Exhibit 99.1
DATE: Feb. 23, 2012
MEDIA CONTACT: Kelly Swan (918) 573-4944 | INVESTOR CONTACT: David Sullivan (918) 573-9360 |
WPX Energy Announces 2011 Results
TULSA, Okla. – WPX Energy (NYSE:WPX) today announced its unaudited financial and operating results for the fourth quarter and the year-ended Dec. 31, 2011. Highlights for the year include:
| • | Revenue from domestic oil and NGL sales rose 87% |
| • | Oil production up 65%; NGL production up 25%; Gas production up 5% |
| • | Bakken Shale oil production more than tripled from 1Q to 4Q |
| • | Proved reserves increased 9% to a company record of nearly 5.3 Tcfe |
| • | Domestic production replaced at a rate of 188% |
| • | Proved, probable and possible (3P) reserves increased 7% to 18.5 Tcfe |
2011 FINANCIAL RESULTS
WPX results for the year-ended Dec. 31, 2011, were impacted by non-cash impairment charges during the fourth quarter primarily due to a decline in forward natural gas prices.
Including these non-cash charges, WPX reported an unaudited net loss attributable to WPX Energy of $302 million in 2011, or a loss of $1.53 per share on a diluted basis. This compares with a net loss of $1,291 million, or a loss of $6.55 per share, on a diluted basis for 2010.
WPX’s adjusted EBITDAX was $1,330 million in 2011 – essentially equal to 2010. Adjusted EBITDAX is a non-GAAP measure. It is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of adjusted EBITDAX to net income (loss) is included in this announcement, as well as a definition.
The 2011 pre-tax, non-cash charges of approximately $547 million related to certain proved and unproved natural gas properties, primarily in the Powder River Basin and Barnett Shale.
WPX also reported $61 million in non-cash charges for dry-hole and leasehold write offs during third-quarter 2011 associated with an unsuccessful exploratory well in Columbia County, Pa., and associated acreage.
Results in 2010 were impacted by non-cash impairment charges of approximately $1 billion to goodwill and $678 million related to certain proved and unproved natural gas properties, primarily in the Barnett Shale.
For the fourth quarter of 2011, WPX reported an unaudited net loss of $338 million, or a loss of $1.72 per share on a diluted basis, compared with net income $12 million, or $0.06 per share on a diluted basis, for the fourth quarter of 2010.
MANAGEMENT PERSPECTIVE
“Our oil and NGL production and revenues reached an all-time high, reflecting our emphasis on the development of our assets in the Bakken Shale and the liquids-rich Piceance Basin,” CEO Ralph Hill said.
“And as we’ve announced, we’re decreasing our natural gas drilling in this commodity environment in favor of pursuing opportunities to grow our oil and NGL production even more.
“Currently, our Bakken Shale development has the highest incremental returns of any of our drilling programs.
“Overall, our operations, balance sheet, cash, liquidity and cash flow place us in a position of strength for 2012,” Hill added.
PRODUCTION
The company’s overall domestic and international production climbed nearly 10 percent in 2011 to an average of 1,399 MMcfe/d, excluding production attributable to discontinued operations in the Arkoma Basin.
The production increase was led by advances in oil and NGL production, which jumped 65 percent and 25 percent respectively in 2011.
Oil production in the company’s highest rate-of-return basin – the Bakken Shale – increased to approximately 6,400 barrels per day in the fourth quarter, which is more than triple first-quarter 2011 production of approximately 1,700 barrels per day. As of mid-February 2012, WPX’s oil production from the Bakken increased to 7,600 barrels per day.
NGL production in the liquids-rich Piceance Basin saw a notable increase as well, up 24 percent overall for the full year. In 2011, NGL production averaged 27.1 Mbbl/d, compared with 21.9 Mbbl/d in 2010.
Natural gas production in the Marcellus Shale rose significantly in late 2011 following the delayed startup of a third-party gathering system. Production in fourth-quarter 2011 rose to 27 MMcf/d, up 238 percent vs. 8 MMcf/d in the same period in 2010. As of mid-February 2012, Marcellus production increased to 59 MMcf/d.
Overall, total natural gas production increased 5 percent in 2011, from an average of 1,096 MMcf/d in 2010 to 1,153 MMcf/d in 2011.
