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| NFX > SEC Filings for NFX > Form 10-Q on 24-Jul-2009 | All Recent SEC Filings |
24-Jul-2009
Quarterly Report
We are an independent oil and gas company engaged in the exploration, development and acquisition of natural gas and crude oil properties. Our domestic areas of operation include the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. Internationally, we are active in Malaysia and China.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and gas reserves. We use the full cost method of accounting for our oil and gas activities.
Oil and Natural Gas Prices. Prices for oil and natural gas fluctuate widely. Oil and natural gas prices affect:
• the amount of cash flow available for capital expenditures;
• our ability to borrow and raise additional capital;
• the quantity of oil and gas that we can economically produce; and
• the accounting for our oil and gas activities including, among other items, the determination of ceiling test writedowns.
An extended decline in oil and natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. Please see the discussion under "Lower oil and gas prices and other factors resulted in a ceiling test writedown and may in the future result in additional ceiling test writedowns or other impairments" in Item 1A of our annual report on Form 10-K for the year ended December 31, 2008 and "- Liquidity and Capital Resources" below.
As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs.
Reserve Replacement. To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and gas reserves.
Significant Estimates. We believe the most difficult, subjective or complex judgments and estimates we must make in connection with the preparation of our financial statements are:
• the quantity of our proved oil and gas reserves;
• the timing of future drilling, development and abandonment activities;
• the cost of these activities in the future;
• the fair value of the assets and liabilities of acquired companies;
• the fair value of our financial instruments including derivative positions; and
• the fair value of stock-based compensation.
Accounting for Hedging Activities. We do not designate price risk management activities as accounting hedges. Because hedges not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. As of June 30, 2009, we had derivative assets of $650 million, of which 51% was measured based upon our valuation model and, as such, is classified as a Level 3 fair value measurement. We value these contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties. Please see Note 7, "Derivative Financial Instruments," and Note 13, "Fair Value Measurements," to our consolidated financial statements appearing earlier in this report for a discussion of the accounting applicable to our oil and gas derivative contracts.
Other factors. Please see "Risk Factors" in Item 1A of our annual report on Form 10-K for the year ended December 31, 2008 and Item 1A of this report for a discussion of a number of other factors that affect our business, financial condition and results of operations. This report should be read together with those discussions.
Results of Operations
Revenues. All of our revenues are derived from the sale of our oil and gas production. The effects of the settlement of hedges designated for hedge accounting are included in revenue, but those not so designated have no effect on our reported revenues. None of our outstanding oil and gas hedging contracts as of June 30, 2009 are designated for hedge accounting and the settlement of all oil and gas hedging contracts during the second quarter and first six months of 2009 and 2008 had no effect on reported revenues. Please see Note 7, "Derivative Financial Instruments," to our consolidated financial statements appearing earlier in this report for a discussion of the accounting applicable to our oil and gas derivative contracts.
Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold. In addition, crude oil from our operations offshore Malaysia and China is produced into FPSOs and "lifted" and sold periodically as barge quantities are accumulated. Revenues are recorded when oil is lifted and sold, not when it is produced into the FPSO. As a result, the timing of liftings may impact period to period results.
Revenues of $287 million for the second quarter of 2009 were 59% lower than the comparable period of 2008. Revenues of $549 million for the first six months of 2009 were 55% lower than the comparable period of 2008. The revenue decrease during both periods is due to significantly lower average realized oil and natural gas prices partially offset by higher oil and gas production.
Three Months Ended Percentage Six Months Ended Percentage
June 30, Increase June 30, Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
Production (1):
Domestic:
Natural gas (Bcf) 45.2 43.7 4 % 90.1 84.1 7 %
Oil and condensate (MBbls) 1,869 1,528 22 % 3,637 2,950 23 %
Total (Bcfe) 56.4 52.9 7 % 111.9 101.8 10 %
International:
Natural gas (Bcf) - - - - - -
Oil and condensate (MBbls) 1,365 793 72 % 2,566 1,830 40 %
Total (Bcfe) 8.2 4.7 72 % 15.4 11.0 40 %
Total:
Natural gas (Bcf) 45.2 43.7 4 % 90.1 84.1 7 %
Oil and condensate (MBbls) 3,234 2,321 39 % 6,203 4,780 30 %
Total (Bcfe) 64.6 57.6 12 % 127.3 112.8 13 %
Average Realized Prices (2):
Domestic:
Natural gas (per Mcf) $ 2.85 $ 9.86 (71 )% $ 3.16 $ 8.75 (64 )%
Oil and condensate (per Bbl) 49.24 110.87 (56 )% 40.98 98.41 (58 )%
Natural gas equivalent (per Mcfe) 3.92 11.35 (65 )% 3.88 10.08 (62 )%
International:
Natural gas (per Mcf) $ - $ - - $ - $ - -
Oil and condensate (per Bbl) 47.29 112.85 (58 )% 44.19 97.29 (55 )%
Natural gas equivalent (per Mcfe) 7.86 18.81 (58 )% 7.36 16.22 (55 )%
Total:
Natural gas (per Mcf) $ 2.85 $ 9.86 (71 )% $ 3.16 $ 8.75 (64 )%
Oil and condensate (per Bbl) 48.42 111.55 (57 )% 42.31 97.98 (57 )%
Natural gas equivalent (per Mcfe) 4.42 11.97 (63 )% 4.30 10.67 (60 )%
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(1) Represents volumes lifted and sold regardless of when produced.
