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| NFX > SEC Filings for NFX > Form 10-K on 26-Feb-2013 | All Recent SEC Filings |
26-Feb-2013
Annual Report
Overview
We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our principal domestic areas of operation include the Mid-Continent, the Rocky Mountains and onshore Gulf Coast. Internationally, we focus on offshore oil developments in Malaysia and China. In February 2013, we initiated a process to evaluate strategic alternatives with respect to our international businesses.
To maintain and grow our production and cash flows, we must continue to develop existing proved reserves and locate or acquire new oil and natural gas reserves to replace those reserves being produced. Our revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. Prices for oil, natural gas and NGLs fluctuate widely and affect:
• the amount of cash flows available for capital expenditures;
• our ability to borrow and raise additional capital; and
• the quantity of oil, natural gas and NGLs that we can economically produce.
We prepare our financial statements in conformity with generally accepted accounting principles, which require 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 natural gas reserves. In addition, we use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits and other internal costs directly attributable to these assets, are capitalized. The net capitalized costs for our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves. If these costs exceed the limit, we are required to charge the excess to earnings, also referred to as a "ceiling test writedown." As of December 31, 2012, the unamortized net capitalized costs of our domestic oil and gas properties exceeded the ceiling amount by approximately $1.5 billion ($948 million, after-tax). The risk of incurring a ceiling test writedown increases when commodity prices are low for a sustained period of time. If there are further declines in SEC pricing, we may be required to record a ceiling test writedown in future periods.
Results of Operations
Revenues. Our revenues are primarily derived from the sale of oil, natural gas and NGLs and do not include the effects of the settlements of our derivative positions. Please see Note 4, "Derivative Financial Instruments," to our consolidated financial statements in Item 8 of 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, substantially all of the crude oil from our offshore operations in Malaysia and China is produced into FPSOs or onshore storage terminals, 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.
During the year ended December 31, 2012, our revenues were up $96 million, or 4%, over 2011 and reflect our continued focus on increasing our liquids production and allowing our natural gas production to decline. Oil production was up 24% in 2012, and when combined with slightly higher prices, added an additional $431 million compared to 2011. Substantially offsetting the uplift in revenues from oil were lower gas prices and volumes that resulted in $326 million less gas revenues in 2012 compared to 2011. Increased NGL production of 30% was more than offset by a 30% decline in NGL prices during the year. Revenues of $2.5 billion for 2011
2012 2011 2010
Production:(1)(2)
Domestic:
Crude oil and condensate (MBbls) 11,988 10,939 8,498
Natural gas (Bcf) 143.5 175.1 186.9
NGLs (MBbls) 2,608 2,004 1,518
Total (Bcfe) 231.1 252.7 247.0
International:
Crude oil and condensate (MBbls) 9,914 6,715 6,057
Natural gas (Bcf) 1.2 0.1 -
Total (Bcfe) 60.7 40.4 36.3
Total:
Crude oil and condensate (MBbls) 21,902 17,654 14,555
Natural gas (Bcf) 144.7 175.2 186.9
NGLs (MBbls) 2,608 2,004 1,518
Total (Bcfe) 291.8 293.1 283.3
Average Realized Prices:(2)(3)
Domestic:
Crude oil and condensate (per Bbl) $ 83.99 $ 85.68 $ 69.03
Natural gas (per Mcf) 2.64 4.05 4.09
NGLs (per Bbl) 31.26 44.42 44.74
Natural gas equivalent (per Mcfe) 6.35 6.89 5.78
International:
Crude oil and condensate (per Bbl) $ 109.67 $ 108.51 $ 75.27
Natural gas (per Mcf) 3.89 3.95 -
Natural gas equivalent (per Mcfe) 18.01 18.06 12.54
Total:
Crude oil and condensate (per Bbl) $ 95.62 $ 94.36 $ 71.62
Natural gas (per Mcf) 2.65 4.05 4.09
NGLs (per Bbl) 31.26 44.42 44.74
Natural gas equivalent (per Mcfe) 8.77 8.43 6.65
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(1) Represents volumes lifted and sold regardless of when produced. Excludes natural gas produced and consumed in operations of 7.8 Bcfe in 2012, 6.8 Bcfe in 2011 and 5.3 Bcfe in 2010.