The domestic net realized averaged price for natural gas in 2011 was $4.30 per Mcf vs. $4.57 in 2010. The domestic net realized averaged price for NGL in 2011 was $40.17 per barrel vs. $35.02 in 2010. The net realized averaged price for domestic oil in 2011 was $85.38 per barrel vs. $66.32 in 2010. All amounts are inclusive of hedges.
| Full Year | 4Q | |||||||||||||||||||||||
| Average Daily Production | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Natural gas (MMcf/d) | ||||||||||||||||||||||||
Piceance Basin | 679 | 631 | 8 | % | 686 | 682 | 1 | % | ||||||||||||||||
Marcellus Shale | 15 | 5 | 200 | % | 27 | 8 | 238 | % | ||||||||||||||||
Powder River Basin | 227 | 230 | -1 | % | 229 | 214 | 7 | % | ||||||||||||||||
San Juan Basin | 135 | 141 | -4 | % | 119 | 137 | -13 | % | ||||||||||||||||
Other | 97 | 89 | 9 | % | 102 | 96 | 6 | % | ||||||||||||||||
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Subtotal (MMcf/d) | 1,153 | 1,096 | 5 | % | 1,163 | 1,137 | 2 | % | ||||||||||||||||
NGLs (Mbbl/d) | ||||||||||||||||||||||||
Piceance | 27.1 | 21.9 | 24 | % | 27.1 | 24.2 | 12 | % | ||||||||||||||||
Other | 1.0 | 0.6 | 67 | % | 0.9 | 0.6 | 50 | % | ||||||||||||||||
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Subtotal (Mbbl/d) | 28.1 | 22.5 | 25 | % | 28.0 | 24.8 | 13 | % | ||||||||||||||||
Oil (Mbbl/d) | ||||||||||||||||||||||||
Bakken Shale | 4.8 | 0.1 | NM | 6.4 | 0.2 | NM | ||||||||||||||||||
Piceance | 2.3 | 2.1 | 10 | % | 2.2 | 2.4 | -8 | % | ||||||||||||||||
International | 5.6 | 5.4 | 4 | % | 5.9 | 5.6 | 5 | % | ||||||||||||||||
Other | 0.2 | 0.2 | 0 | % | 0.3 | 0.3 | 0 | % | ||||||||||||||||
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Subtotal (Mbbl/d) | 12.9 | 7.8 | 65 | % | 14.8 | 8.5 | 74 | % | ||||||||||||||||
Total Production (MMcfe/d) | 1,399 | 1,277 | 10 | % | 1,420 | 1,337 | 6 | % | ||||||||||||||||
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| NM | = a calculation that is not meaningful due to a percentage change in the thousands. |
WPX has previously announced that it expects to grow its overall production by 4 percent in 2012 on an Mcf equivalent basis, driven by capital investments in oil and NGL production. Natural gas production is expected to remain flat in 2012.
EXPENSES
On a per-unit basis, WPX’s domestic lease operating expense (LOE) decreased 8 percent in 2011 to $0.55 per Mcfe vs. $0.60 per Mcfe in 2010. Actual charges were $268 million in 2011 vs. $267 million in 2010.
In 2011, WPX negotiated new fee-based contracts for liquids processing in the Piceance Basin. While these contributed to domestic gathering, processing and transportation charges of $1.02 per Mcfe in 2011 vs. $0.73 per Mcfe in 2010, they allow WPX to retain the vast majority of its NGL production in this basin.
Revenues associated with the new fee-based contracts more than offset the increase in fees. Actual charges for the domestic gathering, processing and transportation charges were $499 million in 2011 vs. $326 million in 2010.
Taxes other than income for domestic operations were $0.24 per Mcfe in 2011 and 2010. Actual charges were $119 million in 2011 vs. $109 million in 2010. The slight increase is primarily associated with greater oil and NGL volumes.
Domestic general and administrative expenses (G&A) totaled $0.56 per Mcfe in 2011 vs. $0.55 per Mcfe in 2010 due in part to the formation of two new asset teams who manage and operate WPX’s developments in the Bakken and Marcellus shales. Actual charges were $273 million in 2011 vs. $244 million in 2010.
Domestic depreciation, depletion and amortization expenses (DD&A) were $1.89 per Mcfe in 2011 vs. $1.92 per Mcfe in 2010. Actual charges were $927 million in 2011 vs. $858 million in 2010.
