflation.
Like all oil and gas exploration and production companies, we face the challenge of natural production decline. An oil and gas exploration and production company depletes part of its asset base with each unit of production. Despite this natural decline, we have been able to grow our production through acquisitions and drilling, adding more reserves than we produce. We also attempt to manage our natural decline by combining the acquisition of mature properties with shallower decline rates with the drilling of new wells that have higher decline rates. This has allowed us to keep our natural decline rate lower than the industry average. Future growth will depend on our ability to continue to add reserves in excess of production.
Our goal for 2008 is to increase production by 20%. To achieve future production and reserve growth, we will continue to pursue acquisitions that meet our criteria and to complete development projects included in our inventory of between 9,500 and 10,300 identified potential drilling locations. Our 2008 development budget is $2.6 billion. While an acquisition budget has not been formalized, we expect to complete acquisitions of both producing and unproved properties for approximately $1.0 billion, during the first quarter of 2008. These acquisitions will be funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering and are subject to typical post-closing adjustments. We plan to actively review additional acquisition opportunities during 2008. We cannot ensure that we will be able to find properties that meet our acquisition criteria and that we can purchase such properties on acceptable terms (see “Liquidity and Capital Resources — Capital Expenditures”).
Increased activity in the oil and gas producing industry has also had an effect on our ability to hire qualified people including not only operational employees, but also all classifications of industry-specific professionals. We continue to find the employees we need to adequately staff our operations; however, the cost of hiring and the time to fill positions has increased. Our employee turnover continues to remain low with total turnover of 9.6% in 2007 and 8.4% in 2006.
In the event that our operating cash flow exceeds our development, exploration and acquisition capital needs, we will consider other alternative uses for this cash including, but not limited to, debt repayment or stock repurchases. In August 2004, the Board of Directors authorized the repurchase of up to 25 million shares of our common stock from time to time in the open market or negotiated transactions. As of December 31, 2007, 2.8 million shares have been repurchased under this authorization.
Sales prices for our natural gas, oil and natural gas liquids production are influenced by supply and demand conditions over which we have little or no control, including weather and regional and global economic conditions. To provide predictable production growth, we may hedge a portion of our production at commodity prices management deems attractive to ensure stable cash flow margins to fund our operating commitments and development program. As of February 2008, we have hedged approximately 65% of our 2008 projected gas production at an average NYMEX price of $8.32 per Mcf, about 60% of our 2008 crude oil production at an average NYMEX price of $74.20 per Bbl and about 30% of our 2008 natural gas liquids production at an average price of $44.22 per Bbl. Our average realized price on hedged production will be lower than these average NYMEX prices because of location, quality and other adjustments.
The combined effect of higher product prices, a 23% increase in gas production, a 4% increase in oil production and a 14% increase in natural gas liquids production resulted in a 20% increase in total revenues to $5.5 billion in 2007 from $4.6 billion in 2006. On an Mcfe produced basis, total revenues were $8.29 in 2007, a 1% increase from $8.21 in 2006.
We analyze, on an Mcfe produced basis, expenses that generally trend with changes in production:
2007 |
2006 |
Increase |
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| Production | $ | 0.93 | $ | 0.88 | 6% |
| Taxes, transportation and other | 0.67 | 0.67 | – | ||
| Depreciation, depletion and amortization | 1.78 | 1.57 | 13% | ||
| Accretion of discount in asset retirement obligation | 0.03 | 0.03 | – | ||
| General and administrative, excluding stock compensation | 0.25 | 0.22 | 14% | ||
| Interest | 0.38 | 0.32 | 19% | ||
| $ | 4.04 | $ | 3.69 | 9% | |
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Production expense per Mcfe rose 6% primarily because of increased maintenance costs. Taxes, transportation and other expense generally is based on product revenues. An increase in transportation and other expense as a result of higher product prices was offset by lower production taxes and lower property taxes. The lower production taxes were primarily due to the benefit of increased gas volumes from new drill wells which were subject to reduced production tax rates. The 13% increase in depreciation, depletion and amortization per Mcfe resulted from higher acquisition, development and facility costs. The 14% increase in all other general and administrative expense per Mcfe is because of increased personnel and other costs related to Company growth. The 19% increase in interest expense is primarily because of an increase in weighted average borrowings to fund recent acquisitions.
Significant expenses that generally do not trend with production include:
Stock compensation. Stock compensation expense was $65 million in 2007 compared to $63 million in 2006.
Derivative fair value (gain) loss. This is the net realized and unrealized gain or loss on derivative financial instruments that does not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. The net derivative fair value gain was $11 million in 2007 compared to $102 million in 2006.
Our primary sources of liquidity are cash flow from operating activities, borrowings under either our revolving credit agreement, our commercial paper program, or our other unsecured and uncommitted lines of credit and public and private offerings of equity and debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk (See “Liquidity and Capital Resources — Financing”).
Significant Events, Transactions and Conditions
The following events, transactions and conditions affect the comparability of results of operations and financial condition for each of the years ended December 31, 2007, 2006 and 2005 and may impact future operations and financial condition.
