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| WPX > SEC Filings for WPX > Form 10-Q on 4-May-2012 | All Recent SEC Filings |
4-May-2012
Quarterly Report
General
The following discussion should be read in conjunction with the selected historical consolidated financial data and the consolidated financial statements and the related notes included in Part I, Item 1 in this Form 10-Q. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Form 10-Q, particularly in "Risk Factors" and "Forward-Looking Statements."
Overview
The following table presents our production volumes and financial highlights for
the three months ended March 31, 2012 and 2011:
Three months ended March 31,
2012 2011
Production Sales Data: (a)
Domestic natural gas (MMcf) 101,346 92,473
Domestic NGLs (MBbls) 2,746 2,425
Domestic oil (MBbls) 948 384
Domestic combined equivalent volumes
(MMcfe) (b) 123,511 109,331
Domestic per day combined equivalent volumes
(MMcfe/d) 1,357 1,215
Domestic combined equivalent volumes (MBoe) 20,585 18,222
International combined equivalent volumes
(MMcfe) (b)(c) 5,052 4,926
Financial Data (millions):
Total domestic revenues $ 879 $ 934
Total international revenues $ 31 $ 24
Consolidated operating income (loss) $ (49 ) $ 49
Consolidated capital expenditures $ 428 $ 319
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(a) Excludes production from our Arkoma Basin and Barnett Shale operations which are classified as discontinued operations and comprise approximately 5 percent of our total production.
(b) Oil and NGLs were converted to MMcfe using the ratio of one barrel of oil, condensate or NGL to six thousand cubic feet of natural gas.
(c) Includes approximately 69 percent of Apco's production (which corresponds to our ownership interest in Apco) and other minor directly held interests.
Our 2012 results continue to be impacted by natural gas prices that continue to decline relative to first-quarter 2011. Also, as a result of declines in forward natural gas prices during first quarter 2012, we recorded impairments of costs of acquired unproved reserves in the Powder River and Piceance Basins of approximately $37 million and $15 million, respectively. Partially offsetting the impact of these declining natural gas prices and impairments is the increased oil and natural gas liquids production. We expect to continue oil and natural gas production increases period-over-period throughout 2012.
As noted in our Form 10-K with regards to potential impairment of our producing assets, we estimated that approximately eight percent could be at risk for impairment if forward prices across all future periods declined by approximately 12 percent to 15 percent, on average, as compared to the forward prices at December 31, 2011. A substantial portion of the remaining carrying value of these other assets could be at risk for impairment if forward prices across all future periods decline by at least 24 percent, on average, as compared to the prices at December 31, 2011. Through March 31, 2012, forward natural gas prices have continued to decline from December 31,
2011 and averaged nine percent over all periods with a decline greater than 20 percent in 2012. While the prices have not declined to a level to trigger an impairment of our producing properties, we estimate that an additional five to six percent decline in the forward prices could result in impairment charges on approximately 12 percent of our producing assets. If forward prices were to decline an additional 18 percent on average across all periods, a substantial portion of the remaining carrying value of the remaining producing assets could be at risk for impairment.
Outlook
Although we are experiencing low natural gas prices, we believe we are well positioned to execute our business strategy of finding and developing reserves and producing natural gas, NGLs and oil at costs that will generate an attractive rate of return on our consolidated incremental development investments. Our focus for the remainder of 2012 is to continue to develop our natural gas portfolio to maintain current natural gas production levels, including the associated leasehold acreage, and grow our oil and natural gas liquids production. At current commodity pricing levels, we are focused on continuing to develop a more balanced reserve and production portfolio that will include a larger portion of oil and NGLs reserves than we have historically maintained. With lower natural gas prices, we will continue to maintain our focus on drilling strategically to manage leasehold expirations and maintain our liquidity. A continued decrease in forward natural gas prices could signal a need to reduce capital spending in 2012 to maintain the liquidity and balance sheet we believe necessary to run our business.