WPX Energy
Consolidated Statement of Operations
(Unaudited)
| Twelve months ending | Fourth Quarter ending | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (Dollars in millions) | (Dollars in millions) | |||||||||||||||
Total revenues | 3,988 | 4,034 | 992 | 960 | ||||||||||||
Total costs before goodwill impairment and impairment of producing properties and costs of acquired unproved reserves | 3,776 | 3,690 | 933 | 896 | ||||||||||||
Impairments of goodwill, producing properties and costs of acquired unproved reserves | 547 | 1,681 | 547 | — | ||||||||||||
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Operating income (loss) | (335 | ) | (1,337 | ) | (488 | ) | 64 | |||||||||
Interest expense | (117 | ) | (124 | ) | (20 | ) | (36 | ) | ||||||||
Interest capitalized | 9 | 16 | 1 | 4 | ||||||||||||
Investment income and other | 26 | 21 | 7 | 6 | ||||||||||||
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Income (loss) from continuing operations before income taxes | (417 | ) | (1,424 | ) | (500 | ) | 38 | |||||||||
Provision (benefit) for income taxes | (145 | ) | (149 | ) | (174 | ) | 18 | |||||||||
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Income (loss) from continuing operations | (272 | ) | (1,275 | ) | (326 | ) | 20 | |||||||||
Loss from discontinued operations | (20 | ) | (8 | ) | (9 | ) | (6 | ) | ||||||||
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Net income (loss) | (292 | ) | (1,283 | ) | (335 | ) | 14 | |||||||||
Less: Net income attributable to noncontrolling interrests | 10 | 8 | 3 | 2 | ||||||||||||
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Net income (loss) attributable to WPX Energy | (302 | ) | (1,291 | ) | (338 | ) | 12 | |||||||||
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Amounts attributable to WPX Energy, Inc.: | ||||||||||||||||
Income (loss) from continuing operations | (282 | ) | (1,283 | ) | (329 | ) | 18 | |||||||||
Loss from discontinued operations | (20 | ) | (8 | ) | (9 | ) | (6 | ) | ||||||||
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Net income (loss) | (302 | ) | (1,291 | ) | (338 | ) | 12 | |||||||||
Basic and diluted earnings (loss) per common share | ||||||||||||||||
Income (loss) from continuing operations | (1.43 | ) | (6.51 | ) | (1.67 | ) | 0.09 | |||||||||
Loss from discontinued operations | (0.10 | ) | (0.04 | ) | (0.05 | ) | (0.03 | ) | ||||||||
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Net income (loss) | (1.53 | ) | (6.55 | ) | (1.72 | ) | 0.06 | |||||||||
Weighted-average shares (millions) | 197.1 | 197.1 | 197.1 | 197.1 | ||||||||||||
ADJUSTED EBITDAX
EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion and amortization and exploration expenses. Adjusted EBITDAX includes adjustments for impairments and discontinued operations.
WPX had adjusted EBITDAX of $1,330 million for the year-ended Dec. 31, 2011 – essentially equal to adjusted EBITDAX in 2010.
For the quarter ended Dec. 31, 2011, WPX had adjusted EBITDAX of $340 million, up 5.5 percent from $322 million of adjusted EBITDAX for the fourth quarter of 2010.
| Year End | Fourth Quarter | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| EBITDAX (non-GAAP) | millions | millions | millions | millions | ||||||||||||
Net income (loss) | ($ | 292 | ) | ($ | 1,283 | ) | ($ | 335 | ) | $ | 14 | |||||
Interest expense | $ | 117 | $ | 124 | $ | 20 | $ | 36 | ||||||||
Provision (benefit) for income taxes | ($ | 145 | ) | ($ | 149 | ) | ($ | 174 | ) | $ | 18 | |||||
Depreciation, depletion and amortization | $ | 949 | $ | 875 | $ | 246 | $ | 220 | ||||||||
Exploration expenses | $ | 134 | $ | 73 | $ | 27 | $ | 28 | ||||||||
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EBITDAX | $ | 763 | ($ | 360 | ) | ($ | 216 | ) | $ | 316 | ||||||
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Impairments | $ | 547 | $ | 1,681 | $ | 547 | $ | 0 | ||||||||
Loss from discontinued operations | $ | 20 | 8 | $ | 9 | $ | 6 | |||||||||
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Adjusted EBITDAX | $ | 1,330 | $ | 1,329 | $ | 340 | $ | 322 | ||||||||
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WPX is forecasting full-year EBITDAX of approximately $1.2 billion for 2012. This assumes the impact of the company’s existing hedges, a $3 NYMEX natural gas price and a $99 per barrel oil price.
A $0.10 change in the price of natural gas equates to an estimated $20 million impact to EBITDAX. A $1 change in the price of oil equates to an estimated $5 million impact to EBITDAX, inclusive of the related impact to NGL.
CASH AND LIQUIDITY
In connection with the separation from Williams, WPX entered into a $1.5 billion revolving credit agreement that became effective in November. The facility remains undrawn.
In November, WPX also issued $1.5 billion of senior notes consisting of $1.1 billion at 6.0 percent due 2022 and $400 million at 5.25 percent due 2017. Approximately $981 million of these proceeds were distributed to Williams.
At Dec. 31, 2011, WPX had approximately $526 million in cash and cash equivalents – including $38 million for international operations – resulting in total liquidity of approximately $2 billion.
2011 DEVELOPMENT ACTIVITIES
In 2011, WPX participated in 1,241 gross (694 net) wells in the United States, of which only two were nonproductive. The number of gross wells refers to the number of wells completed during 2011.
Last year, WPX invested $1.461 billion in drilling and development, excluding costs for facilities construction. Approximately 84 percent of this capital was deployed in the Bakken Shale, Piceance Basin and Marcellus Shale.
WPX’s 2011 domestic drilling, finding and development cost for adding proved reserves was $1.57 per Mcfe, compared with $1.95 a year ago.