Acquisitions. We acquired proved and unproved properties at a total cost of $4.0 billion in 2007, $786 million in 2006 and $2.0 billion in 2005, which were funded by a combination of proceeds from sales of common stock and senior notes, bank borrowings and cash flow from operating activities. The following are significant acquisitions in each of these years:
Closing Date |
Seller |
Amount (in millions) |
Acquisition Area |
||
| 2007 | July | Dominion Resources, Inc. | $ 2,576 (a) | Rocky Mountain Region, San Juan Basin and South Texas | |
| October | Various | 550 | Barnett Shale of North Texas | ||
| 2006 | February | Total E&P USA, Inc. | 300 | East Texas and Mississippi | |
| June | Peak Energy Resources Inc. | 150 (b) | Barnett Shale of North Texas | ||
| 2005 | April | Antero Resources Corporation | 814 (c) | Barnett Shale of North Texas | |
| May | Plains Exploration & Production Company | 336 | East Texas and northwestern Louisiana | ||
| July | ExxonMobil Corporation | 200 | Permian Basin of West Texas and New Mexico | ||
(a) Represents a portion of the allocated purchase price of Dominion Resources, Inc. and includes an allocation of $2.5 billion to proved properties and $73 million to unproved properties. See Note 13 to the Consolidated Financial Statements. (b) Represents a portion of the allocated purchase price of Peak Energy Resources, Inc. and includes an allocation of $97 million to proved properties and $53 million to unproved properties. See Note 13 to the Consolidated Financial Statements. (c) Represents a portion of the allocated purchase price of Antero Resources Corporation and includes an allocation of $634 million to proved properties and $180 million to unproved properties. See Note 13 to the Consolidated Financial Statements. |
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2007, 2006 and 2005 Development and Exploration Programs. Gas development focused on the Eastern and North Texas Regions during 2007, 2006 and 2005. Oil development was concentrated primarily in the Permian Region during all three years. Development costs totaled $2.5 billion in 2007, $2.0 billion in 2006 and $1.3 billion in 2005. Exploration activity in 2007 and 2006 was primarily drilling and geological and geophysical analysis, including seismic studies of underdeveloped properties in South Texas. Exploratory costs were $257 million in 2007, $123 million in 2006 and $52 million in 2005. Our development and exploration activities are generally funded by cash flow from operations.
2008 Acquisition, Development and Exploration Program. We have budgeted $2.6 billion for our 2008 development and exploration program, which we expect to fund using cash flow from operations. While an acquisition budget has not been formalized, we expect to complete acquisitions of both producing and unproved properties for approximately $1.0 billion during the first quarter of 2008. These acquisitions will be funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering and are subject to typical post-closing adjustments. We plan to continue to actively review additional acquisition opportunities during 2008. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, public or private issuance of debt or equity, or asset sales. The cost of 2008 property acquisitions may alter the amount currently budgeted for development and exploration. Our total budget for acquisitions, development and exploration will be adjusted throughout 2008 to focus on opportunities offering the highest rates of return. Additionally, $400 million has been budgeted for the construction of pipeline infrastructure and compression and processing facilities.
As of December 31, 2007, we have an inventory of between 9,500 and 10,300 identified potential drilling locations. We plan to drill about 1,160 (980 net) development wells and perform approximately 750 (600 net) workovers and recompletions in 2007. Drilling plans are dependent upon product prices.
Product Prices. In addition to supply and demand, oil and gas prices are affected by seasonal, political and other conditions we generally cannot control or predict.
Gas. Natural gas prices are affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquefied natural gas. Natural gas competes with alternative energy sources as fuel for heating and the generation of electricity. Natural gas prices rose sharply in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production with gas prices reaching a peak in excess of $15.00 per MMBtu. During most of 2006, gas prices trended lower primarily because of an adequate natural gas supply inventory due to the warmer than normal winter weather and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound, however, the absence of hurricane activity in the Gulf of Mexico in 2007 has kept prices relatively flat. We expect prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to gas price fluctuations. The following are comparative average gas prices for the last three years:
Year Ended December 31 |
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(per Mcf) |
2007 |
2006 |
2005 |
|||
| Average NYMEX price | $ | 6.86 | $ | 7.23 | $ | 8.62 |
| Average realized sales price | $ | 7.50 | $ | 7.69 | $ | 7.04 |
| Average realized sales price excluding hedging | $ | 6.26 | $ | 6.26 | $ | 7.38 |
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At February 12, 2008, the average NYMEX gas price for the following 12 months was $8.91 per MMBtu. As computed on an energy equivalent basis, our proved reserves were 84% natural gas at December 31, 2007. After considering hedges in place as of February 15, 2008, we estimate that a $0.10 per Mcf change in the average gas sales price would result in approximately a $20 million change in 2008 annual operating cash flow before income taxes.
Oil. Crude oil prices are generally determined by global supply and demand. Oil prices have risen primarily because of increasing global demand and supply shortage concerns, inadequate sour crude refining capacity, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico in 2005 and political instability in some oil producing countries. In the last few months of 2007 and early 2008, rising tensions in the Middle East, weakness in the dollar and strong demand caused prices to reach record levels of $100 per Bbl. We expect oil prices to remain volatile. As described under “Hedging Activities” below, we use commodity price hedging instruments to reduce our exposure to oil price fluctuations. The following are comparative average oil prices for the last three years:
Year Ended December 31 |
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(per Bbl) |
2007 |
2006 |
2005 |
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| Average NYMEX price | $ | 72.39 | $ | 66.22 | $ | 56.57 |
| Average realized sales price | $ | 70.08 | $ | 60.96 | $ | 47.03 |
| Average realized sales price excluding hedging | $ | 68.68 | $ | 60.79 | $ | 52.28 |
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At February 12, 2008, the average NYMEX oil price for the following 12 months was $91.91 per Bbl. After considering hedges in place as of February 15, 2008, we estimate that a $1.00 per barrel change in the average oil sales price would result in approximately a $7 million change in 2008 annual operating cash flow before income taxes.
Gulf of Mexico Hurricanes. In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. The Company’s field operations and production were substantially unaffected by these hurricanes. Production expense and development costs, however, increased throughout the industry because of storm damages and related supply shortages and higher insurance costs.
Hedging Activities. We may enter futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts, to hedge our exposure to product price volatility. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive. While there is a risk we may not be able to realize the full benefit of rising prices, management plans to continue its hedging strategy because of the benefits of predictable, stable cash flows.
In 2007, all hedging activities increased gas revenue by $658 million and oil revenue by $24 million. In 2006, all hedging activities increased gas revenue by $618 million and oil revenue by $3 million. In 2005, all hedging activities decreased gas revenue by $127 million and oil revenue by $75 million.
The following summarizes our 2008 NYMEX hedging positions under futures contracts and swap agreements as of February 2008, excluding basis adjustments.
Our average daily production was 1.67 Bcf of gas, 48,844 Bbls of oil and 14,462 Bbls of natural gas liquids in fourth quarter 2007. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments. See Note 8 to the Consolidated Financial Statements.