We believe that our portfolio of reserves provides us an opportunity to continue to grow in our areas where we have oil production (Williston Basin) and high concentrations of NGLs (Piceance Basin), which we believe will generate long-term sustainable value for shareholders. If gas prices were to increase, we believe we have the operational flexibility to respond by increasing our drilling in our natural gas areas. We expect 2012 capital expenditures to be approximately $1.2 billion.
We continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
• Continuing to invest in and grow our production and reserves;
• Retaining the flexibility to make adjustments to our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities;
• Continuing to diversify our commodity portfolio through the development of our Bakken Shale oil play position and liquids-rich basins (primarily Piceance Basin) with high concentrations of NGLs; and
• Continuing to maintain an active economic hedging program around our commodity price risks.
Potential risks or obstacles that could impact the execution of our plan include:
• Lower than anticipated energy commodity prices;
• Lower than expected levels of cash flow from operations;
• Unavailability of capital;
• Higher capital costs of developing unconventional shale properties;
• Counterparty credit and performance risk;
• Decreased drilling success;
• General economic, financial markets or industry downturn;
• Changes in the political and regulatory environments; and
• Increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation.
We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.
Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we began entering into commodity derivative contracts that continue to serve as economic hedges but are not designated as hedges for accounting purposes as we have elected not to utilize hedge accounting on new derivatives instruments. Changes in the fair value of non-hedge derivative instruments, hereafter referred to as economic hedges, are recognized as gains or losses in the earnings of the periods in which they occur, accordingly we believe this will result in future earnings that are more volatile. Hedged derivatives recorded at March 31, 2012 that are included in accumulated other comprehensive income have been and will continue to be transferred to earnings during the same periods in which the forecasted hedged transactions are recognized.
Commodity Price Risk Management
To manage the commodity price risk and volatility of owning producing gas and
oil properties, we enter into derivative contracts for a portion of our future
production. For the remainder of 2012 we have the following contracts as of
March 31, 2012 for our daily domestic production, shown at weighted average
volumes and basin-level weighted average prices:
Apr - Dec 2012 Natural Gas
Volume Weighted Average
(BBtu/d) Price ($/MMBtu)
Location swaps-Rockies 135 $4.76
Location swaps-San Juan 110 $4.94
Location swaps-Mid-Continent 88 $4.76
Location swaps-Southern California 33 $5.14
Location swaps-Northeast 143 $5.54
Apr - Dec 2012 Crude Oil
Weighted Average
Price ($/Bbl)
Volume Floor-Ceiling
(Bbls/d) for Collars
WTI crude oil fixed-price 7,887 $97.99
WTI crude oil costless collar 2,000 $85.00 - $106.30
WTI crude oil swaption 778 $108.00
Apr - Dec 2012 Natural Gas Liquids
Volume Weighted Average
(Bbls/d) Price ($/Bbl)
Natural Gas Liquid Swaps 4,000 $50.74
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Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We also hold a long-term obligation to deliver on a firm basis 200,000 MMbtu/d of natural gas at monthly index pricing to a buyer at the White River Hub (Greasewood-Meeker, CO), which is a major market hub exiting the Piceance Basin. Our interests in the Piceance Basin hold sufficient reserves to meet this obligation, which expires in 2014.
Results of Operations
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.
Domestic includes natural gas, natural gas liquids and oil development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico, North Dakota and Wyoming), and Appalachian regions of the United States. Our development and production techniques specialize in production from tight-sands and shale formations as well as coal bed methane reserves in the Piceance, San Juan, Powder River, Green River, Williston and Appalachian Basins. Associated with our commodity production are sales and marketing activities that include the management of various commodity contracts such as transportation, storage, and related hedges coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco, an oil and gas exploration and production company with concessions primarily in Argentina.
