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Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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WPX Energy, Inc.
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(Exact Name of Registrant as Specified in Its Charter)
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Delaware
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45-1836028
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(State or Other Jurisdiction of
Incorporation or Organization)
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(IRS Employer
Identification No.)
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3500 One Williams Center, Tulsa, Oklahoma
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74172-0172
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(Address of Principal Executive Offices)
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(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.01 par value
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New York Stock Exchange
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6.25% Series A Mandatory Convertible Preferred Stock,
$0.01 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act: None
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Large accelerated filer
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þ
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Accelerated filer
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¨
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Non-accelerated filer
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¨
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(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Page
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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Item 1.
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Business
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•
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Focused, Long-Term Portfolio Management
. We are focused on long-term profitable growth. Our objective over time is to grow our production within our cash flow. With that in mind, we regularly evaluate the performance of our assets and, when appropriate, we consider divestitures of assets that are underperforming or which are no longer a part of our strategic focus. Since mid-2014, we have completed approximately $5.5 billion of asset acquisitions and divestitures, allowing us to focus on our core areas and strengthen our financial position. With regard to our core assets, we expect to allocate capital to the most profitable opportunities based on commodity price cycles and other market conditions, enabling us to grow our reserves and production in a manner that maximizes our returns on investments.
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•
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Build Asset Scale.
We expect to opportunistically acquire acreage positions in areas where we feel we can establish significant scale and replicate cost-efficient development practices. We may also consider other “bolt-on” transactions that are directed at driving operational efficiencies through increased scale. We can manage costs by focusing on the establishment of large scale, contiguous acreage blocks where we can operate a majority of the properties. We believe this strategy allows us to better achieve economies of scale and apply continuous technological improvements in our operations. We have a history of acquiring undeveloped properties that meet our expected return requirements and other acquisition criteria to expand upon our existing positions as well as acquiring undeveloped acreage in new geographic areas that offer significant resource potential.
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•
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Margin Expansion thru Focus on Costs
. We believe we can expand our margins by focusing on opportunities to reduce our cost structure through improved operating efficiencies and minimal increases in employee headcount as we grow. As we have rationalized our portfolio and reduced our areas of focus to core basins, we believe our cost structure and our organization size are in alignment with our margin growth objectives.
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•
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Continue Oil Development and Increase Optionality.
We believe that efforts to develop our oil properties will yield a more balanced commodity mix in our production, providing us with the option of focusing on the commodity with the best returns under different market conditions. This optionality, we believe, will place us in a position where we can better protect and grow our cash flows. We have engaged in, and will continue to engage in, commodity derivative hedging activities to maintain a degree of cash flow stability. Typically, we target hedging approximately 50 percent of expected revenue from domestic production during a current calendar year in order to strike an appropriate balance of commodity price upside with cash flow protection, although we may vary from this level based on our perceptions of market risk. We have hedged
39,554
Bbls per day and
30,000
Bbls per day of our anticipated remaining 2017 and 2018 oil production, respectively, at a weighted average price of $
50.93
per barrel and
$54.61
per barrel, respectively. We also have natural gas derivatives totaling
170,000
MMBtu per day and
155,000
MMBtu per day for the remainder of 2017 and 2018, respectively, at a weighted average price of $
3.02
per MMBtu and
$2.98
per MMBtu, respectively.
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•
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Maintain Financial Flexibility.
We believe that our continued focus on cost reductions, increased capital efficiency and long-term oil production growth will allow us to generate increased and sustainable annual cash flows from operations. This cash flow, combined with our capital structure and available sources of liquidity, will allow us to efficiently develop and grow our resource base and pursue reserve growth throughout a variety of commodity price environments.
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As of December 31, 2016
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||||||||||||
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Oil
(Mbbls)
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Gas
(MMcf)
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NGL
(Mbbls)
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Equivalent
(Mboe)
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%
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||||
Proved Developed
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84,372
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440,161
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24,065
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181,797
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52%
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Proved Undeveloped
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90,191
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294,240
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25,378
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164,609
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48%
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Total Proved
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174,563
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|
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734,401
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49,443
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346,406
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As of December 31, 2016
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||||||||||
Oil
(Mbbls)
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Gas
(MMcf)
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NGL
(Mbbls)
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Equivalent
(Mboe)
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|||||
Delaware Basin
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66,866
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|
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274,629
|
|
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30,895
|
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143,532
|
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Williston Basin
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86,785
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51,771
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9,486
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|
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104,900
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San Juan Basin
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20,817
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367,943
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8,820
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90,961
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Other
|
95
|
|
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40,058
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|
|
242
|
|
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7,013
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Total Proved
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174,563
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734,401
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49,443
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346,406
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% of
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% of
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MMboe
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December 31, 2015
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December 31, 2016
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Proved Undeveloped Reserves at December 31, 2015
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181
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Converted to Proved Developed Reserves
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(18
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)
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(10)%
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(11)%
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Extensions and Discoveries
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85
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47%
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52%
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Revisions
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(17
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)
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(9)%
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(10)%
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Acquisitions
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1
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1%
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1%