(2) Had we included the effects of hedging contracts not designated for hedge accounting, our average realized price for total gas would have been $6.21 and $7.95 per Mcf for the three months ended June 30, 2009 and 2008, respectively, and $5.84 and $7.92 per Mcf for the six months ended June 30, 2009 and 2008, respectively. Our total oil and condensate average realized price would have been $76.09 and $85.42 per Bbl for the three months ended June 30, 2009 and 2008, respectively, and $75.29 and $77.08 per Bbl for the six months ended June 30, 2009 and 2008, respectively. All amounts for the three and six months ended June 30, 2008 exclude the cash payments to reset our 2009 and 2010 crude oil hedges of $488 million and $502 million, respectively.
Domestic Production. Our three and six months ended June 30, 2009 domestic oil and gas production (stated on a natural gas equivalent basis) increased over the comparable periods of 2008 primarily due to increased production in our Mid-Continent and Rocky Mountain divisions as a result of continued successful drilling efforts.
International Production. Our three and six months ended June 30, 2009 international oil production (stated on a natural gas equivalent basis) increased over the comparable periods of 2008 primarily due to the new field development on PM 323 in Malaysia and the timing of liftings of our oil production in Malaysia.
Operating Expenses. We believe the most informative way to analyze changes in our operating expenses from period to period is on a unit-of-production, or per Mcfe, basis.
The following table presents information about our operating expenses for the three months ended June 30, 2009 and 2008.
Unit-of-Production Total Amount
Three Months Ended Percentage Three Months Ended Percentage
June 30, Increase June 30, Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(Per Mcfe) (In millions)
Domestic:
Lease operating $ 0.80 $ 0.87 (8 )% $ 45 $ 46 (2 )%
Production and other taxes 0.21 0.42 (50 )% 12 22 (47 )%
Depreciation, depletion
and amortization 1.94 2.79 (30 )% 110 148 (26 )%
General and administrative 0.57 0.69 (17 )% 32 36 (12 )%
Other 0.09 - 100 % 5 - 100 %
Total operating expenses 3.61 4.77 (24 )% 204 252 (19 )%
International:
Lease operating $ 1.44 $ 2.44 (41 )% $ 12 $ 12 (1 )%
Production and other taxes 0.34 6.33 (95 )% 3 30 (91 )%
Depreciation, depletion
and amortization 3.33 3.78 (12 )% 27 18 52 %
General and administrative 0.22 0.28 (21 )% 2 1 37 %
Total operating expenses 5.33 12.83 (58 )% 44 61 (28 )%
Total:
Lease operating $ 0.88 $ 1.00 (12 )% $ 57 $ 58 (1 )%
Production and other taxes 0.23 0.91 (75 )% 15 52 (72 )%
Depreciation, depletion
and amortization 2.12 2.87 (26 )% 137 166 (17 )%
General and administrative 0.52 0.65 (20 )% 34 37 (10 )%
Other 0.08 - 100 % 5 - 100 %
Total operating expenses 3.83 5.43 (29 )% 248 313 (21 )%
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Domestic Operations. Our domestic operating expenses for the three months ended June 30, 2009, stated on a Mcfe basis, decreased 24% over the same period of 2008. The components of the period to period change are as follows:
• Lease operating expense (LOE) per Mcfe decreased 8% primarily due to lower operating costs for all of our operations.
• Production and other taxes per Mcfe decreased 50% primarily due to significantly lower realized commodity prices during the second quarter of 2009 compared to the same period of 2008.
• Our depreciation, depletion and amortization (DD&A) rate per Mcfe decreased 30% primarily as a result of the ceiling test writedowns recorded at December 31, 2008 and March 31, 2009.