Natural Gas |
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Production Period |
Mcf per Day |
Average |
||
| 2008 | January to March | 1,100,000 | $ | 8.33 |
| April to December | 1,200,000 | $ | 8.32 | |
Crude Oil |
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Production Period |
Bbls per Day |
Average |
||
| 2008 | January to December | 30,000 | $ | 74.20 |
Natural Gas Liquids |
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Production Period |
Bbls per Day |
Average |
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| 2008 | January to December | 5,000 | $ | 44.22 |
Derivative Fair Value (Gain) Loss. We record in our income statements realized and unrealized derivative fair value gains and losses related to derivatives that do not qualify for hedge accounting, as well as the ineffective portion of hedge derivatives. We recorded net derivative fair value gains of $11 million in 2007, $102 million in 2006 and $13 million in 2005. Of these amounts, an $11 million gain in 2007, a $67 million gain in 2006 and a $1 million loss in 2005 was due to the ineffective portion of hedge derivatives. These ineffective hedge derivative gains and losses are primarily because of fluctuating oil and gas prices and their effect on hedges of production in areas without corresponding basis or location differential swap contracts.
Derivative fair value (gain) loss includes a net gain related to our Btu swap contracts of $16 million in 2006 and a net loss of $23 million in 2005. The remaining portion of these contracts was terminated as of February 28, 2006.
Unrealized derivative gains and losses associated with effective cash flow hedges are recorded in stockholders’ equity as accumulated other comprehensive income (loss). At December 31, 2007, we have an unrealized pre-tax loss of $52 million in accumulated other comprehensive income (loss) related to the fair value of derivatives designated as cash flow hedges of natural gas, crude oil and natural gas liquids price risk. Based on December 31 mark-to-market prices, all of this fair value loss is expected to be reclassified into earnings in 2008. The actual reclassification to earnings will be based on mark-to-market prices at contract settlement date.
Stock-Based Compensation. Stock compensation totaled $65 million in 2007, $63 million in 2006 and $34 million in 2005. Included in stock option expense in 2006 is $36 million related to options granted in the second quarter which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. As of December 31, 2007, stock compensation expense is expected to total $92 million in 2008, $46 million in 2009, and $21 million in 2010 related to all outstanding stock awards.
Hugoton Royalty Trust Distribution. In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded. We recorded this dividend at $614 million, or approximately $1.35 per common share, the fair market value of the units based on the May 12, 2006 average high and low New York Stock Exchange trade price of $28.31. After considering the cost of the trust units, we recorded a gain on distribution of $469 million before income tax.
Senior Note Offerings. In April 2005, we sold $400 million of 5.3% senior notes due June 2015. In March 2006, we sold $400 million of 5.65% senior notes due April 2016 and $600 million of 6.1% senior notes due April 2036. In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007. Proceeds from the senior notes were used to fund property acquisitions and reduce bank debt.
Common Stock Transactions. In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc.
In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $1.0 billion of property acquisitions expected to close in first quarter 2008 and to repay indebtedness under our commercial paper program.
Shelf Registration Statement. In June 2006, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which could include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities are to be used for general corporate purposes, including the reduction of bank debt.
In June 2006, we registered 3.2 million shares of our common stock, which were issued in the acquisition of Peak Energy Resources on June 30, 2006.
Results of Operations
2007 Compared to 2006
For the year 2007, net income was $1.7 billion compared with net income of $1.9 billion for 2006. Earnings for 2007 include the net after-tax effects of a $28 million non-cash derivative fair value loss. Earnings for 2006 include the net after-tax effects of a $295 million gain on the distribution of Hugoton Royalty Trust units, a $24 million non-cash derivative fair value gain and $34 million of income tax expense related to enactment of a State of Texas margin tax.
Revenues for 2007 were $5.5 billion, or 20% higher than 2006 revenues of $4.6 billion. Gas and natural gas liquids revenue increased $724 million, or 21%, because of a 23% increase in gas production, a 14% increase in natural gas liquids production and a 23% increase in natural gas liquids prices from an average price of $37.03 per Bbl in 2006 to $45.37 in 2007, partially offset by a 2% decrease in gas prices from an average of $7.69 per Mcf in 2006 to $7.50 in 2007 (see “Significant Events, Transactions and Conditions — Product Prices — Gas” above). Increased production was attributable to the 2007 acquisition and development program.
Oil revenue increased $202 million, or 20%, because of a 4% increase in production, primarily due to the 2007 acquisition and development program, and a 15% increase in oil prices from an average of $60.96 per Bbl in 2006 to $70.08 in 2007 (see “Significant Events, Transactions and Conditions — Product Prices — Oil” above).
Gas gathering, processing and marketing activities resulted in a net contribution of $19 million in 2007 compared to a net contribution of $45 million in 2006. The decreased net contribution was primarily due to higher costs.
Expenses for 2007 totaled $2.6 billion as compared with total 2006 expenses of $1.9 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $124 million, or 25%, primarily because of increased overall production and higher maintenance costs. The per Mcfe production expense increase from $0.88 in 2006 to $0.93 in 2007 is primarily attributable to the increased maintenance costs. Taxes, transportation and other expense increased 19%, or $72 million, primarily because of higher product revenues. Taxes, transportation and other per Mcfe was $0.67 in both 2007 and 2006. An increase in transportation and other expense as a result of higher product prices was offset by lower production taxes and lower property taxes. The lower production taxes were primarily due to the benefit of increased gas volumes from new drill wells which were subject to reduced production tax rates. Exploration expense increased $30 million primarily because of increased seismic costs in South Texas and unsuccessful exploratory wells.
Depreciation, depletion and amortization (DD&A) increased $312 million, or 36% primarily because of increased production. On an Mcfe basis, DD&A increased 13% from $1.57 in 2006 to $1.78 in 2007 because of higher acquisition, development and facility costs.