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Divestitures
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(67
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)
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(37)%
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(41)%
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Proved Undeveloped Reserves at December 31, 2016
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165
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Year Ended December 31,
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Year Ended December 31,
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||||||||||||||
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2016
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2015
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2014
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2016
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2015
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2014
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||||||
Oil
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(Mbbls)
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(Mbbls/d)
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||||||||||||||
Delaware Basin
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4,773
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1,261
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(a)
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—
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13.0
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3.5
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(b)
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—
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Williston Basin
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7,596
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7,958
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7,123
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20.8
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21.8
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19.5
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San Juan Basin
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2,782
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3,252
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1,426
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7.6
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8.9
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3.9
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Other
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27
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8
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19
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0.1
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—
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0.1
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Total
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15,178
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12,479
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8,568
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41.5
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34.2
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23.5
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Natural Gas
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(MMcf)
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(MMcf/d)
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||||||||||||||
Delaware Basin
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15,818
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4,217
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(a)
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—
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43.2
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11.6
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(b)
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—
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Williston Basin
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4,603
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4,284
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3,056
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12.6
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11.7
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8.4
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San Juan Basin
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45,728
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47,093
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40,133
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124.9
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129.0
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110.0
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Other
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6,693
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10,593
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31,344
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18.3
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|
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29.0
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|
|
85.8
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Total
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72,842
|
|
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66,187
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74,533
|
|
|
199.0
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|
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181.3
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204.2
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||||||
NGLs
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(Mbbls)
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(Mbbls/d)
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||||||||||||||
Delaware Basin
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1,445
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|
409
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(a)
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—
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4.0
|
|
|
1.1
|
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(b)
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—
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Williston Basin
|
782
|
|
|
720
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|
|
538
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|
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2.1
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|
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2.0
|
|
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1.5
|
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San Juan Basin
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1,388
|
|
|
1,247
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|
|
327
|
|
|
3.8
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|
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3.4
|
|
|
0.9
|
|
Other
|
30
|
|
|
36
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|
|
33
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
Total
|
3,645
|
|
|
2,412
|
|
|
898
|
|
|
10.0
|
|
|
6.6
|
|
|
2.5
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
Combined Equivalent Volumes
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(Mboe)
|
|
(Mboe/d)
|
||||||||||||||
Delaware Basin
|
8,854
|
|
|
2,373
|
|
(a)
|
—
|
|
|
24.2
|
|
|
6.5
|
|
(b)
|
—
|
|
Williston Basin
|
9,145
|
|
|
9,392
|
|
|
8,170
|
|
|
25.0
|
|
|
25.7
|
|
|
22.4
|
|
San Juan Basin
|
11,791
|
|
|
12,348
|
|
|
8,442
|
|
|
32.2
|
|
|
33.8
|
|
|
23.1
|
|
Other
|
1,173
|
|
|
1,809
|
|
|
5,276
|
|
|
3.2
|
|
|
5.0
|
|
|
14.5
|
|
Total
|
30,963
|
|
|
25,922
|
|
|
21,888
|
|
|
84.6
|
|
|
71.0
|
|
|
60.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Oil(a):
|
|
|
|
|
|
||||||
Oil excluding all derivative settlements (per barrel)
|
$
|
36.31
|
|
|
$
|
39.61
|
|
|
$
|
78.09
|
|
Impact of net cash received related to settlement of derivatives (per barrel)
|
12.50
|
|
|
31.21
|
|
|
2.17
|
|
|||
Oil net price including all derivative settlements (per barrel)
|
$
|
48.81
|
|
|
$
|
70.82
|
|
|
$
|
80.26
|
|
Natural gas(a):
|
|
|
|
|
|
||||||
Natural gas excluding all derivative settlements (per Mcf)
|
$
|
1.72
|
|
|
$
|
2.08
|
|
|
$
|
3.78
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)
|
1.53
|
|
|
3.93
|
|
|
(0.37
|
)
|
|||
Natural gas net price including all derivative settlements (per Mcf)
|
$
|
3.25
|
|
|
$
|
6.01
|
|
|
$
|
3.41
|
|
NGL(a):
|
|
|
|
|
|
||||||
NGL excluding all derivative settlements (per barrel)
|
$
|
12.48
|
|
|
$
|
9.39
|
|
|
$
|
22.94
|
|
Impact of net cash received related to settlement of derivatives (per barrel)
|
—
|
|
|
—
|
|
|
7.81
|
|
|||
NGL net price including all derivative settlements (per barrel)
|
$
|
12.48
|
|
|
$
|
9.39
|
|
|
$
|
30.75
|
|
|
|
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|
||||||
Combined commodity price per Mboe, including all derivative settlements
|
$
|
33.04
|
|
|
$
|
50.32
|
|
|
$
|
44.30
|
|
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Year Ended December 31,
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||||||||||
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2016
|
|
2015
|
|
2014
|
||||||
Production costs:
|
|
|
|
|
|
||||||
Lifting costs and workovers
|
$
|
4.74
|
|
|
$
|
5.02
|
|
|
$
|
5.96
|
|
Facilities operating expense
|
0.30
|
|
|
0.34
|
|
|
0.26
|
|
|||
Accretion expense
|
0.18
|
|
|
0.19
|
|
|
0.22
|
|
|||
Other operating and maintenance
|
0.04
|
|
|
0.04
|
|
|
0.07
|
|
|||
Total LOE
|
$
|
5.26
|
|
|
$
|
5.59
|
|
|
$
|
6.51
|
|
Gathering, processing and transportation charges
|
2.45
|
|
|
2.48
|
|
|
3.25
|
|
|||
Taxes other than income
|
1.94
|
|
|
2.38
|
|
|
4.03
|
|
|||
Total production cost
|
$
|
9.65
|
|
|
$
|
10.45
|
|
|
$
|
13.79
|
|
General and administrative
|
$
|
6.90
|
|
|
$
|
8.12
|
|
|
$
|
10.24
|
|
Depreciation, depletion and amortization
|
$
|
20.11
|
|
|
$
|
20.39
|
|
|
$
|
16.58
|
|
|
Oil Wells
(Gross)
|
|
Oil Wells
(Net)
|
|
Gas Wells
(Gross)
|
|
Gas Wells
(Net)
|
||||
Delaware Basin
|
1,203
|
|
|
577
|
|
|
222
|
|
|
108
|
|
Williston Basin
|
320
|
|
|
187
|
|
|
—
|
|
|
—
|
|
San Juan Basin
|
166
|
|
|
146
|
|
|
3,198
|
|
|
913
|
|
Other(a)
|
—
|
|
|
—
|
|
|
1,224
|
|
|
51
|
|
Total
|
1,689
|
|
|
910
|
|
|
4,644
|
|
|
1,072
|
|
(a)
|
Includes Green River Basin, Appalachia Basin and other miscellaneous properties.
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||||||||
|
Gross Acres
|
|
Net Acres
|
|
Gross Acres
|
|
Net Acres
|
|
Gross Acres
|
|
Net Acres
|
||||||
Delaware Basin
|
125,344
|
|
|
69,292
|
|
|
54,832
|
|
|
28,689
|
|
|
180,176
|
|
|
97,981
|
|
Williston Basin
|
68,198
|
|
|
59,661
|
|
|
64,133
|
|
|
24,918
|
|
|
132,331
|
|
|
84,579
|
|
San Juan Basin
|
276,388
|
|
|
158,587
|
|
|
99,527
|
|
|
76,978
|
|
|
375,915
|
|
|
235,565
|
|
Other(a)
|
44,832
|
|
|
11,795
|
|
|
120,382
|
|
|
79,665
|
|
|
165,214
|
|
|
91,460
|
|
Total
|
514,762
|
|
|
299,335
|
|
|
338,874
|
|
|
210,250
|
|
|
853,636
|
|
|
509,585
|
|
(a)
|
Primarily acreage in exploratory areas we no longer plan to develop.