Highlights for each of the company’s areas are provided below. All volumes are reported on a net basis.
| • | In the Bakken Shale, WPX grew its rig count from three to five in 2011; had an average of 5.2 Mboe/d of production; and completed 25 gross (20 net) wells. |
| • | In the Piceance Basin, WPX deployed 11 drilling rigs for the majority of 2011, including nine in the Piceance Valley and two in the Piceance Highlands. The company’s assets in the basin produced an average of 679 MMcf/d of gas production, along with an average of 29.4 Mbbl/d of NGL and oil. WPX participated in the completion of 385 gross (361 net) wells in the Piceance Basin |
| • | In the Marcellus Shale, WPX deployed four rigs for the majority of 2011 and had an average of 15 MMcf/d of production. Production levels and the number of completions were hampered for much of 2011 awaiting the completion of a third-party gathering system. In the fourth quarter, production increased to 27 MMcf/d following the startup of that pipeline. WPX completed 38 gross (19 net) Marcellus Shale wells in 2011. At year-end, another 27 wells were awaiting completion. |
| • | In the Powder River Basin, WPX had an average of 227 MMcf/d of production and participated in the completion of 524 gross (226 net) wells. Approximately 400 of these wells were drilled in prior years and completed the dewatering process in 2011. |
| • | In the San Juan Basin, WPX deployed two rigs for the majority of 2011 and had an average of 136 MMcfe/d of production. WPX completed 56 gross (33 net) San Juan wells. |
| • | In WPX’s other areas, the company deployed one rig and had an average of 134 MMcfe/d of production from continuing operations. WPX’s other properties consist of the company’s holdings in the Barnett Shale, Green River Basin and its international interests. Arkoma production is excluded because the properties are classified as discontinued operations. |
RESERVES
As of Dec. 31, 2011, WPX’s total proved reserves increased to a company high of nearly 5.3 trillion cubic feet equivalent – up approximately 9 percent vs. 2010.
Approximately 77 percent of WPX’s 2011 total proved reserves are natural gas and 23 percent natural gas liquids (NGL) and crude oil. At year-end 2010, natural gas accounted for 83 percent of the company’s reserves using an industry standard ratio of 6-to-1 to convert oil and NGL to natural gas equivalent.
Today, WPX also is reporting that its total proved, probable, and possible (3P) reserves increased 7 percent to approximately 18.5 Tcfe. The 3P figure consists of approximately 5.3 Bcfe in proved reserves, 7.7 Bcfe in probable reserves and 5.5 Bcfe in possible reserves.
3P Detail | Net Oil, MMBbl | Net NGL, MMBbl | Net Gas, Bcf | Net Reserves, Bcfe | ||||||||||||
Proved Reserves | 63.3 | 135.3 | 4,073 | 5,265 | ||||||||||||
Probable Reserves | 74.3 | 195.1 | 6,130 | 7,746 | ||||||||||||
Possible Reserves | 85.4 | 176.0 | 3,904 | 5,472 | ||||||||||||
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Total 3P Reserves | 223.0 | 506.4 | 14,107 | 18,483 | ||||||||||||
At year-end 2010, WPX had 3P reserves of approximately 17.3 Tcfe after using an industry standard ratio of 6-to-1 to convert oil and NGL reserves to natural gas equivalent.
2012 CAPITAL INVESTMENT
As previously reported, 95 percent of WPX’s 2012 $1.2 billion domestic capital budget is focused on the company’s core areas in the Bakken Shale, Piceance Basin and Marcellus Shale, with approximately 65 percent of the budget designated for areas with oil and NGL production.
For 2012, WPX plans to add a sixth rig in the Bakken Shale at mid-year and deploy an average of five rigs in the Piceance Basin and three rigs in Susquehanna County in the Marcellus Shale.
In keeping with the company’s philosophy for capital discipline, this equates to a more than 40 percent decrease in the company’ s rig count in the Piceance and Marcellus vs. the original plan for 2012 activity.
The company’s 2012 capital spending is expected to yield a 50-60 percent increase in domestic oil production and an 8 percent increase in NGL production.
TODAY’S CONFERENCE CALL
WPX management will discuss the results during a Live Meeting starting at 10:30 a.m. EST today. Participants can view the slides for the meeting via a link atwww.wpxenergy.com.
To hear the audio for the conference, participants also will need to dial (888) 334-2993. The passcode is 4022996. International callers should dial (719) 325-2309 and use the same passcode.
Form 10-K
WPX plans to file its 2011 Form 10-K with the Securities and Exchange Commission next week. Once filed, the document will be available on both the SEC and WPX websites.
About WPX Energy, Inc.
WPX Energy is an exploration and production company focused on developing its significant natural gas, natural gas liquids and oil reserves, particularly in the Piceance Basin, Bakken Shale and Marcellus Shale. The company also has domestic operations in the Powder River and San Juan basins and the Barnett Shale, as well as international investments in Argentina and Colombia. Go to http://www.wpxenergy.com/investors/subscribe-to-email/ to join our e-mail list.
WPX Energy, Inc.