General and administrative expense increased $42 million (22%). Of this increase, $2 million was the result of an increase in non-cash incentive award compensation. Included in 2006 non-cash incentive award compensation was $36 million related to options granted in the second quarter which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. Excluding this charge, non-cash incentive award compensation increased $38 million in 2007 primarily as a result of additional incentive award grants since last year as well as an increase in the fair value of each award granted. Increased general and administrative expense, excluding non-cash incentive award compensation, is primarily because of higher employee expenses related to Company growth. Excluding non-cash incentive award compensation, general and administrative expense per Mcfe increased 14% from $0.22 in 2006 to $0.25 in 2007.
The derivative fair value gain for 2007 was $11 million compared to $102 million in 2006. The 2007 gain is primarily related to the ineffective portion of hedge derivatives. The 2006 gain is primarily related to the ineffective portion of hedge derivatives as well as a $16 million gain on the final settlement of Btu swap contracts. See Note 7 to Consolidated Financial Statements.
Interest expense increased $70 million, or 39%, primarily because of a 43% increase in the weighted average borrowings to partially fund property acquisitions partially offset by higher interest income related to increased cash on hand and an increase in capitalized interest. Interest expense per Mcfe increased 19% from $0.32 in 2006 to $0.38 in 2007. The 2007 effective income tax rate was 36.0%, as compared with a 37.2% effective rate for 2006. Excluding the effect of the $34 million income tax expense related to a State of Texas margin tax, the effective tax rate for the 2006 period was 36.0%. The current portion of total income taxes was 31% in 2007 and 52% in 2006. Excluding the effect of the gain on the distribution of Hugoton Royalty Trust units, the current portion of total income taxes was 39% in 2006. The decline in the current portion of total income taxes was primarily due to increased development costs in 2007.
2006 Compared to 2005
For the year 2006, net income was $1.9 billion compared with net income of $1.2 billion for 2005. Earnings for 2006 include the net after-tax effects of a $295 million gain on the distribution of Hugoton Royalty Trust units, a $24 million non-cash derivative fair value gain and $34 million of income tax expense related to enactment of a new State of Texas margin tax. Earnings for 2005 include the net after-tax effects of non-cash incentive compensation of $22 million, a $25 million non-cash derivative fair value gain and a gain of $6 million on the exchange of producing properties.
Revenues for 2006 were $4.6 billion, or 30% higher than 2005 revenues of $3.5 billion. Gas and natural gas liquids revenue increased $703 million, or 25%, because of a 15% increase in gas production and a 9% increase in gas prices from an average of $7.04 per Mcf in 2005 to $7.69 in 2006, as well as a 13% increase in natural gas liquids production and a 9% increase in natural gas liquids prices from an average price of $34.10 per Bbl in 2005 to $37.03 in 2006 (see “Significant Events, Transactions and Conditions — Product Prices — Gas” above). Increased production was attributable to the 2006 acquisition and development program.
Oil revenue increased $332 million, or 50%, because of a 15% increase in production, primarily due to the 2006 acquisition and development program, and a 30% increase in oil prices from an average of $47.03 per Bbl in 2005 to $60.96 in 2006 (see “Significant Events, Transactions and Conditions — Product Prices — Oil” above).
Gas gathering, processing and marketing activities resulted in a contribution of $45 million in both 2006 and 2005. In 2005, other revenues of $6 million were primarily related to a net gain on sale or exchange of producing properties. See Note 13 to Consolidated Financial Statements.
Expenses for 2006 totaled $1.9 billion as compared with total 2005 expenses of $1.6 billion. Increased expenses are generally related to increased production from acquisitions and development and related Company growth. Production expense increased $85 million, or 21%, primarily because of increased overall production, and higher labor, fuel, compression and maintenance costs. The per Mcfe production expense increase from $0.84 in 2005 to $0.88 in 2006 is primarily attributable to the increased maintenance and workover costs and the higher cost of electricity. Taxes, transportation and other expense, which is generally directly related to product revenue, increased 22%, or $66 million, primarily because of increased transportation and other expense related to higher product prices. Taxes, transportation and other per Mcfe increased 6% from $0.63 in 2005 to $0.67 in 2006 primarily due to increased transportation and other expense as a result of higher product prices. Exploration expense decreased $2 million primarily because of decreased seismic work in the Barnett Shale.
Depreciation, depletion and amortization (DD&A) increased $220 million, or 34%, primarily because of increased production. On an Mcfe basis, DD&A increased 16% from $1.35 in 2005 to $1.57 in 2006 because of higher acquisition, development and infrastructure costs.
General and administrative expense increased $34 million (22%). Excluding a $24 million decrease in non-cash performance and restricted share award compensation related to performance and restricted share grants to employees and a $53 million charge for expensing stock options related to the adoption of SFAS No. 123R in 2006, general and administrative expense increased $5 million (4%). Increased general and administrative expense is primarily because of higher employee expenses related to Company growth. Included in stock option expense in the 2006 period is $36 million related to options granted in the second quarter which were subject to accelerated vesting provisions upon retirement under employment agreements for certain employees. As required under SFAS No. 123R, stock option awards subject to such vesting provisions granted to retirement-eligible employees are expensed upon grant, rather than over the expected vesting period. Excluding stock compensation, general and administrative expense per Mcfe decreased 12% from $0.25 in 2005 to $0.22 in 2006.
The derivative fair value gain for 2006 was $102 million compared to $13 million in 2005. The 2006 gain is primarily related to the ineffective portion of hedge derivatives as well as a $16 million gain on the final settlement of Btu swap contracts. The 2005 gain is primarily because of a $37 million gain related to natural gas basis swap agreements not qualifying for hedge accounting, partially offset by losses on Btu swap contracts. See Note 7 to Consolidated Financial Statements.
Interest expense increased $27 million, or 18%, primarily because of a 14% increase in the weighted average borrowings to partially fund property acquisitions and a 10% increase in the weighted average interest rate due to increases in short-term rates. Interest expense per Mcfe increased 3% from $0.31 in 2005 to $0.32 in 2006.