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
Gross Wells
|
|
Net Wells
|
|
Gross Wells
|
|
Net Wells
|
|
Gross Wells
|
|
Net Wells
|
||||||
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Delaware Basin
|
40
|
|
|
31
|
|
|
19
|
|
(a)
|
16
|
|
(a)
|
—
|
|
|
—
|
|
Williston Basin
|
25
|
|
|
21
|
|
|
21
|
|
|
13
|
|
|
55
|
|
|
45
|
|
San Juan Basin
|
12
|
|
|
12
|
|
|
53
|
|
|
46
|
|
|
47
|
|
|
44
|
|
Other(b)
|
41
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
42
|
|
|
7
|
|
Development well total
|
118
|
|
|
64
|
|
|
127
|
|
|
75
|
|
|
144
|
|
|
96
|
|
Exploration wells:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Nonproductive(c)
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
5
|
|
|
5
|
|
Exploration well total
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
5
|
|
|
5
|
|
Total Drilled
|
118
|
|
|
64
|
|
|
128
|
|
|
76
|
|
|
149
|
|
|
101
|
|
(a)
|
Reflects wells drilled from the Acquisition date of August 17, 2015 through December 31, 2015.
|
(b)
|
Includes Appalachia Basin, Green River Basin and other miscellaneous properties.
|
(c)
|
Reflects exploration wells which were drilled and not completed.
|
|
2017
|
|
2018
|
|
2019
|
|
2020+
|
|
Total
|
|||||
Delaware Basin
|
2,402
|
|
|
638
|
|
|
2,938
|
|
|
3,865
|
|
|
9,843
|
|
Williston Basin
|
122
|
|
|
426
|
|
|
156
|
|
|
—
|
|
|
704
|
|
San Juan Basin
|
6,684
|
|
|
11,365
|
|
|
12,351
|
|
|
6,267
|
|
|
36,667
|
|
Other(a)
|
43,845
|
|
|
6,854
|
|
|
6,567
|
|
|
13,499
|
|
|
70,765
|
|
Total (Net Acres)
|
53,053
|
|
|
19,283
|
|
|
22,012
|
|
|
23,631
|
|
|
117,979
|
|
(a)
|
Primarily acreage in exploratory areas we no longer plan to develop.
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the timing of construction or drilling activities including seasonal wildlife closures;
|
•
|
the employment of tribal members or use of tribal owned service businesses;
|
•
|
the rates of production or “allowables”;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells;
|
•
|
the notice to surface owners and other third parties; and
|
•
|
the use, maintenance and restoration of roads and bridges used during all phases of drilling and production.
|
•
|
Prior to perforating the production casing and hydraulic fracturing operations, the casing is pressure tested.
|
•
|
Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all pressurized lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, specialized equipment is utilized to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Should any problem be detected during the hydraulic fracturing treatment, the operation is shut down until the problem is evaluated, reported and remediated.
|
•
|
As a means to protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken to ensure proper containment and storage of fluids. For example, any earthen pits containing non-fresh water must be lined with a synthetic impervious liner. These pits are tested regularly, and in certain sensitive areas have additional leak detection systems in place. At least two feet of freeboard, or available capacity, must be present in the pit at all times. In addition, earthen berms are constructed around any storage tanks, any fluid handling equipment, and in some cases around the perimeter of the location to contain any fluid releases. These berms are considered to be a “secondary” form of containment and serve as an added measure for the protection of groundwater.
|
•
|
We conduct baseline water monitoring in some of the basins in which we use hydraulic fracturing.
|
•
|
In Colorado we perform baseline water monitoring required by the Colorado Oil and Gas Conservation Commission.
|
•
|
The BLM may require baseline water monitoring as a condition of approval for drilling permits.
|
•
|
There are currently no regulatory requirements to conduct baseline water monitoring in the Williston Basin, the Delaware Basin or the New Mexico portion of our San Juan Basin assets. The majority of our assets in the San Juan Basin are on federal lands, and there are few cases where water wells are within one to two miles of our wells, which is outside the range that we would typically sample.
|
•
|
Improper cementing work. This can create conditions in which hydraulic fracturing fluids and other natural occurring substances can migrate into the surrounding geological formation. Production casing cementing tops and cement bond effectiveness are evaluated using either a temperature log or an acoustical cement bond log prior to any completion operations. If the cement bond or cement top is determined to be inadequate for zone isolation, remedial cementing operations are performed to fill any voids and re-establish integrity. As part of this remedial operation, the casing is again pressure tested before fracturing operations are initiated.
|
•
|
Initial casing integrity failure. The casing is pressure tested prior to commencing completion operations. If the test fails due to a compromise in the casing, the applicable oil and gas regulatory body will be notified and a remediation procedure will be written, approved and completed before any further operations are conducted. In addition, casing
|
•
|
Well failure or casing integrity failure during production. Loss of wellbore integrity can occur over time even if the well was correctly constructed due to downhole operating environments causing corrosion and stress. During production, the bradenhead, casing and tubing pressures are monitored and a casing failure can be identified and evaluated. Remediation could include placing additional cement behind casing, installing a casing patch, or plugging and abandoning the well, if necessary.
|
•
|
“Fluid leakoff” during the fracturing process. Fluid leakoff can occur during hydraulic fracturing operations whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropore or pore spaces within the formation, existing natural fractures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. Fluid leakoff is accounted for in the volume design of nearly every fracturing job and “pump-in” tests are often conducted prior to fracturing jobs to estimate the extent of fluid leakoff. In certain situations, very fine grain sand is added in the initial part of the treatment to seal-off any small fractures of micropore spaces and mitigate fluid leak-off.
|
•
|
Amended and Restated Certificate of Incorporation
|
•
|
Restated Bylaws
|
•
|
Corporate Governance Guidelines
|
•
|
Code of Business Conduct, which is applicable to all WPX Energy directors and employees, including the principal executive officer, the principal financial officer and the principal accounting officer
|
•
|
Audit Committee Charter
|
•
|
Compensation Committee Charter
|
•
|
Nominating and Governance Committee Charter
|
Item 1A.
|
Risk Factors
|
•
|
amounts and nature of future capital expenditures;
|
•
|
expansion and growth of our business and operations;
|
•
|
financial condition and liquidity;
|
•
|
business strategy;
|
•
|
estimates of proved oil and natural gas reserves;
|
•
|
reserve potential;
|
•
|
development drilling potential;
|
•
|
cash flow from operations or results of operations;
|
•
|
acquisitions or divestitures;
|
•
|
seasonality of our business; and
|
•
|
crude oil, natural gas and NGL prices and demand.
|
•
|
availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices and the availability and cost of capital;
|
•
|
inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
|
•
|
the strength and financial resources of our competitors;
|
•
|
development of alternative energy sources;
|
•
|
the impact of operational and development hazards;
|
•
|
costs of, changes in, or the results of laws, government regulations (including climate change regulation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;
|
•
|
changes in maintenance and construction costs;
|
•
|
changes in the current geopolitical situation;
|
•
|
our exposure to the credit risk of our customers;
|
•
|
risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
|
•
|
risks associated with future weather conditions;
|
•
|
acts of terrorism; and
|
•
|
other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business.”