(2) Historically, we reported natural gas liquid (NGL) volumes combined with oil and condensate production. Effective in our Form 10-K for the period ended December 31, 2012, we began reporting NGL production separately from crude oil and condensate production. As such, all production volumes and average realized prices for periods prior to 2012 have been reclassified for comparability between periods.
(3) Had we included the effects of hedging contracts not designated for hedge accounting, the average realized price for total natural gas would have been $3.57, $5.43 and $5.62 per Mcf for the years ended December 31, 2012, 2011 and 2010, respectively; and the average crude oil realized price would have been $95.68, $91.70 and $81.32 per Bbl for 2012, 2011 and 2010, respectively. We did not have any hedging contracts associated with NGL production in 2012, 2011 or 2010.
Domestic Production. Our 2012 domestic oil, natural gas and NGL production, stated on a natural gas equivalent basis, decreased 9% compared to 2011 production. The decrease relates primarily to the sale of assets in the Gulf of Mexico and natural declines in our natural gas assets due to lack of investment as our investments have been focused on oil and liquids projects. Our domestic oil and liquids production increased approximately 13% in 2012 when compared to the prior year.
International Production. Our 2012 international oil production increased by 48% over 2011 levels primarily due to an increase of 53% in Malaysia production resulting from continued successful drilling on our East Belamut field, as well as full-year production on our East Piatu and Puteri fields, brought online during the fourth quarter of 2011. Our 2011 international oil production increased over 2010 levels primarily due to an increase in production of 13% in Malaysia as a result of new field developments from our East Piatu and East Belamut fields and the timing of liftings.
Operating Expenses.
Year ended December 31, 2012 compared to December 31, 2011
The following table compares information about our operating expenses between
the following periods:
Unit-of-Production Total Amount
Year Ended Percentage Year Ended Percentage
December 31, Increase December 31, Increase
2012 2011 (Decrease) 2012 2011 (Decrease)
(Per Mcfe) (In millions)
Domestic:
Lease operating $ 1.76 $ 1.42 24 % $ 406 $ 358 13 %
Production and other
taxes 0.29 0.27 7 % 67 68 (2 )%
Depreciation, depletion
and amortization 2.96 2.46 20 % 683 621 10 %
General and
administrative 0.91 0.71 28 % 211 180 17 %
Ceiling test impairment 6.44 - n/a 1,488 - n/a
Other 0.06 - n/a 15 - n/a
Total operating expenses 12.42 4.85 156 % 2,870 1,227 134 %
International:
Lease operating $ 1.79 $ 2.36 (24 )% $ 108 $ 95 14 %
Production and other
taxes 4.57 6.49 (30 )% 277 262 6 %
Depreciation, depletion
and amortization 4.48 3.60 24 % 272 146 87 %
General and
administrative 0.12 0.13 (8 )% 7 5 30 %
Total operating expenses 10.95 12.58 (13 )% 664 508 31 %
Total:
Lease operating $ 1.76 $ 1.55 14 % $ 514 $ 453 13 %
Production and other
taxes 1.18 1.13 4 % 344 330 4 %
Depreciation, depletion
and amortization 3.27 2.62 25 % 955 767 25 %
General and
administrative 0.75 0.63 19 % 218 185 18 %
Ceiling test impairment 5.10 - n/a 1,488 - n/a
Other 0.05 - n/a 15 - n/a
Total operating expenses 12.11 5.92 105 % 3,534 1,735 104 %
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Domestic Operations. Excluding the ceiling test writedown, the increase in our depletion rate due to price related downward reserve revisions and the impact of selling our offshore Gulf of Mexico assets, our operating expenses increased 21%. The components of the significant period-to-period change are as follows:
• Lease operating expenses (LOE) include normally recurring expenses to operate and produce our oil and gas wells, non-recurring well workover and repair-related expenses and the costs to transport our production to
• increased workover activity was the primary factor resulting in a $14 million increase in non-recurring LOE in our Rocky Mountain region;
• restimulation of several wells in our effort to improve performance was the leading driver of the $13 million non-recurring LOE increase in our Mid-Continent region;
• repairs to plugged flow lines in our deepwater Gulf of Mexico operations, which were subsequently sold in the fourth quarter of 2012, was the primary driver of an additional increase of $12 million in non-recurring LOE; and
Transportation costs related to firm transportation agreements in our Mid-Continent region accounted for $0.08 per Mcfe of the increase.