The 2006 effective income tax rate was 37.2%, as compared with a 36.3% effective rate for 2005. Excluding the effect of the $34 million income tax expense related to a new State of Texas margin tax enacted during second quarter, the effective tax rate for the 2006 period was 36%. The lower rate in 2006 is because of the benefit of certain nonrecurring permanent tax over book differences which was partially offset by increased income taxes in states other than Texas. Because of increased profit in 2006 and greater utilization of net operating loss carryforwards in 2005, the current portion of total income tax expense increased from 37% in 2005 to 52% in 2006.
Liquidity and Capital Resources
Our primary sources of liquidity are cash provided by operating activities, borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit or our commercial paper program, occasional proved property sales and private or public offerings of equity and debt. Other than for operations, our cash requirements are generally for the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. We believe that our sources of liquidity are adequate to fund our cash requirements in 2008.
Cash provided by operating activities was $3.6 billion in 2007, compared with cash provided by operating activities of $2.9 billion in 2006 and $2.1 billion in 2005. Increased cash provided by operating activities from 2006 to 2007 and from 2005 to 2006 was primarily because of increased production from acquisitions and development activity, and higher price realizations in 2006 compared to 2005. Cash provided by operating activities was decreased by changes in operating assets and liabilities of $72 million in 2007 and $158 million in 2005 and was increased by changes in operating assets and liabilities of $5 million in 2006. Changes in operating assets and liabilities are primarily the result of timing of cash receipts and disbursements. Cash provided by operating activities was also reduced by exploration expense (net of dry hole expense beginning in 2006) of $31 million in 2007, $13 million in 2006 and $24 million in 2005. Cash provided by operating activities is largely dependent upon the prices received for oil and gas production. As of February 2008, we have hedged approximately 65% of our 2008 projected gas production, about 60% of our projected 2008 crude oil production and about 30% of our projected 2008 natural gas liquids production. See “Significant Events, Transactions and Conditions — Product Prices” above.
Financial Condition
Total assets increased 47% from $12.9 billion at December 31, 2006 to $18.9 billion at December 31, 2007, primarily because of Company growth related to acquisitions and development. As of December 31, 2007, total capitalization was $14.3 billion, of which 44% was long-term debt. Capitalization at December 31, 2006 was $9.3 billion, of which 37% was long-term debt. The increase in the debt-to-capitalization ratio from year-end 2006 to 2007 is primarily because of increased borrowings to partially fund property acquisitions.
Working Capital
We generally maintain low cash and cash equivalent balances because we use available funds to reduce either bank debt or borrowings under our commercial paper program. Short-term liquidity needs are satisfied by either bank commitments under our loan agreements or our commercial paper program (see “Financing” below). Because of this, and since our principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. Working capital declined from $345 million at December 31, 2006 to a negative position of $250 million at December 31, 2007. Excluding the effects of derivative fair value and deferred tax current assets and liabilities, working capital decreased $71 million from a negative position of $159 million at December 31, 2006 to a negative position of $230 million at December 31, 2007. This decrease is because of increased accounts payable and accrued liabilities primarily related to increased production and drilling liabilities partially offset by increased accounts receivable related to increased revenues and increased current income taxes receivable. Any cash settlement of hedge derivatives should generally be offset by increased or decreased cash flows from our sales of related production. Therefore, we believe that most of the changes in derivative fair value assets and liabilities are offset by changes in value of our oil and gas reserves. This offsetting change in value of oil and gas reserves, however, is not recorded in the financial statements.
When the monthly cash settlement amount under our hedge derivatives is calculated, if market prices are higher than the fixed contract prices, we are required to pay the contract counterparties. While this payment will ultimately be funded by higher prices received from sale of our production, production receipts lag payments to the counterparties by as much as 55 days. Any interim cash needs are funded by borrowings under either our revolving credit agreement, our other unsecured and uncommitted lines of credit, or our commercial paper program. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.
Most of our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. We currently have the majority of our credit exposure with several A- or better rated integrated energy companies. Financial and commodity-based futures and swap contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, and we have master netting agreements with counterparties that provide for offsetting payables against receivables from separate derivative contracts. Letters of credit or other appropriate forms of security are obtained as considered necessary to limit risk of loss.
Financing
On December 31, 2007, we had no borrowings under our revolving credit agreement with commercial banks, and we had available borrowing capacity of $1.2 billion net of our commercial paper borrowings. In February 2008, we amended this agreement to, among other things, increase the borrowing capability to $2.5 billion and to extend the maturity date to April 1, 2013. We have annual options to request successive one-year extensions and an option to increase the commitment up to an additional $1.0 billion. The interest rate on any borrowing is generally based on the LIBOR plus 0.40%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. We also incur a commitment fee on unused borrowing commitments, which is 0.09%. The agreement requires us to maintain a debt-to-total capitalization ratio of not more than 65%. We use the facility for general corporate purposes and as a backup facility for our commercial paper program (see below). We did not make any borrowings under our revolving credit facility during 2007.
In February 2008, we increased our commercial paper program availability to $2.5 billion. Borrowings under the commercial paper program reduce our available capacity under the revolving credit facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms up to 397 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. On December 31, 2007, borrowings were $772 million at an interest rate of 5.38%.
In February 2008, we also amended our $300 million term loan credit agreement to increase outstanding borrowings to $500 million and to extend the maturity date to April 1, 2013. In March 2007, we amended our $300 million term loan credit agreement to conform its covenants and pricing to our bank revolving credit agreement and to extend the maturity.
Additionally in February 2008, we entered into a new five-year unsecured term loan agreement with The Royal Bank of Scotland Finance (Ireland) that provides for a maximum loan amount of $100 million available in a single advance that matures February 5, 2013. The interest rate is currently based on LIBOR plus 0.34%, and interest is paid at least quarterly. Other terms and conditions are substantially the same as our term loan. The proceeds were used for general corporate purposes.
We have unsecured and uncommitted lines of credit with commercial banks totaling $300 million. As of December 31, 2007, there were no borrowings under these lines.
In February 2008, we completed a public offering of 23 million common shares at $55.00 per share. After underwriting discount and other offering costs of $42 million, net proceeds of $1.2 billion were used to fund a portion of the $1.0 billion of property acquisitions expected to close in first quarter 2008 and to repay indebtedness under our commercial paper program.