|
•
|
increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, supplies, skilled labor, capital or transportation;
|
•
|
equipment failures or accidents;
|
•
|
adverse weather conditions, such as floods or blizzards;
|
•
|
title and lease related problems;
|
•
|
limitations in the market for oil and natural gas;
|
•
|
unexpected drilling conditions or problems;
|
•
|
pressure or irregularities in geological formations;
|
•
|
regulations and regulatory approvals;
|
•
|
changes or anticipated changes in energy prices; or
|
•
|
compliance with environmental and other governmental requirements.
|
•
|
actual prices we receive for oil and natural gas;
|
•
|
actual cost of development and production expenditures;
|
•
|
the amount and timing of actual production; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
weather conditions;
|
•
|
the level of consumer demand;
|
•
|
the overall economic environment;
|
•
|
worldwide and domestic supplies of and demand for oil, natural gas and NGLs;
|
•
|
turmoil in the Middle East and other producing regions;
|
•
|
the activities of the Organization of Petroleum Exporting Countries;
|
•
|
terrorist attacks on production or transportation assets;
|
•
|
variations in local market conditions (basis differential);
|
•
|
the price and availability of other types of fuels;
|
•
|
the availability of pipeline capacity;
|
•
|
supply disruptions, including plant outages and transportation disruptions;
|
•
|
the price and quantity of foreign imports of oil and natural gas;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
volatility in the oil and natural gas markets;
|
•
|
the credit of participants in the markets where products are bought and sold; and
|
•
|
the adoption of regulations or legislation relating to climate change.
|
•
|
hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;
|
•
|
aging infrastructure and mechanical problems;
|
•
|
damages to pipelines, pipeline blockages or other pipeline interruptions;
|
•
|
uncontrolled releases of oil, natural gas (including sour gas), NGLs, brine or industrial chemicals;
|
•
|
operator error;
|
•
|
pollution and environmental risks;
|
•
|
fires, explosions and blowouts;
|
•
|
risks related to truck and rail loading and unloading; and
|
•
|
terrorist attacks or threatened attacks on our facilities or those of other energy companies.
|
•
|
make it more difficult for us to satisfy our obligations with respect to our revolving credit facility;
|
•
|
impair our ability to obtain additional financing, if necessary, for working capital, letters of credit or other forms of guarantees, capital expenditures, acquisitions or other purposes or make such financing unavailable on favorable terms;
|
•
|
require us to dedicate a substantial portion of our cash flow from operations to make payments on our debt, thereby reducing funds available for operations, capital expenditures, future business opportunities and other purposes;
|
•
|
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
|
•
|
reduce our ability to make acquisitions or expand our business;
|
•
|
limit our ability to borrow additional funds;
|
•
|
limit our ability to sell assets to raise funds if needed for working capital, capital expenditures, acquisitions or other purposes;
|
•
|
make it difficult for us to pay dividends on shares of our common stock;
|
•
|
increase our vulnerability to adverse economic and industry conditions, including increases in interest rates; and
|
•
|
place us at a competitive disadvantage compared to competitors who might have relatively less debt.
|
•
|
changes in oil and natural gas prices, including in different geographic locations;
|
•
|
demand for oil and natural gas;
|
•
|
the success of our drilling program;
|
•
|
changes in our drilling schedule;
|
•
|
adjustments to our reserve estimates and differences between actual and estimated production, revenue and expenditures;
|
•
|
competition from other oil and gas companies;
|
•
|
costs and liabilities relating to governmental laws and regulations and environmental risks;
|
•
|
general market, political and economic conditions;
|
•
|
our failure to meet financial analysts’ performance or financing expectations;
|
•
|
changes in recommendations by financial analysts; and
|
•
|
changes in market valuations of other companies in our industry.
|
•
|
Clean Air Act (“CAA”) and analogous state laws, which impose obligations related to air emissions;
|
•
|
Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;
|
•
|
Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
|
•
|
Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;
|
•
|
National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;
|
•
|
Safe Drinking Water Act (“SDWA”), which restricts the disposal, treatment or release of water produced or used during oil and gas development;
|
•
|
Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and
|
•
|
Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulation of above ground storage tanks and sets forth liability for spills by responsible parties.
|
•
|
some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;
|
•
|
we may assume liabilities that were not disclosed to us or that exceed our estimates;
|
•
|
properties we acquire may be subject to burdens on title that we were not aware of at the time of acquisition or that interfere with our ability to hold the property for production;
|
•
|
we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
|
•
|
acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
|
•
|
we may issue additional equity or debt securities related to future acquisitions.
|
•
|
restrictions on business combinations for a three-year period with a stockholder who becomes the beneficial owner of more than 15 percent of our common stock;
|
•
|
restrictions on the ability of our stockholders to remove directors; and
|
•
|
supermajority voting requirements for stockholders to amend our organizational documents.
|
Item 1B.
|
Unresolved Staff Comments
|
Item 2.
|
Properties
|
Item 3.
|
Legal Proceedings
|
Item 4.
|
Mine Safety Disclosures
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
As of December 31,
|
||||||||||||||||||||||
Total Return Analysis data:
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
||||||||||||
WPX
|
$
|
100.00
|
|
|
$
|
81.89
|
|
|
$
|
112.16
|
|
|
$
|
64.01
|
|
|
$
|
31.59
|
|
|
$
|
80.19
|
|
MID
|
$
|
100.00
|
|
|
$
|
116.07
|
|
|
$
|
152.71
|
|
|
$
|
165.21
|
|
|
$
|
159.08
|
|
|
$
|
188.88
|
|
S&P O&G
|
$
|
100.00
|
|
|
$
|
103.13
|
|
|
$
|
131.07
|
|
|
$
|
91.64
|
|
|
$
|
57.99
|
|
|
$
|
79.51
|
|
Item 6.
|
Selected Financial Data
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Statement of operations data:
|
(Millions, except per share amounts)
|
||||||||||||||||||
Product revenues
|
$
|
722
|
|
|
$
|
655
|
|
|
$
|
971
|
|
|
$
|
744
|
|
|
$
|
1,044
|
|
Net gain (loss) on derivatives not designated as hedges
|
$
|
(207
|
)
|
|
$
|
418
|
|
|
$
|
434
|
|
|
$
|
(124
|
)
|
|
$
|
78
|
|
Gas management revenue
|
$
|
177
|
|
|
$
|
286
|
|
|
$
|
1,110
|
|
|
$
|
882
|
|
|
$
|
856
|
|
Total revenues
|
$
|
693
|
|
|
$
|
1,366
|
|
|
$
|
2,523
|
|
|
$
|
1,505
|
|
|
$
|
1,981
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations(a)
|
$
|
(612
|
)
|
|
$
|
(4
|
)
|
|
$
|
256
|
|
|
$
|
(1,005
|
)
|
|
$
|
(2
|
)
|
Income (loss) from discontinued operations(b)
|
11
|
|
|
(1,722
|
)
|
|
(85
|
)
|
|
(186
|
)
|
|
(209
|
)
|
|||||
Net income (loss)
|
$
|
(601
|
)
|
|
$
|
(1,726
|
)
|
|
$
|
171
|
|
|
$
|
(1,191
|
)
|
|
$
|
(211
|
)
|
Less: Net income attributable to noncontrolling interests
|
—
|
|
|
1
|
|
|
7
|
|
|
(6
|
)
|
|
12
|
|
|||||
Net income (loss) attributable to WPX Energy, Inc.