Three Month-Over-Three Month Results of Operations
Revenue Analysis
Percentage
Three months ended March 31, Increase
2012 2011 $ Change (Decrease)
(Millions)
Domestic revenues:
Natural gas sales $ 353 $ 404 $ (51 ) (13 )%
Natural gas liquid sales 92 84 8 10 %
Oil and condensate sales 80 34 46 135 %
Total product revenues 525 522 3 1 %
Gas management 337 408 (71 ) (17 )%
Mark to market gains and
losses and hedge
ineffectiveness 14 2 12 NM
Other 3 2 1 50 %
Total domestic revenues $ 879 $ 934 $ (55 ) (6 )%
Total international
revenues $ 31 $ 24 $ 7 29 %
Total revenues $ 910 $ 958 $ (48 ) (5 )%
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Domestic Revenues
Significant variances in comparative revenues reflect:
• $51 million decrease in natural gas sales reflects a per Mcf price (including the impact of hedges) of $3.48 for the three months ended March 31, 2012 compared to $4.37 for the three months ended March 31, 2011 on production sales volumes of 101,346 MMcf and 92,473 MMcf for the three months ended March 31, 2012 and 2011, respectively. Without hedges, our natural gas price per Mcf was $2.41 compared to $3.54 for the three months ended March 31, 2012 and 2011, respectively.
• $8 million increase in natural gas liquids sales reflects a per barrel price of $33.46 compared to $34.84 for the three months ended March 31, 2012 and 2011, respectively. Production sales volumes increased to 2,746 Mbbls from 2,425 Mbbls for the three months ended March 31, 2012 and 2011, respectively.
• $46 million increase in oil and condensate sales reflects a per barrel price of $84.54 (including the impact of hedges) compared to $87.13 on production sales volumes of 948 Mbbls and 384 Mbbls for the three months ended March 31, 2012 and 2011 respectively.
• A $12 million increase in mark-to-market gains and hedge ineffectiveness. Items in 2012 included $15 million of gains that were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett properties and $12 million of mark to market gains on natural gas and natural gas liquids derivatives, partially offset by $13 million of mark to market losses on crude oil derivatives due to the increase in oil prices.
International Revenues
International revenues increased primarily due to increased oil sales due to higher average oil sales prices for the three months ended March 31, 2012 compared to the same period in 2011.
Cost and operating expense and operating income (loss) analysis:
Percentage
Three months ended March 31, Increase
2012 2011 $ Change (Decrease)
(Millions)
Domestic costs and expenses:
Lease and facility operating $ 61 $ 58 $ 3 5 %
Gathering, processing and
transportation 135 112 23 21 %
Taxes other than income 25 27 (2 ) (7 )%
Gas management, including
charges for unutilized pipeline
capacity 355 417 (62 ) (15 )%
Exploration 14 11 3 27 %
Depreciation, depletion and
amortization 222 202 20 10 %
Impairment of costs of acquired
unproved reserves 52 - 52 NM
General and administrative 65 64 1 2 %
Other-net 5 - 5 NM
Total domestic costs and
expenses $ 934 $ 891 $ 43 5 %
International costs and
expenses:
Lease and facility operating $ 6 $ 5 $ 1 20 %
Taxes other than income 5 3 2 67 %
Exploration 5 1 4 NM
Depreciation, depletion and
amortization 6 5 1 20 %
General and administrative 3 3 - - %
Other-net - 1 (1 ) (100 )%
Total international costs and
expenses $ 25 $ 18 $ 7 39 %
Total costs and expenses $ 959 $ 909 $ 50 6 %
Domestic operating income
(loss) $ (55 ) $ 43 $ (98 ) NM
International operating income $ 6 $ 6 $ - - %
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Domestic Costs
Significant variances in comparative costs and expenses reflect:
• Lease and facility operating expense for the three months ended March 31, 2012 averaged $0.50 per Mcfe compared to $0.52 per Mcfe for the same period in 2011.
• $23 million increase in gathering, processing and transportation expenses primarily as a result of an increase in natural gas liquids volumes. This increase also includes a $9 million adjustment related to royalty calculations for prior periods. Our gathering, processing and transportation charges averaged $1.09 per Mcfe compared to an average of $1.02 per Mcfe for the three months ended March 31, 2012 and 2011, respectively.