In June 2007, we completed a public offering of 21.6 million common shares at $48.40 per share. After underwriting discount and other offering costs of $35 million, net proceeds of $1.0 billion were used to fund a portion of the acquisition of natural gas and oil properties from Dominion Resources, Inc.
In July 2007, we sold $300 million of 5.9% senior notes due August 1, 2012, $450 million of 6.25% senior notes due August 1, 2017 and $500 million of 6.75% senior notes due August 1, 2037. In August 2007, we sold an additional $250 million of the 5.9% senior notes, $300 million of the 6.25% senior notes and $450 million of the 6.75% senior notes that constituted a further issuance of the senior notes issued in July 2007. Together, the 5.9% senior notes were issued at 100.585% of par to yield 5.761% to maturity. The 6.25% senior notes were issued at 100.419% of par to yield 6.193% to maturity. The 6.75% senior notes were issued at 100.022% of par to yield 6.748% to maturity. Interest is payable on each series of notes on February 1 and August 1 of each year, beginning February 1, 2008. Net proceeds of $2.24 billion were used to fund a portion of the acquisition of properties from Dominion Resources, Inc. and to pay down outstanding commercial paper borrowings.
Possible Formation of a Master Limited Partnership
In conjunction with our announcement of the Dominion acquisition, we disclosed our intent to review our entire portfolio of producing properties, including those acquired in the acquisition, for selective inclusion in a potential master limited partnership to be formed by us with an initial capitalization of over $500 million. In February 2008, we announced that we would not pursue the formation of a master limited partnership at this time.
Capital Expenditures
In 2007, exploration and development cash expenditures totaled $2.7 billion compared with $2.1 billion in 2006. We have budgeted $2.6 billion for the 2008 development and exploration program and an additional $400 million for the construction of pipeline infrastructure and compression and processing facilities. As we have done historically, we expect to fund the 2008 development program with cash flow from operations. We have the flexibility to adjust our actual development expenditures in response to changes in product prices, industry conditions and the effects of our acquisition and development programs.
Raw material shortages and strong global demand for steel have caused prices to remain high. In response, we maintain a large tubular inventory and have contracts with our suppliers to support our development program. While we expect to acquire adequate supplies to complete our development program, a further tightening of steel supplies could restrain the program, limiting production growth and increasing development costs.
Although drilling rigs have been in short supply throughout the industry, we have secured or contracted to secure the rigs necessary to support our current drilling program.
While an acquisition budget has not been formalized, we expect to complete acquisitions of both producing and unproved properties for approximately $1 billion during the first quarter of 2008. These acquisitions will be funded both by commercial paper borrowings and by proceeds from the February 2008 common stock offering and are subject to typical post-closing adjustments. We plan to actively review additional acquisition opportunities during 2008. If acquisition, development and exploration expenditures exceed cash flow from operations, we expect to obtain additional funding through our bank credit facilities, our commercial paper program, issuance of public or private debt or equity, or asset sales. Other than the requirement for us to maintain a debt-to-total capitalization ratio of not more than 65%, there are no restrictions under our revolving credit agreement that would affect our ability to use our remaining borrowing capacity.
To date, we have not spent significant amounts to comply with environmental or safety regulations, and we do not expect to do so during 2008. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.04 per common share for the first three quarters of 2005, $0.06 per common share for fourth quarter 2005 and the first three quarters of 2006, $0.072 per common share for fourth quarter 2006 and $0.096 per common share for the first three quarters of 2007. In November 2007, the Board of Directors declared a five-for-four stock split of its common stock and increased its quarterly dividend to $0.12 per common share for the fourth quarter 2007, effecting a 25% dividend increase. On February 19, 2008, the Board of Directors declared a first quarter 2008 dividend of $0.12 per common share.
In January 2006, the Board of Directors declared a dividend to common stockholders, consisting of all 21.7 million Hugoton Royalty Trust units owned by us. The dividend ratio of 0.047688 trust units for each common share outstanding was set on the record date of April 26, 2006. The units were distributed on May 12, 2006, when this dividend was recorded at approximately $1.35 per common share, based on the fair market value of the units on that date.
Our ability to pay dividends is dependent upon our financial condition, earnings and cash flow from operations, the level of our capital expenditures, our future business prospects and other matters our Board deems relevant.
Off-Balance Sheet Arrangements
We do not have any investments in unconsolidated entities or persons that could materially affect the liquidity or the availability of capital resources. Under the terms of some of our operating leases for compressors, airplanes and vehicles, we have various residual value guarantees and other payment provisions upon our election to return the equipment under certain specified conditions. Guarantees related to these leases are not material. The only material off-balance sheet arrangements that we have entered into are those disclosed in the following table of contractual obligations and commitments.
Contractual Obligations and Commitments
The following summarizes our significant obligations and commitments to make future contractual payments as of December 31, 2007. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses.
Payments Due by Year |
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(in millions) |
Total |
2008 |
2009 |
2010 |
2011 |
2012 |
After 2012 |
|||||||
| Long-term debt | $ | 6,320 | $ | – | $ | – | $ | – | $ | – | $ | 1,975 | $ | 4,345 |
| Operating leases | 92 | 24 | 21 | 19 | 13 | 7 | 8 | |||||||
| Drilling contracts | 218 | 142 | 61 | 15 | – | – | – | |||||||
| Purchase commitments | 173 | 147 | 26 | – | – | – | – | |||||||
| Transportation contracts | 999 | 117 | 122 | 121 | 116 | 107 | 416 | |||||||
| Derivative contract liabilities at December 31, 2007 fair value | 243 | 239 | 3 | 1 | – | – | – | |||||||
| Total | $ | 8,045 | $ | 669 | $ | 233 | $ | 156 | $ | 129 | $ | 2,089 | $ | 4,769 |
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Long-Term Debt. At December 31, 2007, borrowings were $772 million under our commercial paper program. Because we had both the intent and ability to refinance the balance due with borrowings under our credit facility due in April 2012, the $772 million outstanding under the commercial paper program is reflected in the table above as due in 2012. Borrowings of $300 million under our term loan are due in April 2012, and our senior notes, totaling $5.2 billion at December 31, 2007, are due 2012 through 2037. In February 2008, we extended the maturities of both our credit facility and our term loan to April 2013. For further information regarding long-term debt, see Note 3 to Consolidated Financial Statements.