Consolidated
(UNAUDITED)
| 2010 | 2011 | |||||||||||||||||||||||||||||||||||||||
(Dollars in millions) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | ||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||||||||||
Product revenues | ||||||||||||||||||||||||||||||||||||||||
Natural gas sales | $ | 490 | $ | 427 | $ | 454 | $ | 441 | $ | 1,812 | $ | 434 | $ | 453 | $ | 464 | $ | 444 | $ | 1,795 | ||||||||||||||||||||
Natural gas liquid sales | 71 | 68 | 61 | 85 | 285 | 86 | 105 | 110 | 107 | 408 | ||||||||||||||||||||||||||||||
Oil and condensate sales | 26 | 32 | 31 | 39 | 128 | 52 | 84 | 86 | 93 | 315 | ||||||||||||||||||||||||||||||
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Total product revenues | 587 | 527 | 546 | 565 | 2,225 | 572 | 642 | 660 | 644 | 2,518 | ||||||||||||||||||||||||||||||
Gas management | 556 | 366 | 435 | 385 | 1,742 | 408 | 337 | 347 | 336 | 1,428 | ||||||||||||||||||||||||||||||
Hedge ineffectiveness and mark to market gains and losses | 9 | — | 16 | 2 | 27 | 2 | 6 | 12 | 9 | 29 | ||||||||||||||||||||||||||||||
Other | 12 | 11 | 9 | 8 | 40 | 2 | 5 | 3 | 3 | 13 | ||||||||||||||||||||||||||||||
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Total revenues | 1,164 | 904 | 1,006 | 960 | 4,034 | 984 | 990 | 1,022 | 992 | 3,988 | ||||||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||||||||
Lease and facility operating expense | 66 | 66 | 75 | 79 | 286 | 70 | 70 | 78 | 77 | 295 | ||||||||||||||||||||||||||||||
Gathering, processing and transportation | 72 | 73 | 71 | 110 | 326 | 115 | 125 | 132 | 127 | 499 | ||||||||||||||||||||||||||||||
Taxes other than income | 40 | 33 | 36 | 16 | 125 | 31 | 45 | 33 | 31 | 140 | ||||||||||||||||||||||||||||||
Gas management ,including charges for unutilized pipeline capacity | 558 | 376 | 451 | 386 | 1,771 | 417 | 345 | 360 | 351 | 1,473 | ||||||||||||||||||||||||||||||
Exploration | 8 | 10 | 27 | 28 | 73 | 13 | 20 | 74 | 27 | 134 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 216 | 217 | 222 | 220 | 875 | 216 | 236 | 251 | 246 | 949 | ||||||||||||||||||||||||||||||
Impairment of producing properties and costs of acquired unproved reserves | — | — | 678 | — | 678 | — | — | — | 547 | 547 | ||||||||||||||||||||||||||||||
Goodwill impairment | — | — | 1,003 | — | 1,003 | — | — | — | — | — | ||||||||||||||||||||||||||||||
General and aministrative | 61 | 61 | 61 | 70 | 253 | 70 | 65 | 73 | 77 | 285 | ||||||||||||||||||||||||||||||
Other-net | — | 3 | (9 | ) | (13 | ) | (19 | ) | 3 | 2 | (1 | ) | (3 | ) | 1 | |||||||||||||||||||||||||
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Total costs and expenses | 1,021 | 839 | 2,615 | 896 | 5,371 | 935 | 908 | 1,000 | 1,480 | 4,323 | ||||||||||||||||||||||||||||||
Operating income (loss) | 143 | 65 | (1,609 | ) | 64 | (1,337 | ) | 49 | 82 | 22 | (488 | ) | (335 | ) | ||||||||||||||||||||||||||
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Interest expense | (25 | ) | (25 | ) | (38 | ) | (36 | ) | (124 | ) | (49 | ) | (48 | ) | — | (20 | ) | (117 | ) | |||||||||||||||||||||
Interest capitalized | 4 | 4 | 4 | 4 | 16 | 4 | 4 | — | 1 | 9 | ||||||||||||||||||||||||||||||
Investment income and other | 5 | 6 | 4 | 6 | 21 | 6 | 6 | 7 | 7 | 26 | ||||||||||||||||||||||||||||||
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Income (loss) from continuing operations before income taxes | $ | 127 | $ | 50 | $ | (1,639 | ) | $ | 38 | $ | (1,424 | ) | $ | 10 | $ | 44 | $ | 29 | $ | (500 | ) | $ | (417 | ) | ||||||||||||||||
Provision (benefit) for income taxes | $ | 44 | $ | 18 | $ | (229 | ) | $ | 18 | $ | (149 | ) | $ | 3 | $ | 16 | $ | 10 | $ | (174 | ) | $ | (145 | ) | ||||||||||||||||
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Income (loss) from continuing operations | $ | 83 | $ | 32 | $ | (1,410 | ) | $ | 20 | $ | (1,275 | ) | $ | 7 | $ | 28 | $ | 19 | $ | (326 | ) | $ | (272 | ) | ||||||||||||||||
Loss from discontinued operations | $ | — | $ | (1 | ) | $ | (1 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) | $ | — | $ | (3 | ) | $ | (9 | ) | $ | (20 | ) | ||||||||||||