• General and administrative (G&A) expense per Mcfe decreased 17% primarily due to a decrease in incentive compensation expense, which is calculated based on adjusted net income (as defined in our incentive compensation plan). Adjusted net income for purposes of our incentive compensation plan excludes (a) unrealized gains and losses on commodity derivatives and (b) the impact from any full cost ceiling test writedowns. Additionally, we match the costs / benefits of the 2008 crude oil hedge unwind / reset with the period in which these barrels are produced for the purposes of determining adjusted net income. During the second quarter of 2009, we capitalized $15 million of direct internal costs as compared to $13 million in the second quarter of 2008.
International Operations. Our international operating expenses for the three months ended June 30, 2009, stated on a Mcfe basis, decreased 58% over the same period of 2008. The components of the period to period change are as follows:
• LOE per Mcfe decreased 41% while total LOE remained flat period over period. The decrease in LOE per Mcfe is primarily due to increased production volumes associated with the new field development on PM 323 in Malaysia and lower operating costs.
• Production and other taxes decreased significantly due to substantially lower oil prices during the second quarter of 2009.
• The DD&A rate on an Mcfe basis decreased slightly while total DD&A expense increased 52% primarily due to the additional production volumes associated with the new field development on PM 323 in Malaysia.
• G&A expense decreased $0.06 per Mcfe primarily due to the 72% increase in production volumes period over period.
The following table presents information about our operating expenses for the six months ended June 30, 2009 and 2008.
Unit-of-Production Total Amount
Six Months Ended Percentage Six Months Ended Percentage
June 30, Increase June 30, Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(Per Mcfe) (In millions)
Domestic:
Lease operating $ 0.93 $ 0.91 2 % $ 104 $ 93 12 %
Production and other taxes 0.17 0.43 (60 )% 18 44 (58 )%
Depreciation, depletion
and amortization 2.18 2.79 (22 )% 244 284 (14 )%
General and administrative 0.57 0.66 (14 )% 64 67 (4 )%
Ceiling test writedown 12.02 - 100 % 1,344 - 100 %
Other 0.06 - 100 % 7 - 100 %
Total operating expenses 15.93 4.79 233 % 1,781 488 266 %
International:
Lease operating $ 1.57 $ 2.20 (29 )% $ 24 $ 24 -
Production and other taxes 0.34 5.41 (94 )% 6 59 (91 )%
Depreciation, depletion
and amortization 3.39 3.58 (5 )% 52 39 33 %
General and administrative 0.13 0.19 (32 )% 2 2 (4 )%
Total operating expenses 5.43 11.38 (52 )% 84 124 (33 )%
Total:
Lease operating $ 1.00 $ 1.03 (3 )% $ 128 $ 117 10 %
Production and other taxes 0.19 0.92 (79 )% 24 103 (77 )%
Depreciation, depletion
and amortization 2.32 2.86 (19 )% 296 323 (8 )%
General and administrative 0.52 0.61 (15 )% 66 69 (4 )%
Ceiling test writedown 10.56 - 100 % 1,344 - 100 %
Other 0.05 - 100 % 7 - 100 %
Total operating expenses 14.64 5.42 170 % 1,865 612 205 %
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Domestic Operations. Our domestic operating expenses for the six months ended June 30, 2009, stated on a Mcfe basis, increased 233% over the same period of 2008 primarily due to a full cost ceiling test writedown recorded at March 31, 2009. The components of the period to period change are as follows:
• LOE per Mcfe increased 2% primarily due to increased well workover activity associated with our onshore Texas and deepwater Gulf of Mexico operations compared to the same period of 2008.
• Production and other taxes per Mcfe decreased 60% primarily due to significantly lower realized commodity prices during the first six months of 2009 compared to the same period of 2008.
• Our DD&A rate per Mcfe decreased 22% primarily as a result of the ceiling test writedowns recorded at December 31, 2008 and March 31, 2009.
• G&A expense per Mcfe decreased 14% primarily due to a decrease in incentive compensation expense, which is calculated based on adjusted net income (as defined in our incentive compensation plan). Adjusted net income for purposes of our incentive compensation plan excludes (a) unrealized gains and losses on commodity derivatives and (b) the impact from any full cost ceiling test writedowns. Additionally, we match the costs / benefits of the 2008 crude oil hedge unwind / reset with the period in which these barrels are produced for the purposes of determining adjusted net income. During the first six months of 2009, we capitalized $28 million of direct internal costs as compared to $24 million in the first six months of 2008.
• We recorded a ceiling test writedown of $1.3 billion ($12.02 per Mcfe) due to significantly lower natural gas prices at March 31, 2009.