|
$
|
(601
|
)
|
|
$
|
(1,727
|
)
|
|
$
|
164
|
|
|
$
|
(1,185
|
)
|
|
$
|
(223
|
)
|
Less: Dividends on preferred stock
|
18
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Less: Loss on induced conversion of preferred stock
|
22
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss) attributable to WPX Energy, Inc. common stockholders
|
$
|
(641
|
)
|
|
$
|
(1,736
|
)
|
|
$
|
164
|
|
|
$
|
(1,185
|
)
|
|
$
|
(223
|
)
|
Amounts attributable to WPX Energy, Inc.:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(652
|
)
|
|
$
|
(13
|
)
|
|
$
|
256
|
|
|
$
|
(993
|
)
|
|
$
|
(2
|
)
|
Income (loss) from discontinued operations
|
$
|
11
|
|
|
$
|
(1,723
|
)
|
|
$
|
(92
|
)
|
|
$
|
(192
|
)
|
|
$
|
(221
|
)
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.26
|
|
|
$
|
(4.95
|
)
|
|
$
|
(0.01
|
)
|
Income (loss) from discontinued operations
|
$
|
0.03
|
|
|
$
|
(7.36
|
)
|
|
$
|
(0.45
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(1.11
|
)
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.24
|
|
|
$
|
(4.95
|
)
|
|
$
|
(0.01
|
)
|
Income (loss) from discontinued operations
|
$
|
0.03
|
|
|
$
|
(7.36
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(1.11
|
)
|
|
As of December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Balance sheet data:
|
(Millions)
|
||||||||||||||||||
Total assets
|
$
|
7,264
|
|
|
$
|
8,393
|
|
|
$
|
8,896
|
|
|
$
|
8,508
|
|
|
$
|
9,536
|
|
Long-term debt
|
$
|
2,575
|
|
|
$
|
3,189
|
|
|
$
|
2,260
|
|
|
$
|
1,895
|
|
|
$
|
1,483
|
|
Total stockholder’s equity
|
$
|
3,466
|
|
|
$
|
3,535
|
|
|
$
|
4,319
|
|
|
$
|
4,109
|
|
|
$
|
5,268
|
|
Total equity, including noncontrolling
interests
|
$
|
3,466
|
|
|
$
|
3,535
|
|
|
$
|
4,428
|
|
|
$
|
4,210
|
|
|
$
|
5,371
|
|
(a)
|
Income (loss) from continuing operations includes significant pre-tax items comprised of the following:
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(Millions)
|
||||||||||||||||||
Impairment of producing properties and costs of acquired unproved reserves
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
772
|
|
|
$
|
48
|
|
Impairment of unproved leasehold property
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
41
|
|
|
$
|
317
|
|
|
$
|
—
|
|
Impairment of equity method investment
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20
|
|
|
$
|
—
|
|
Impairment of exploratory area well costs and dry hole costs
|
$
|
—
|
|
|
$
|
24
|
|
|
$
|
21
|
|
|
$
|
3
|
|
|
$
|
1
|
|
Net (gain) loss on sales of assets and divestment of transportation contracts
|
$
|
22
|
|
|
$
|
(349
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(b)
|
Income (loss) from discontinued operations includes the results of holdings in the Piceance Basin, holdings in the Powder River Basin, holdings in the Barnett Shale and Arkoma Basin and Apco Oil and Gas International Inc. Significant components included in income (loss) from discontinued operations are comprised of the following:
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(Millions)
|
||||||||||||||||||
Piceance pre-tax impairments, including impairment of producing properties, costs of acquired unproved reserves and exploratory area well costs
|
$
|
—
|
|
|
$
|
2,334
|
|
|
$
|
72
|
|
|
$
|
88
|
|
|
$
|
75
|
|
Powder River pre-tax impairments
|
$
|
—
|
|
|
$
|
16
|
|
|
$
|
45
|
|
|
$
|
192
|
|
|
$
|
102
|
|
Net pre-tax gain on divestments
|
$
|
(51
|
)
|
|
$
|
(26
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(38
|
)
|
Powder River gain on sale of deep rights leasehold
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(36
|
)
|
|
$
|
—
|
|
Loss on sale of working interests in the Piceance Basin
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
196
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Production Sales Volume Data(a):
|
|
|
|
|
|
||||||
Oil (MBbls)
|
15,178
|
|
|
12,479
|
|
|
8,568
|
|
|||
Natural gas (MMcf)
|
72,842
|
|
|
66,187
|
|
|
74,533
|
|
|||
NGLs (MBbls)
|
3,645
|
|
|
2,412
|
|
|
898
|
|
|||
Combined equivalent volumes (Mboe)
|
30,963
|
|
|
25,922
|
|
|
21,888
|
|
|||
Production Sales Volume Per Day(a):
|
|
|
|
|
|
||||||
Oil (MBbls/d)
|
41.5
|
|
|
34.2
|
|
|
23.5
|
|
|||
Natural Gas (MMcf/d)
|
199
|
|
|
181
|
|
|
204
|
|
|||
NGL (MBbls/d)
|
10.0
|
|
|
6.6
|
|
|
2.5
|
|
|||
Combined equivalent volumes (Mboe/d)
|
84.6
|
|
|
71.0
|
|
|
60.0
|
|
|||
Financial Data (millions):
|
|
|
|
|
|
||||||
Total product revenues
|
$
|
722
|
|
|
$
|
655
|
|
|
$
|
971
|
|
Total revenues
|
$
|
693
|
|
|
$
|
1,366
|
|
|
$
|
2,523
|
|
Operating income (loss)
|
$
|
(731
|
)
|
|
$
|
274
|
|
|
$
|
526
|
|
Cash capital expenditures(b)
|
$
|
(578
|
)
|
|
$
|
(1,124
|
)
|
|
$
|
(1,807
|
)
|
Capital expenditure activity(c)
|
$
|
(584
|
)
|
|
$
|
(865
|
)
|
|
$
|
(1,934
|
)
|
(a)
|
Excludes production from our discontinued operations.
|
(b)
|
Includes cash capital expenditures related to discontinued operations of $35 million, $266 million and $597 million for the years ended December 31, 2016, 2015 and 2014, respectively, and excludes capital expenditures related to acquisitions.