Net income (loss) | $ | 83 | $ | 31 | $ | (1,411 | ) | $ | 14 | $ | (1,283 | ) | $ | (1 | ) | $ | 28 | $ | 16 | $ | (335 | ) | $ | (292 | ) | |||||||||||||||
Less: Net income attributable to noncontrolling interests | $ | 2 | $ | 2 | $ | 2 | $ | 2 | $ | 8 | $ | 2 | $ | 3 | $ | 2 | $ | 3 | $ | 10 | ||||||||||||||||||||
Net income (loss) attributable to WPX Energy | $ | 81 | $ | 29 | $ | (1,413 | ) | $ | 12 | $ | (1,291 | ) | $ | (3 | ) | $ | 25 | $ | 14 | $ | (338 | ) | $ | (302 | ) | |||||||||||||||
Adjusted EBITDAX Reconciliation to Net Income (Loss): | ||||||||||||||||||||||||||||||||||||||||
Net income (loss) | $ | 83 | $ | 31 | $ | (1,411 | ) | $ | 14 | $ | (1,283 | ) | $ | (1 | ) | $ | 28 | $ | 16 | $ | (335 | ) | $ | (292 | ) | |||||||||||||||
Interest expense | 25 | 25 | 38 | 36 | 124 | 49 | 48 | — | 20 | 117 | ||||||||||||||||||||||||||||||
Provision (benefit) for income taxes | 44 | 18 | (229 | ) | 18 | (149 | ) | 3 | 16 | 10 | (174 | ) | (145 | ) | ||||||||||||||||||||||||||
Depreciation, depletion and amortization | 216 | 217 | 222 | 220 | 875 | 216 | 236 | 251 | 246 | 949 | ||||||||||||||||||||||||||||||
Exploration expenses | 8 | 10 | 27 | 28 | 73 | 13 | 20 | 74 | 27 | 134 | ||||||||||||||||||||||||||||||
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EBITDAX | 376 | 301 | (1,353 | ) | 316 | (360 | ) | 280 | 348 | 351 | (216 | ) | 763 | |||||||||||||||||||||||||||
Impairments of goodwill, producing properties and cost of acquired unproved reserves | — | — | 1,681 | — | 1,681 | — | — | — | 547 | 547 | ||||||||||||||||||||||||||||||
Loss from discontinued operations | — | 1 | 1 | 6 | 8 | 8 | — | 3 | 9 | 20 | ||||||||||||||||||||||||||||||
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Adjusted EBITDAX | $ | 376 | $ | 302 | $ | 329 | $ | 322 | $ | 1,329 | $ | 288 | $ | 348 | $ | 354 | $ | 340 | $ | 1,330 | ||||||||||||||||||||
WPX Energy, Inc.
Domestic Segment
(UNAUDITED)
| 2010 | 2011 | |||||||||||||||||||||||||||||||||||||||
(Dollars in millions) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | ||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||||||||||
Product revenues | ||||||||||||||||||||||||||||||||||||||||
Natural gas sales | $ | 486 | $ | 424 | $ | 451 | $ | 436 | $ | 1,797 | $ | 430 | $ | 449 | $ | 460 | $ | 440 | $ | 1,779 | ||||||||||||||||||||
Natural gas liquid sales | 70 | 67 | 60 | 85 | 282 | 85 | 104 | 109 | 106 | 404 | ||||||||||||||||||||||||||||||
Oil and condensate sales | 11 | 14 | 13 | 19 | 57 | 34 | 64 | 64 | 67 | 229 | ||||||||||||||||||||||||||||||
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Total product revenues | 567 | 505 | 524 | 540 | 2,136 | 549 | 617 | 633 | 613 | 2,412 | ||||||||||||||||||||||||||||||
Gas management | 556 | 366 | 435 | 385 | 1,742 | 408 | 337 | 347 | 336 | 1,428 | ||||||||||||||||||||||||||||||
Hedge ineffectiveness and mark to market gains and losses | 9 | — | 16 | 2 | 27 | 2 | 6 | 12 | 9 | 29 | ||||||||||||||||||||||||||||||
Other | 12 | 11 | 9 | 8 | 40 | 1 | 4 | 2 | 2 | 9 | ||||||||||||||||||||||||||||||
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Total revenues | 1,144 | 882 | 984 | 935 | 3,945 | 960 | 964 | 994 | 960 | 3,878 | ||||||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||||||||
Lease and facility operating expense | 63 | 61 | 70 | 73 | 267 | 65 | 64 | 71 | 68 | 268 | ||||||||||||||||||||||||||||||
Gathering, processing and transportation | 72 | 73 | 71 | 110 | 326 | 115 | 125 | 132 | 127 | 499 | ||||||||||||||||||||||||||||||
Taxes other than income | 37 | 29 | 32 | 11 | 109 | 28 | 39 | 27 | 25 | 119 | ||||||||||||||||||||||||||||||
Gas management, including charges for unutilized pipeline capacity | 558 | 376 | 451 | 386 | 1,771 | 417 | 345 | 360 | 351 | 1,473 | ||||||||||||||||||||||||||||||
Exploration | 4 | 8 | 27 | 28 | 67 | 12 | 19 | 74 | 26 | 131 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 212 | 213 | 218 | 215 | 858 | 211 | 231 | 245 | 240 | 927 | ||||||||||||||||||||||||||||||