Transportation Contracts. We have entered firm transportation contracts with various pipelines for various terms through 2022. Under these contracts we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. We have generally delivered at least minimum volumes under these firm transportation contracts, therefore avoiding payment for deficiencies.
In December 2006, we entered into a ten-year firm transportation contract that commences upon completion of a new 502-mile pipeline spanning from southeast Oklahoma to east Alabama. Upon the pipeline’s completion, currently expected in first quarter 2009, we will transport gas volumes for a minimum transportation fee of $2 million per month plus fuel not to exceed 1.2% of the sales price, depending on receipt point and other conditions. The potential effect of this agreement is not included in the above summary of our transportation contract commitments since our commitment is contingent upon completion of the pipeline.
Derivative Contracts. We have entered into futures contracts and swaps to hedge our exposure to natural gas, oil and natural gas liquids price fluctuations. As of December 31, 2007, the market prices generally exceeded fixed prices specified by these contracts, resulting in a derivative fair value net current liability of $40 million and a net long-term liability of $4 million. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2007, the current liability related to such contracts was $239 million and the noncurrent liability was $4 million. While such payments generally will be funded by higher prices received from the sale of our production, production receipts may be received as much as 55 days after payment to counterparties and can result in draws on our revolving credit facility, our other unsecured and uncommitted lines of credit or our commercial paper program. See Note 7 to Consolidated Financial Statements.
Post-Retirement Plans
We have a retiree medical plan that provides retired employees and directors with health care benefits similar to those provided employees. Employees are eligible to receive benefits when their combined age and years of qualified service total 60, with a minimum age of 50 and a minimum of 10 years of service. However, employees who were eligible under the previous eligibility rules were grandfathered in under the previous rules which allowed them to receive benefits when their combined age and years of qualified service totaled 60, with a minimum age of 45 and a minimum of five years of service. Directors are still eligible to receive benefits when their combined age and years of qualified service total 60, with a minimum age of 45 and a minimum of five years of service. Otherwise, retirement benefits are only provided through our defined contribution 401(k) plan. Post-retirement medical benefits are not prefunded but are paid when incurred. Our periodic benefit cost recorded for 2007 was $2 million and is expected to be approximately $3 million in 2008. Future benefit costs will be affected by fluctuations in interest rates and health care cost trends. We do not currently anticipate that retiree medical plan costs will be significant in relation to the Company’s future financial position, results of operations or cash flows.
Related Party Transactions
A firm, affiliated with one of our nonemployee directors, has performed property acquisition advisory services for the Company. In February 2005, this firm was acquired by another company which continues to perform property acquisition advisory services for us, and a division of the company also performed co-manager services on our June 2007 common stock offering and our July and August 2007, March 2006 and April 2005 senior note offerings. We paid this firm total fees of $3.4 million in 2007, $78,500 in 2006 and $5.0 million in 2005, and there were no amounts payable at December 31, 2007 or 2006. In February 2008, this firm served as one of 24 co-managers on our common stock offering.
In February 2007, in recognition of the Chairman and Chief Executive Officer of the Company and as part of a charitable giving program to support higher education, the Board of Directors approved a conditional contribution of $6.8 million to assist in building an athletics and academic center at Baylor University. This contribution is to be paid in two equal installments of $3.4 million. The first payment was made May 2007 and the second is expected to be paid in the first half of 2008. Since this is a conditional contribution, the first payment is included as general and administrative expense in 2007. However, the second payment will not be made and included in general administrative expense until such time as the condition is satisfied. Concurrently, our Chairman and Chief Executive Officer, made a $3.2 million pledge for the same project. In return for these contributions, the Company and Mr. Simpson obtained naming rights for the building and certain facilities within the building.
In November 2007, the Board of Directors approved and we paid our Chairman and Chief Executive Officer $150,000 for an easement across his property in North Texas. The easement was for approximately 10,000 feet at the standard easement rate in the area of $15 per foot.
Critical Accounting Policies and Estimates
Our financial position and results of operations are significantly affected by accounting policies and estimates related to our oil and gas properties, proved reserves, asset retirement obligation and commodity prices and risk management, as summarized below.
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for their property costs using either the “successful efforts” or “full cost” accounting method. Under the successful efforts method, unsuccessful exploratory well costs, as well as all exploratory geological and geophysical costs, are expensed. Under the full cost method, all exploration costs are capitalized, regardless of success. Selection of the oil and gas accounting method can have a significant impact on a company’s financial results. We use the successful efforts method of accounting and generally pursue acquisitions and development of proved reserves as opposed to exploration activities.
In accordance with Statement of Financial Accounting Standards No. 144, we evaluate possible impairment of producing properties when conditions indicate that the properties may be impaired. Such conditions include a significant decline in product prices which we believe to be other than temporary or a significant downward revision in estimated proved reserves for a field or area. An impairment provision must be recorded to adjust the net book value of the property to its estimated fair value if the net book value exceeds the estimated future net cash flows from the property. The estimated fair value of the property is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flows are based on the latest available proved reserve and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices and industry forecasts and analysis.
The impairment assessment process is primarily dependent upon the estimate of proved reserves. Any overstatement of estimated proved reserve quantities would result in an overstatement of estimated future net cash flows, which could result in an understated assessment of impairment. The subjectivity and risks associated with estimating proved reserves are discussed under “Oil and Gas Reserves” below. Prediction of product prices is subjective since prices are largely dependent upon supply and demand resulting from global and national conditions generally beyond our control. However, management’s assessment of product prices for purposes of impairment is consistent with that used in its business plans and investment decisions. While there is judgment involved in management’s estimate of future product prices, the potential impact on impairment is not currently significant since current and projected product prices are substantially higher than our net acquisition and development costs per Mcfe. Because of this, our historical impairment of producing properties has been limited to a $2 million provision in 1998. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
Oil and Gas Reserves
Our proved oil and gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.