|
(c)
|
Includes capital expenditures related to discontinued operations of $27 million, $184 million and $629 million for the years ended December 31, 2016, 2015 and 2014, respectively, and excludes capital expenditures related to acquisitions.
|
•
|
$625 million unfavorable change in net gain (loss) on derivatives from a gain of $418 million to a loss of $207 million. Increases in forward prices during 2016 drove the 2016 loss;
|
•
|
$56 million unfavorable change in net gas management margin;
|
•
|
$95 million higher depreciation expense; and
|
•
|
the absence of $349 million of gain on sale of assets and divestment of transportation contracts and impairment of producing properties in 2015 compared to $22 million net loss for 2016 (see Note 5 of Notes to Consolidated Financial Statements);
|
•
|
$67 million increase in product revenues;
|
•
|
$43 million decrease in exploration expense;
|
•
|
the absence in 2016 of a $22 million charge associated with a contract termination included in 2015 expenses;
|
•
|
the absence in 2016 of a $23 million charge included in 2015 expenses associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements); and
|
•
|
the absence in 2016 of $23 million of acquisition costs included in 2015 expenses.
|
•
|
$316 million lower production revenues,
|
•
|
$165 million higher depreciation, depletion and amortization expense,
|
•
|
$106 million lower net gas management margin,
|
•
|
$22 million charge associated with a contract termination in the first quarter of 2015,
|
•
|
$23 million charge associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements); and
|
•
|
$23 million of acquisition costs in 2015;
|
•
|
$349 million net gain on sales of assets in 2015 (see Note
5
of Notes to Consolidated Financial Statements) and
|
•
|
$45 million in total from lower operating expenses, including lease and facility operating, gathering, processing and transportation, operating taxes and general and administrative expenses for 2015 compared to 2014.
|
•
|
continuing to grow our oil production and reserves through the development of our positions in the Delaware Basin, Williston Basin and Gallup Sandstone in the San Juan Basin;
|
•
|
continuing to pursue cost improvements and efficiency gains;
|
•
|
employing new technology and operating methods;
|
•
|
continuing to invest in projects to assess resources and add new development opportunities to our portfolio;
|
•
|
retaining the flexibility to make adjustments to our planned levels and allocation of capital investment expenditures in response to changes in economic conditions or business opportunities; and
|
•
|
continuing to maintain an active economic hedging program around our commodity price risks.
|
•
|
lower than anticipated energy commodity prices;
|
•
|
lower than expected results from acquisitions;
|
•
|
higher capital costs of developing our properties, including the impact of inflation;
|
•
|
lower than expected levels of cash flow from operations;
|
•
|
counterparty credit and performance risk;
|
•
|
general economic, financial markets or industry downturn;
|
•
|
unavailability of capital either under our revolver or access to capital markets;
|
•
|
changes in the political and regulatory environments;
|
•
|
increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment supplies, skilled labor or transportation; and
|
•
|
decreased drilling success.
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2016
|
|
2015
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
551
|
|
|
$
|
494
|
|
|
$
|
57
|
|
|
12
|
%
|
Natural gas sales
|
125
|
|
|
138
|
|
|
(13
|
)
|
|
(9
|
)%
|
|||
Natural gas liquid sales
|
46
|
|
|
23
|
|
|
23
|
|
|
100
|
%
|
|||
Total product revenues
|
722
|
|
|
655
|
|
|
67
|
|
|
10
|
%
|
|||
Net gain (loss) on derivatives
|
(207
|
)
|
|
418
|
|
|
(625
|
)
|
|
NM
|
|
|||
Gas management
|
177
|
|
|
286
|
|
|
(109
|
)
|
|
(38
|
)%
|
|||
Other
|
1
|
|
|
7
|
|
|
(6
|
)
|
|
(86
|
)%
|
|||
Total revenues
|
$
|
693
|
|
|
$
|
1,366
|
|
|
$
|
(673
|
)
|
|
(49
|
)%
|
•
|
$57 million
increase
in oil sales reflects $107 million related to higher production sales volumes partially offset by a $50 million related to lower sales prices for 2016 compared to 2015. The increase in production sales volumes relates to our Delaware Basin which was acquired on August 17, 2015. The Delaware Basin volumes were 13.0 Mbbls per day for 2016 compared to 3.5 Mbbls per day for 2015. Delaware Basin volumes from the acquisition date to December 31, 2015 were 9.2 Mbbls per day. The following table reflects oil and condensate production prices and volumes for 2016 and 2015.
|
|
Years ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
|
||||||
Oil sales (per barrel)
|
$
|
36.31
|
|
|
$
|
39.61
|
|
Impact of net cash received related to settlement of
derivatives (per barrel)(a)
|
12.50
|
|
|
31.21
|
|
||
Oil net price including all derivative settlements (per barrel)
|
$
|
48.81
|
|
|
$
|
70.82
|
|
|
|
|
|
||||
Oil production sales volumes (Mbbls)
|
15,178
|
|
|
12,479
|
|
||
Per day oil production sales volumes (Mbbls/d)
|
41.5
|
|
|
34.2
|
|
•
|
$13 million
decrease
in natural gas sales reflects $27 million related to lower sales prices offset by a $14 million increase related to higher production sales volumes for 2016 compared to 2015. The increase in our production sales volumes is due to our Delaware Basin which was acquired on August 17, 2015. The following table reflects natural gas production prices and volumes for 2016 and 2015.
|
|
Years ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
1.72
|
|
|
$
|
2.08
|
|
Impact of net cash received related to settlement of derivatives (per Mcf)(a)
|
1.53
|
|
|
3.93
|
|
||
Natural gas net price including all derivative settlements (per Mcf)
|
$
|
3.25
|
|
|
$
|
6.01
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
72,842
|
|
|
66,187
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
199
|
|
|
181
|
|
•
|
$23 million
increase
in natural gas liquids sales is due to $12 million related to higher production sales volumes and $11 million related to higher NGL sales prices for 2016 compared to 2015. The following table reflects NGL production prices and volumes for 2016 and 2015.
|
|
Years ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
12.48
|
|
|
$
|
9.39
|
|
|
|
|
|
||||
NGL production sales volumes (Mbbls)
|
3,645
|
|
|
2,412
|
|
||
Per day NGL production sales volumes (Mbbls/d)
|
10.0
|
|
|
6.6
|
|
•
|
$625 million
unfavorable change in net gain (loss) on derivatives primarily reflects an unfavorable change from a gain of $418 million in 2015 to a loss of $207 million in 2016. Settlements from our derivatives totaled $302 million for 2016 and net settlements were $617 million for 2015.