Impairment of producing properties and costs of acquired unproved reserves | — | 678 | — | 678 | — | — | — | 547 | 547 | |||||||||||||||||||||||||||||||
Goodwill impairment | — | 1,003 | — | 1,003 | — | — | — | — | — | |||||||||||||||||||||||||||||||
General and aministrative, including Williams | 59 | 59 | 58 | 68 | 244 | 67 | 63 | 70 | 73 | 273 | ||||||||||||||||||||||||||||||
Other-net | — | 3 | (9 | ) | (13 | ) | (19 | ) | 2 | 2 | (2 | ) | (4 | ) | (2 | ) | ||||||||||||||||||||||||
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Total costs and expenses | 1,005 | 822 | 2,599 | 878 | 5,304 | 917 | 888 | 977 | 1,453 | 4,235 | ||||||||||||||||||||||||||||||
Operating income (loss) | 139 | 60 | (1,615 | ) | 57 | (1,359 | ) | 43 | 76 | 17 | (493 | ) | (357 | ) | ||||||||||||||||||||||||||
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Interest expense | (25 | ) | (25 | ) | (38 | ) | (36 | ) | (124 | ) | (49 | ) | (48 | ) | — | (20 | ) | (117 | ) | |||||||||||||||||||||
Interest capitalized | 4 | 4 | 4 | 4 | 16 | 4 | 4 | — | 1 | 9 | ||||||||||||||||||||||||||||||
Investment income and other | 1 | 1 | 1 | 1 | 4 | 1 | 2 | 2 | 1 | 6 | ||||||||||||||||||||||||||||||
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Income (loss) from continuing operations before income taxes | $ | 119 | $ | 40 | $ | (1,648 | ) | $ | 26 | $ | (1,463 | ) | $ | (1 | ) | $ | 34 | $ | 19 | $ | (511 | ) | $ | (459 | ) | |||||||||||||||
Summary of Production Volumes (1) | ||||||||||||||||||||||||||||||||||||||||
Natural gas (mmcf) | 94,641 | 95,954 | 99,358 | 102,822 | 392,775 | 98,185 | 101,481 | 108,734 | 105,120 | 413,520 | ||||||||||||||||||||||||||||||
Natural gas liquids (MBbls) | 1,813 | 2,058 | 1,945 | 2,240 | 8,056 | 2,426 | 2,527 | 2,567 | 2,539 | 10,059 | ||||||||||||||||||||||||||||||
Oil (MBbls) | 167 | 204 | 222 | 264 | 857 | 392 | 720 | 743 | 822 | 2,677 | ||||||||||||||||||||||||||||||
Combined equivalent volumes (mmcfe) (2) | 106,523 | 109,526 | 112,357 | 117,847 | 446,253 | 115,089 | 120,963 | 128,591 | 125,285 | 489,926 | ||||||||||||||||||||||||||||||
(1) Excludes production from our Arkoma Basin operations which are reported as discontinued operations and comprised less than one percent of our total production. |
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(2) Amounts for 2010 have been recalculated using a conversion ratio for our NGLs of 6 to 1 as these were previously reported in natural gas volumes. |
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Realized average price per unit, including the impact of hedges (1) | ||||||||||||||||||||||||||||||||||||||||
Natural gas (per mmcf) | 5.14 | 4.42 | 4.54 | 4.24 | 4.57 | 4.38 | 4.42 | 4.23 | 4.19 | 4.30 | ||||||||||||||||||||||||||||||
Natural gas liquids (per bbl) | 38.61 | 32.56 | 30.85 | 37.95 | 35.02 | 35.04 | 41.16 | 42.46 | 41.75 | 40.17 | ||||||||||||||||||||||||||||||
Oil (per bbl) | 65.87 | 68.63 | 58.56 | 71.97 | 66.32 | 86.73 | 88.89 | 86.14 | 81.51 | 85.38 | ||||||||||||||||||||||||||||||
(1) Excludes our Arkoma Basin operations, which are reported as discontinued operations. |
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Expenses per Mmcfe (1) | ||||||||||||||||||||||||||||||||||||||||
Lease and facility operating expense | 0.59 | 0.56 | 0.62 | 0.62 | 0.60 | 0.56 | 0.53 | 0.55 | 0.54 | 0.55 | ||||||||||||||||||||||||||||||
Gathering, processing and transportation | 0.68 | 0.67 | 0.63 | 0.93 | 0.73 | 1.00 | 1.03 | 1.03 | 1.01 | 1.02 | ||||||||||||||||||||||||||||||
Taxes other than income | 0.35 | 0.26 | 0.28 | 0.09 | 0.24 | 0.24 | 0.32 | 0.21 | 0.20 | 0.24 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1.99 | 1.94 | 1.94 | 1.82 | 1.92 | 1.83 | 1.91 | 1.91 | 1.92 | 1.89 | ||||||||||||||||||||||||||||||
General and aministrative | 0.55 | 0.54 | 0.52 | 0.58 | 0.55 | 0.58 | 0.52 | 0.54 | 0.58 | 0.56 | ||||||||||||||||||||||||||||||
(1) Excludes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations. |
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WPX Energy, Inc.