International Operations. Our international operating expenses for the six months ended June 30, 2009, stated on a Mcfe basis, decreased 52% over the same period of 2008. The period to period change was primarily related to the following items:
• LOE per Mcfe decreased 29% while total LOE remained flat period over period. The decrease in LOE per Mcfe is primarily due to increased production volumes associated with the new field development on PM 323 in Malaysia and lower operating costs.
• Production and other taxes decreased significantly due to substantially lower oil prices during the first six months of 2009.
• The DD&A rate on an Mcfe basis decreased slightly while total DD&A expense increased 33% during the first six months of 2009 primarily due to the additional production volumes associated with the new field development on PM 323 in Malaysia.
• G&A expense per Mcfe decreased $0.06 primarily due to the 40% increase in total international production volumes period over period.
Commodity Derivative Income (Expense)
Commodity derivative expense during the second quarter of 2009 decreased $571 million over the same period of 2008 and commodity derivative income for the first six months of 2009 increased $1.2 billion over the same period of 2008. The significant fluctuation from period to period is due to the extreme volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.
Interest Expense
The following table presents information about interest expense for the
indicated periods.
Three Months Ended Six Months Ended
June 30, June 30,
2009 2008 2009 2008
(In millions)
Gross interest expense:
Credit
arrangements $ 2 $ 2 $ 5 $ 3
Senior notes 3 3 6 7
Senior subordinated
notes 26 21 51 35
Other 1 2 2 2
Total gross interest
expense 32 28 64 47
Capitalized
interest (12 ) (13 ) (26 ) (27 )
Net interest
expense $ 20 $ 15 $ 38 $ 20
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The increase in gross interest expense for both the three and six month periods ended June 30, 2009 over the comparable prior periods resulted primarily from the May 2008 issuance of $600 million principal amount of our 7 1/8% Senior Subordinated Notes due 2018.
Taxes. The effective tax rates for the second quarter of 2009 and 2008 were 35.4% and 15.6%, respectively. The effective tax rates for the first six months of 2009 and 2008 were 36.4% and 22.3%, respectively. The change in our effective tax rates for the three and six month periods ended June 30, 2008 as compared to the comparable periods of 2009 were due to significant changes in the proportion of our 2008 book income in separate state taxing jurisdictions compared to total consolidated domestic book income. Certain corporate items, such as hedging losses, are not includable in determining taxable income for the state of Oklahoma; however these items are included in the determination of consolidated U.S. federal income taxes. Our effective tax rate for all periods was different than the federal statutory tax rate due to deductions that do not generate tax benefits, state income taxes and the differences between international and U.S. federal statutory rates. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
Liquidity and Capital Resources
We must find new and develop existing reserves to maintain and grow our production and cash flow. We accomplish this through successful drilling programs and the acquisition of properties. These activities require substantial capital expenditures. Lower prices for oil and natural gas may reduce the amount of oil and gas that we can economically produce, and can also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as further described below.
We establish a capital budget at the beginning of each calendar year. In light of the current economic outlook and commodity price environment, we intend to limit our 2009 capital expenditures to a level that we expect can be funded with cash flow from operations, thereby preserving liquidity under our credit arrangements. Our 2009 capital budget focuses on those projects that we believe will generate and lay the foundation for production growth. We have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations.
Although our 2009 capital budget is set at a level that we believe corresponds with our anticipated 2009 cash flows, the timing of capital expenditures and the receipt of cash flows do not necessarily match, and we anticipate borrowing and repaying funds under our credit arrangements throughout the year. For example, our capital expenditures were front-end loaded and we outspent cash flows in the first half of 2009. We may have to further reduce capital expenditures and our ability to execute our business plans could be diminished if (1) one or more of the lenders under our existing credit arrangements fail to honor its contractual obligation to lend to us, (2) the amount that we are allowed to borrow under our existing credit facility is reduced as a result of lower oil and natural gas prices, declines in reserves, lending requirements or for other reasons or (3) our customers or working interest owners default on their obligations to us.
We continue to hold auction rate securities with a fair value of $45 million. We will attempt to sell these securities every 7-28 days until the auction succeeds, the issuer calls the securities or the securities mature. We currently do not believe that the decrease in the fair value of these investments is permanent or that the failure of the auction mechanism will have a material impact on our liquidity given the amount of our available borrowing capacity under our credit arrangements. Please see Note 13, "Fair Value Measurements" for more information regarding the auction rate securities.
Credit Arrangements. We have a revolving credit facility that matures in . . .
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