|
•
|
$109 million
decrease
in gas management revenues primarily due to lower average prices on physical natural gas sales as well as lower natural gas and crude sales volumes. The decrease in volumes primarily resulted from reduced activity following the sale of a package of marketing contracts in the second quarter of 2015 and release of certain related firm transportation capacity in the first and second quarters of 2015 (see Note
5
of Notes to Consolidated Financial Statements). The decrease in volumes was partially offset by the sale of production
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per MBoe Expense
|
|||||||||||
|
2016
|
|
2015
|
|
|
2016
|
|
2015
|
||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Depreciation, depletion and amortization
|
$
|
623
|
|
|
$
|
528
|
|
|
$
|
(95
|
)
|
|
(18
|
)%
|
|
$20.11
|
|
$20.39
|
Lease and facility operating
|
163
|
|
|
145
|
|
|
(18
|
)
|
|
(12
|
)%
|
|
$5.26
|
|
$5.59
|
|||
Gathering, processing and transportation
|
76
|
|
|
64
|
|
|
(12
|
)
|
|
(19
|
)%
|
|
$2.45
|
|
$2.48
|
|||
Taxes other than income
|
60
|
|
|
62
|
|
|
2
|
|
|
3
|
%
|
|
$1.94
|
|
$2.38
|
|||
Exploration
|
42
|
|
|
85
|
|
|
43
|
|
|
51
|
%
|
|
|
|
|
|||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
General and administrative expenses
|
181
|
|
|
179
|
|
|
(2
|
)
|
|
(1
|
)%
|
|
$5.84
|
|
$6.95
|
|||
Equity based compensation
|
33
|
|
|
31
|
|
|
(2
|
)
|
|
(6
|
)%
|
|
$1.06
|
|
$1.17
|
|||
Total general and administrative
|
214
|
|
|
210
|
|
|
(4
|
)
|
|
(2
|
)%
|
|
$6.90
|
|
$8.12
|
|||
Gas management, including charges for unutilized pipeline capacity
|
208
|
|
|
261
|
|
|
53
|
|
|
20
|
%
|
|
|
|
|
|||
Net (gain) loss on sales of assets and divestment of transportation contracts and impairment of producing properties (Note 5)
|
22
|
|
|
(349
|
)
|
|
(371
|
)
|
|
NM
|
|
|
|
|
|
|||
Acquisition costs (Note 2)
|
—
|
|
|
23
|
|
|
23
|
|
|
100
|
%
|
|
|
|
|
|||
Other—net
|
16
|
|
|
63
|
|
|
47
|
|
|
75
|
%
|
|
|
|
|
|||
Total costs and expenses
|
$
|
1,424
|
|
|
$
|
1,092
|
|
|
$
|
(332
|
)
|
|
(30
|
)%
|
|
|
|
|
Operating income (loss)
|
$
|
(731
|
)
|
|
$
|
274
|
|
|
$
|
(1,005
|
)
|
|
NM
|
|
|
|
|
|
•
|
$95 million
increase
in depreciation, depletion and amortization is primarily due to higher volumes in our Delaware Basin, which was acquired on August 17, 2015, partially offset by a lower rate per Boe and lower volumes in the Williston Basin in 2016.
|
•
|
$18 million
increase
in lease and facility operating expenses primarily related to our Delaware Basin which was acquired on August 17, 2015 partially offset by reduced costs across our basins. Lease and facility operating expenses for 2016 and 2015 included $67 million and $25 million, respectively, from our Delaware Basin.
|
•
|
$12 million
increase
in gathering, processing and transportation expenses is primarily due to the sale of our San Juan Basin and Williston Basin gathering systems.
|
•
|
$43 million
decrease
in exploration expenses is primarily due to 2015 dry hole costs, impairments of exploratory area well costs and unproved leasehold property impairment, amortization and expiration related to a non-core exploratory play where we no longer intend to continue exploration activities.
|
•
|
General and administrative expenses for both 2016 and 2015 include $15 million for severance and relocation costs associated with workforce reductions and office consolidations. We will continually challenge our levels of general and administrative costs, however, we believe our organizational size is conducive for future growth. Excluding the severance and relocation costs in 2016 and 2015, general and administrative expenses would have averaged $6.43 per Boe for 2016 and $7.52 per Boe for 2015.
|
•
|
$53 million
decrease
in gas management expenses is primarily due to lower purchase volumes, as well as lower average prices on physical natural gas cost of sales for 2016 compared to 2015. The decrease in volumes primarily resulted from reduced activity following the sale of a package of marketing contracts in the second quarter of 2015 and release of certain related firm transportation capacity in the first and second quarters of 2015 (see Note
5
of Notes to Consolidated Financial Statements).The decrease in volumes is partially offset by the sale of production volumes pursuant to our purchase agreement with the buyer of the Piceance Basin operations. This
|
•
|
$22 million net loss on sales of assets and divestment of transportation contracts in 2016 primarily related to a $238 million loss on the divestment of transportation obligations offset by $217 million of gains recognized related to the sale of the San Juan Basin gathering system. The $349 million net gain in 2015 primarily related to a $209 million gain on the sale of a package of marketing contracts and release of certain related firm transportation capacity in the second quarter of 2015, $70 million from the sale of a North Dakota gathering system in the fourth quarter of 2015 and a net gain of $69 million on the sale of a portion of our Appalachian Basin assets in the first quarter of 2015. (See Note
5
of Notes to Consolidated Financial Statements for further discussion of these sales).
|
•
|
$23 million of acquisition costs in 2015 related to the acquisition of RKI (see Note
2
of Notes to Consolidated Financial Statements).
|
•
|
$47 million
decrease
in other expenses primarily relates to a $22 million charge associated with a contract termination in the first quarter of 2015 and a $23 million charge associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements).