International Segment
(UNAUDITED)
| 2010 | 2011 | |||||||||||||||||||||||||||||||||||||||
(Dollars in millions) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | ||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||||||||||
Product revenues: | ||||||||||||||||||||||||||||||||||||||||
Natural gas sales | $ | 4 | $ | 3 | $ | 3 | $ | 5 | $ | 15 | $ | 4 | $ | 4 | $ | 4 | $ | 4 | $ | 16 | ||||||||||||||||||||
Natural gas liquid sales | 1 | 1 | 1 | — | 3 | 1 | 1 | 1 | 1 | 4 | ||||||||||||||||||||||||||||||
Oil and condensate sales | 15 | 18 | 18 | 20 | 71 | 18 | 20 | 22 | 26 | 86 | ||||||||||||||||||||||||||||||
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Total product revenues | 20 | 22 | 22 | 25 | 89 | 23 | 25 | 27 | 31 | 106 | ||||||||||||||||||||||||||||||
Gas management | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Hedge ineffectiveness and mark to market gains and losses | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Other | — | — | — | — | — | 1 | 1 | 1 | 1 | 4 | ||||||||||||||||||||||||||||||
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Total revenues | 20 | 22 | 22 | 25 | 89 | 24 | 26 | 28 | 32 | 110 | ||||||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||||||||
Lease and facility operating expense | 3 | 5 | 5 | 6 | 19 | 5 | 6 | 7 | 9 | 27 | ||||||||||||||||||||||||||||||
Gathering, processing and transportation | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
Taxes other than income | 3 | 4 | 4 | 5 | 16 | 3 | 6 | 6 | 6 | 21 | ||||||||||||||||||||||||||||||
Gas management (including charges for unutilized pipeline capacity) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
Exploration | 4 | 2 | — | — | 6 | 1 | 1 | — | 1 | 3 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 4 | 4 | 4 | 5 | 17 | 5 | 5 | 6 | 6 | 22 | ||||||||||||||||||||||||||||||
Impairment of producing properties and costs of acquired unproved reserves | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
Goodwill impairment | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
General and aministrative | 2 | 2 | 3 | 2 | 9 | 3 | 2 | 3 | 4 | 12 | ||||||||||||||||||||||||||||||
Other-net | — | 1 | — | 1 | 1 | 3 | ||||||||||||||||||||||||||||||||||
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Total costs and expenses | 16 | 17 | 16 | 18 | 67 | 18 | 20 | 23 | 27 | 88 | ||||||||||||||||||||||||||||||
Operating income (loss) | 4 | 5 | 6 | 7 | 22 | 6 | 6 | 5 | 5 | 22 | ||||||||||||||||||||||||||||||
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Interest expense | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Interest capitalized | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
Investment income and other | 4 | 5 | 3 | 5 | 17 | 5 | 4 | 5 | 6 | 20 | ||||||||||||||||||||||||||||||
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Income (loss) from continuing operations before income taxes | $ | 8 | $ | 10 | $ | 9 | $ | 12 | $ | 39 | $ | 11 | $ | 10 | $ | 10 | $ | 11 | $ | 42 | ||||||||||||||||||||
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Summary of Production Volumes | ||||||||||||||||||||||||||||||||||||||||
Total (mmcfe) (1) (2) | 4,773 | 5,116 | 4,895 | 5,155 | 19,940 | 4,926 | 5,280 | 5,231 | 5,373 | 20,810 | ||||||||||||||||||||||||||||||
| (1) | Converted using 6 to 1 conversion rate for NGL and Oil |
| (2) | Refelcts approximately 69 percent of Apco's production. |
# # #
This press release includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the company. Statements regarding future drilling and production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, the volatility of oil, natural gas and NGL prices; uncertainties inherent in estimating oil, natural gas and NGL reserves; drilling risks; environmental risks; and political or regulatory changes. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this press release are made as of the date of this press release, even if subsequently made available by WPX Energy on its website or otherwise. WPX Energy does not undertake and expressly disclaims any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Investors are urged to consider carefully the disclosure in our filings with the Securities and Exchange Commission, available from us at WPX Energy, Attn: Investor Relations, P.O. Box 21810, Tulsa, Okla., 74102, or from the SEC’s website atwww.sec.gov.
Additionally, the SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. From time to time, we elect to use “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines”possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines. Investors are urged to consider closely the disclosure in our SEC filings that may be accessed through the SEC’s website atwww.sec.gov.
The SEC’s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.