• $62 million decrease in gas management expenses, primarily due to a 34 percent decrease in average prices on physical natural gas cost of sales partially offset by a 24 percent increase in natural gas sales volumes. Also included in gas management expenses are $11 million and $10 million for the three months ended March 31, 2012 and 2011, respectively, for unutilized pipeline capacity. Gas management expenses for the period ended March 31, 2012 also includes $11 million related to lower of cost or market charges to the carrying value of natural gas inventories in storage.
• $20 million higher depreciation, depletion and amortization expenses reflect higher production volumes. During the three months ended March 31, 2012 our depreciation, depletion and amortization averaged $1.80 per Mcfe compared to an average $1.84 per Mcfe for the same period in 2011.
• $52 million of property impairments of cost of acquired unproved reserves for the three months ended March 31, 2012, as previously discussed.
International costs
International costs increased primarily due to increased exploration expenses related to 3-D seismic acquisition costs.
Consolidated results below operating income (loss)
Percentage
Three months ended March 31, Increase
2012 2011 $ Change (Decrease)
(Millions)
Consolidated operating income
(loss) $ (49 ) $ 49 $ (98 ) NM
Interest expense (26 ) (49 ) 23 (47 )%
Interest capitalized 2 4 (2 ) (50 )%
Investment income and other 10 6 4 67 %
Income (loss) from continuing
operations before income taxes (63 ) 10 (73 ) NM
Provision (benefit) for income
taxes (25 ) 3 (28 ) NM
Income (loss) from continuing
operations (38 ) 7 (45 ) NM
Loss from discontinued
operations (2 ) (8 ) 6 75 %
Net loss (40 ) (1 ) (39 ) NM
Less: Net income attributable
to noncontrolling interests 3 2 1 50 %
Net loss attributable to WPX
Energy $ (43 ) $ (3 ) $ (40 ) NM
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NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
Interest expense in 2012 reflects interest accrued on our senior notes, issued in November 2011. Interest expense in 2011 reflects interest associated with our unsecured notes payable with Williams. These amounts were cancelled by Williams and contributed to capital on June 30, 2011.
Our investment income results primarily from equity earnings associated with our international and domestic equity investments.
Provision (benefit) for income taxes changed favorably due to the pre-tax loss in 2012 compared to the pre-tax income in 2011. See Note 7 for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Management's Discussion and Analysis of Financial Condition and Liquidity
Outlook
We expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures and tax and debt payments while maintaining a sufficient level of liquidity. We retained approximately $500 million of the net proceeds from the issuance of the Notes and have a $1.5 billion credit facility. These sources of liquidity along with our expected cash flows from operations should be sufficient to allow us to pursue our business strategy and goals for the remainder of 2012 and 2013.
If energy commodity prices for 2012 and 2013 continue to trend lower, as they have done during early 2012, we believe the effect on our cash flows from operations would be partially mitigated by our hedging program. In addition, we note the following assumptions for the remainder of 2012 and 2013:
• Our capital expenditures are estimated to be approximately $1.2 billion in 2012, and are generally considered to be largely discretionary; and
• Apco's liquidity requirements will continue to be provided from its cash flows from operations.
Potential risks associated with our planned levels of liquidity and the planned capital and investment
expenditures discussed above include:
• Sustained reductions in energy commodity prices from the range of current expectations;
• Lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices;
• Higher than expected collateral obligations that may be required, including those required under new commercial agreements;
• Significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold; and
• Reduced access to our credit facility.
Liquidity
We plan to conservatively manage our balance sheet. Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses throughout 2012. Our internal and external sources of consolidated liquidity include cash generated from operations, cash and cash equivalents on hand and our credit facility. Additional sources of liquidity, if needed and if available, include bank financings, proceeds from the issuance of long-term debt and equity securities and proceeds from asset sales. As of March 31, 2012 we have not accessed our credit facility.
Sources (Uses) of Cash
The following table and discussion summarize our sources (uses) of cash for the
three months ended March 31, 2012 and 2011.
Three months ended March 31,
2012 2011
(Millions)
Net cash provided (used) by:
Operating activities $ 252 $ 240
. . .
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