• Our average depreciation, depletion and amortization (DD&A) rate increased $0.50 per Mcfe during 2012 and reflects our continued focus on oil and liquids rich gas developments that are more capital intensive on a per Mcfe basis as compared to natural gas developments. While our average DD&A rate in 2011 was $2.46, our rate for the fourth quarter of 2011 was $2.58. During 2012, this rate increased as the additional cost of each Mcfe added was higher. In addition, the full year average rate was negatively impacted by downward reserve revisions (primarily due to natural gas price declines) combined with the net impact of selling our remaining Gulf of Mexico assets. Without these items, our average DD&A rate for the year ended December 31, 2012 would have been $2.89.
• General and administrative (G&A) expense per Mcfe increased during 2012 primarily due to employee-related expenses associated with our domestic work force combined with lower domestic production. During 2012, we capitalized $95 million ($0.41 per Mcfe) of direct internal costs as compared to $83 million ($0.33 per Mcfe) during 2011.
• In the fourth quarter of 2012 we recorded a ceiling test writedown of $1.5 billion ($6.44 per Mcfe) due to a net decrease in the discounted value of our proved reserves. The primary reason for the change in value was negative price-related reserve revisions as a result of a 33% decrease in the natural gas SEC pricing.
• Other expenses of $15 million ($0.06 per Mcfe) include a writedown of $8 million of subsea wellhead inventory that was not included in the sale of our Gulf of Mexico assets and contract termination costs of $6 million in consideration of other services.
International Operations. Our international operating expenses for 2012, stated on a Mcfe basis, decreased 13% over 2011. The components of the period-to-period change are as follows:
• LOE per Mcfe decreased by 24% ($0.57 per Mcfe) primarily due to lower non-recurring workover activity during 2012. Recurring LOE was essentially flat on a per unit basis with a decrease of $0.02 per Mcfe, or 1%.
• Production and other taxes per Mcfe decreased by 30% due to an overall change in the mix of production that was lifted and sold from the various PSCs in Malaysia including the fields brought online during the fourth quarter of 2011. The production tax rates per barrel of oil lifted and sold from these newer developments are lower, per the terms of our PSCs, while we recover our costs associated with these developments.
• Total DD&A expense increased 87% in 2012 compared to 2011 due to a combination of an increase in the average DD&A rate and a 50% increase in production during 2012. Our average annual DD&A rate per Mcfe increased 24% when compared to the average annual 2011 rate. The average annual 2012 rate
Year ended December 31, 2011 compared to December 31, 2010
The following table presents information comparing our operating expenses for the following periods:
Unit-of-Production Total Amount
Year Ended Percentage Year Ended Percentage
December 31, Increase December 31, Increase
2011 2010 (Decrease) 2011 2010 (Decrease)
(Per Mcfe) (In millions)
Domestic:
Lease operating $ 1.42 $ 1.07 33 % $ 358 $ 264 35 %
Production and other taxes 0.27 0.18 50 % 68 44 54 %
Depreciation, depletion
and amortization 2.46 2.08 18 % 621 515 21 %
General and administrative 0.71 0.61 16 % 180 150 20 %
Other - 0.03 (100 )% - 7 (100 )%
Total operating expenses 4.85 3.97 22 % 1,227 980 25 %
International:
Lease operating $ 2.36 $ 1.72 37 % $ 95 $ 62 52 %
Production and other taxes 6.49 2.25 188 % 262 82 220 %
Depreciation, depletion
and amortization 3.60 3.56 1 % 146 129 12 %
General and administrative 0.13 0.17 (24 )% 5 6 (11 )%
Total operating expenses 12.58 7.70 63 % 508 279 82 %
Total:
Lease operating $ 1.55 $ 1.15 35 % $ 453 $ 326 39 %
Production and other taxes 1.13 0.44 157 % 330 126 162 %
Depreciation, depletion
and amortization 2.62 2.27 15 % 767 644 19 %
General and administrative 0.63 0.55 15 % 185 156 19 %
Other - 0.03 (100 )% - 7 (100 )%
Total operating expenses 5.92 4.44 33 % 1,735 1,259 38 %
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Domestic Operations. Our domestic operating expenses for 2011, stated on a Mcfe basis, increased 22% over those for 2010. The components of the significant period-to-period change are as follows:
• The increase in domestic LOE per Mcfe resulted from a 50% ($0.26 per Mcfe) increase in the normally recurring portion of our LOE. Recurring LOE in our Rocky Mountains region accounted for approximately 60% of the increase due to increased water handling and overall operating and service-related costs in the basins in which we operate. In addition, LOE increased ($0.08 per Mcfe) due to increased transportation costs resulting from the commencement of firm transportation contracts in our Mid-Continent region throughout 2010.