Proved reserves, as defined by the Financial Accounting Standards Board and adopted by the Securities and Exchange Commission, are limited to reservoir areas that indicate economic producibility through actual production or conclusive formation tests, and generally cannot extend beyond the immediately adjoining undrilled portion. Although improved technology often can identify possible or probable reserves other than by drilling, these reserves cannot be estimated and disclosed.
Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition. As shown in Note 15 to the Consolidated Financial Statements, net upward revisions occurred to proved reserves on an Mcfe basis in 2007 and 2005, resulting in a decrease of DD&A expense of approximately 1%, or $13 million in 2007 and 2%, or $10 million, in 2005. Net downward revisions of proved reserves on an Mcfe basis occurred in 2006, resulting in an increase in DD&A expense of approximately 1%, or $8 million in 2006. Based on proved reserves at December 31, 2007, we estimate that a 1% change in proved reserves would increase or decrease 2008 DD&A expense by approximately $13 million.
During 2007, development and exploration activities resulted in extensions, additions, discoveries and net revisions of proved reserves that were 308% of our 2007 production. Over the last five years, our proved reserve extensions, additions, discoveries and net revisions averaged 262% of our production for this period. Our proved reserve extensions, additions and discoveries in 2007 included an increase of 1.5 Tcfe in proved undeveloped reserves, or approximately 75% of our total extensions, additions and discoveries. The remaining extensions, additions and discoveries were proved developed reserves. Over the past five years, approximately 73% of our proved reserves extensions, additions and discoveries were proved undeveloped reserves. These proved undeveloped reserve extensions, additions and discoveries were generally reclassified to proved developed reserves within three years. Development of our proved undeveloped reserves is not subject to significant uncertainties such as regulatory approvals, and we believe that we have adequate resources to develop these reserves, dependent on commodity prices not declining significantly. We believe that reserve additions, comparable to these historical reserve additions, are attainable in the near term future, subject to product prices and development costs remaining at levels to ensure economic viability.
The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 15 to Consolidated Financial Statements, are prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2007, we revised our existing estimated asset retirement obligation by $39 million, or approximately 13% of the asset retirement obligation at December 31, 2006, based on a review of current plugging and abandonment costs. Over the past four years, revisions to the estimated asset retirement obligation averaged approximately 12% of the asset retirement obligation at the beginning of the year. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Commodity Prices and Risk Management
Commodity prices significantly affect our operating results, financial condition, cash flows and ability to borrow funds. Current market oil and gas prices are affected by supply and demand as well as seasonal, political and other conditions which we generally cannot control. Oil and gas prices and markets are expected to continue their historical volatility. See “Significant Events, Transactions and Conditions — Product Prices” above.
We attempt to reduce our price risk on a portion of our production by entering into financial instruments such as futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. While these instruments secure a certain price and, therefore, a certain cash flow, there is the risk that we may not be able to realize the full benefit of rising prices. These contracts also expose us to credit risk of nonperformance by the contract counterparties, all of which are major investment grade financial institutions. We attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of security.
While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under U.S. generally accepted accounting principles, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. Derivatives that provide effective cash flow hedges are designated as hedges, and, to the extent the hedge is determined to be effective, we defer related unrealized fair value gains and losses in accumulated other comprehensive income (loss) until the hedged transaction occurs. See “Derivatives” under Note 1 to Consolidated Financial Statements regarding our accounting policy related to derivatives.
See also “Commodity Price Risk” under Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for the effect of price changes on derivative fair value gains and losses.
Accounting Pronouncements
In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements, was issued. SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. In November 2007, the effective date was deferred for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value on a recurring basis. The provisions of SFAS No. 157 that were not deferred are effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 157, effective January 1, 2008, did not have a significant effect on our reported financial position or earnings.
In February 2007, SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115, was issued. SFAS No. 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159, effective January 1, 2008, did not have a significant effect on reported financial position or earnings.
In December 2007, SFAS No. 141R, Business Combinations, was issued. Under SFAS No. 141R, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. It further requires that research and development assets acquired in a business combination that have no alternative future use to be measured at their acquisition-date fair value and then immediately charged to expense, and that acquisition-related costs are to be recognized separately from the acquisition and expensed as incurred. Among other changes, this statement also requires that “negative goodwill” be recognized in earnings as a gain attributable to the acquisition, and any deferred tax benefits resultant in a business combination are recognized in income from continuing operations in the period of the combination. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. The effect of adopting SFAS No. 141R has not been determined, but it is not expected to have a significant effect on our reported financial position or earnings.
In December 2007, SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, was issued. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Among other requirements, this statement requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. The effect of adopting SFAS No. 160 is not expected to have an effect on our reported financial position or earnings.
Production Imbalances
We have gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well, or by cash payment by the overproduced party to the underproduced party. We use the entitlement method of accounting for natural gas sales. Accordingly, revenue is deferred for gas deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Our net gas imbalance receivable of $1 million at December 31, 2007 was reported in the balance sheet as a $1 million net current receivable. At December 31, 2006, our net gas imbalance payable of $2 million was reported in the balance sheet as a $3 million net current receivable and a $5 million net long-term payable.
Forward-Looking Statements
Certain information included in this annual report and other materials filed or to be filed by us with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by us, contain projections and forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to our operations and the oil and gas industry. Such forward-looking statements may be or may concern, among other things, capital expenditures in total or by region, capital budget, cash flow, drilling activity, drilling locations, the number of wells to be drilled, worked over or recompleted in total or by region, acquisition and development activities and funding thereof, production and reserve growth, pricing differentials, reserve potential, operating costs, operating margins, production activities, oil, gas and natural gas liquids reserves and prices, hedging activities and the results thereof, liquidity, debt repayment, unused borrowing capacity, estimated stock award vesting periods, completion of pipelines and processing facilities, regulatory matters, competition, and value of non-cash dividends. Such forward-looking statements are based on management’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “predicts,” “anticipates,” “believes,” “estimates,” “goal,” “should,” “could,” “assume,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are discussed in Item 1A, Risk Factors.