• Production and other taxes per Mcfe increased due to a 21% increase in realized oil prices in 2011, coupled with a 4% increase in oil and natural gas production subject to production taxes.
• Since late 2009, the shift of our capital investments toward the oil plays in our portfolio has resulted in an increase in our DD&A rate. The increase in total DD&A expense is related to the increase in the DD&A rate, coupled with a slight increase in our production volumes during 2011 compared to 2010.
• During the fourth quarter of 2010, we recorded an impairment of $7 million ($0.03 per Mcfe) related to certain claims related to the bankruptcy proceedings associated with TXCO Resources Inc.
International Operations. Our international operating expenses for 2011, stated on a Mcfe basis, increased 63% over 2010. The components of the period-to-period change are as follows:
• LOE per Mcfe increased due to non-recurring pipeline and facilities repair in Malaysia, fixed production costs associated with certain of our PSCs in Malaysia and increased overall operating service costs from the various PSCs during 2011 compared to 2010.
• Production and other taxes per Mcfe increased due to an increase, per the terms of the PSCs, in the tax rate per barrel of oil lifted and sold as a result of the 44% increase in realized oil prices in 2011.
• Total DD&A expense increased due to an 11% increase in volumes during 2011 compared to 2010 combined with an increase in our ratio of costs subject to depletion over proved reserves in the fourth quarter 2011 related to our new offshore Malaysian developments.
Interest Expense. The following table presents information about interest expense for each of the years in the three-year period ended December 31:
2012 2011 2010
(In millions)
Gross interest expense:
Credit arrangements $ 9 $ 11 $ 3
Senior notes 73 11 2
Senior subordinated notes 122 152 149
Other 1 1 2
Total gross interest expense 205 175 156
Capitalized interest (68 ) (82 ) (58 )
Net interest expense $ 137 $ 93 $ 98
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The increase in gross interest expense in 2012 as compared to 2011 primarily resulted from the September 2011 issuance of $750 million aggregate principal amount of 5 3/4% Senior Notes due 2022, as well as the June 2012 issuance of $1 billion aggregate principal amount of 5 5/8% Senior Notes due 2024, partially offset by the redemption in April 2012 of our $325 million 6 5/8% Senior Subordinated Notes due 2014 and in July 2012 of our $550 million 6 5/8% Senior Subordinated Notes due 2016. The increase in gross interest expense in 2011 as compared to 2010 resulted from increased borrowings under our credit arrangements and the September 2011 issuance of $750 million aggregate principal amount of 5 3/4% Senior Notes due 2022. See Note 8, "Debt," to our consolidated financial statements in Item 8 of this report.
Interest expense associated with oil and gas properties excluded from amortization is capitalized into oil and gas properties. Capitalized interest decreased in 2012 as compared to 2011, due to a reduction in our average balance of oil and gas properties excluded from amortization. As a result of the October 2012 sale of our Gulf of Mexico assets, unproved oil and gas properties that had been previously excluded from amortization were removed from such classification. Capitalized interest increased in 2011 as compared to 2010 due to an increase in the average balance of oil and gas properties excluded from amortization, primarily resulting from the acquisition of assets in the Uinta Basin of Utah.
Taxes. The effective tax rates for the years ended December 31, 2012, 2011 and 2010 were (20%), 36% and 37%, respectively. 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. Our effective tax rate generally approximates 37%. Our effective tax rate for 2012 was affected by our decision to repatriate international earnings, use foreign tax credits (FTCs), a valuation allowance for FTCs and the recording of a valuation allowance related to our deferred tax asset in Malaysia. Please see the discussion and tables in Note 9, "Income Taxes," to our consolidated financial statements in Item 8 of this report, which are incorporated herein by reference.
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; operating expenses; and capital costs.
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