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2016
|
|
2015
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income (loss)
|
$
|
(731
|
)
|
|
$
|
274
|
|
|
$
|
(1,005
|
)
|
|
NM
|
|
Interest expense
|
(207
|
)
|
|
(187
|
)
|
|
(20
|
)
|
|
(11
|
)%
|
|||
Loss on extinguishment of debt
|
(1
|
)
|
|
(65
|
)
|
|
64
|
|
|
98
|
%
|
|||
Investment income and other
|
2
|
|
|
(2
|
)
|
|
4
|
|
|
NM
|
|
|||
Income (loss) from continuing operations before income taxes
|
(937
|
)
|
|
20
|
|
|
(957
|
)
|
|
NM
|
|
|||
Provision (benefit) for income taxes
|
(325
|
)
|
|
24
|
|
|
349
|
|
|
NM
|
|
|||
Income (loss) from continuing operations
|
(612
|
)
|
|
(4
|
)
|
|
(608
|
)
|
|
NM
|
|
|||
Income (loss) from discontinued operations
|
11
|
|
|
(1,722
|
)
|
|
1,733
|
|
|
NM
|
|
|||
Net income (loss)
|
(601
|
)
|
|
(1,726
|
)
|
|
1,125
|
|
|
65
|
%
|
|||
Less: Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
(100
|
)%
|
|||
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
$
|
(601
|
)
|
|
$
|
(1,727
|
)
|
|
$
|
1,126
|
|
|
65
|
%
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2015
|
|
2014
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|||||||
Oil sales
|
$
|
494
|
|
|
$
|
669
|
|
|
$
|
(175
|
)
|
|
(26
|
)%
|
Natural gas sales
|
138
|
|
|
282
|
|
|
(144
|
)
|
|
(51
|
)%
|
|||
Natural gas liquid sales
|
23
|
|
|
20
|
|
|
3
|
|
|
15
|
%
|
|||
Total product revenues
|
655
|
|
|
971
|
|
|
(316
|
)
|
|
(33
|
)%
|
|||
Net gain (loss) on derivatives
|
418
|
|
|
434
|
|
|
(16
|
)
|
|
(4
|
)%
|
|||
Gas management
|
286
|
|
|
1,110
|
|
|
(824
|
)
|
|
(74
|
)%
|
|||
Other
|
7
|
|
|
8
|
|
|
(1
|
)
|
|
(13
|
)%
|
|||
Total revenues
|
$
|
1,366
|
|
|
$
|
2,523
|
|
|
$
|
(1,157
|
)
|
|
(46
|
)%
|
•
|
$175 million decrease in oil sales reflects $480 million related to lower sales prices partially offset by a $305 million increase related to increased sales volumes for 2015 compared to 2014. The increase in production sales volumes primarily relates to Delaware Basin volumes since the Acquisition and continued development drilling in the Williston Basin and Gallup Sandstone in the San Juan Basin. In the Williston and San Juan Basins, volumes were 21.8 Mbbls per day and 8.9 Mbbls per day, respectively for 2015 compared to 19.5 Mbbls per day and 3.9 Mbbls per day, respectively, for 2014. Volumes in the Delaware Basin since the Acquisition date were 9.2 Mbbls per day. The following table reflects oil and condensate production prices and volumes for 2015 and 2014.
|
|
Years ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
|
||||||
Oil sales (per barrel)
|
$
|
39.61
|
|
|
$
|
78.09
|
|
Impact of net cash received (paid) related to settlement of
derivatives (per barrel)(a)
|
31.21
|
|
|
2.17
|
|
||
Oil net price including all derivative settlements (per barrel)
|
$
|
70.82
|
|
|
$
|
80.26
|
|
|
|
|
|
||||
Oil production sales volumes (Mbbls)
|
12,479
|
|
|
8,568
|
|
||
Per day oil production sales volumes (Mbbls/d)
|
34.2
|
|
|
23.5
|
|
•
|
$144 million decrease in natural gas sales is primarily due to $113 million related to lower sales prices and $31 million related to lower production sales volumes for 2015 compared to 2014. The decrease in our production sales volumes is due in part to the sale of Appalachian Basin assets in the first quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements) partially offset by an increase in production sales volumes in the San Juan Basin in 2015 and the Delaware Basin since the Acquisition date. The following table reflects natural gas production prices and volumes for 2015 and 2014.
|
|
Years ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
|
||||||
Natural gas sales (per Mcf)
|
$
|
2.08
|
|
|
$
|
3.78
|
|
Impact of net cash received (paid) related to settlement of derivatives (per Mcf)(a)
|
3.93
|
|
|
(0.37
|
)
|
||
Natural gas net price including all derivative settlements (per Mcf)
|
$
|
6.01
|
|
|
$
|
3.41
|
|
|
|
|
|
||||
Natural gas production sales volumes (MMcf)
|
66,187
|
|
|
74,533
|
|
||
Per day natural gas production sales volumes (MMcf/d)
|
181
|
|
|
204
|
|
•
|
$3 million increase in natural gas liquids sales is primarily due to $35 million related to higher production sales volumes substantially offset by $32 million related to lower NGL sales prices for 2015 compared to 2014. The following table reflects NGL production prices and volumes for 2015 and 2014.
|
|
Years ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
|
||||||
NGL sales (per barrel)
|
$
|
9.39
|
|
|
$
|
22.94
|
|
Impact of net cash received related to settlement of
derivatives (per barrel)(a)
|
—
|
|
|
7.81
|
|
||
NGL net price including all derivative settlements (per barrel)
|
$
|
9.39
|
|
|
$
|
30.75
|
|
|
|
|
|
||||
NGL production sales volumes (Mbbls)
|
2,412
|
|
|
898
|
|
||
Per day NGL production sales volumes (Mbbls/d)
|
6.6
|
|
|
2.5
|
|
•
|
$16 million unfavorable change in net gain (loss) on derivatives not designated as hedges primarily reflects a $77 million unfavorable change on derivatives related to our production partially offset by a $61 million favorable change on derivatives related to gas management. Settlements of our derivatives in 2015 totaled $650 million. We have a net derivative asset of $426 million as of December 31, 2015 of which approximately $363 million relates to 2016 production.
|
•
|
$824 million decrease in gas management revenues primarily due to lower average prices on physical natural gas sales as well as lower natural gas sales volumes. The decrease in volumes primarily relates to the sale of a package of marketing contracts in the second quarter of 2015 and release of certain related firm transportation capacity in the first and second quarters of 2015 (see Note
5
of Notes to Consolidated Financial Statements). The decrease in the sales price was greater than the decrease in the purchase price as reflected in the $718 million decrease in related gas management costs and expenses, discussed below.
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|
Per MBoe Expense
|
|||||||||||||||
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
||||||||||||||
|
(Millions)
|
|
|
|
|
|
|
|
|
|||||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Depreciation, depletion and amortization
|
$
|
528
|
|
|
$
|
363
|
|
|
$
|
(165
|
)
|
|
(45
|
)%
|
|
$
|
20.39
|
|
|
$
|
16.58
|
|
Lease and facility operating
|
145
|
|
|
143
|
|
|
(2
|
)
|
|
(1
|
)%
|
|
$
|
5.59
|
|
|
$
|
6.51
|
|
|||
Gathering, processing and transportation
|
64
|
|
|
71
|
|
|
7
|
|
|
10
|
%
|
|
$
|
2.48
|
|
|
$
|
3.25
|
|
|||
Taxes other than income
|
62
|
|
|
88
|
|
|
26
|
|
|
30
|
%
|
|
$
|
2.38
|
|
|
$
|
4.03
|
|
|||
Exploration
|
85
|
|
|
101
|
|
|
16
|
|
|
16
|
%
|
|
|
|
|
|||||||
General and administrative:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
General and administrative expenses
|
179
|
|
|
194
|
|
|
15
|
|
|
8
|
%
|
|
$
|
6.95
|
|
|
$
|
8.87
|
|
|||
Equity based compensation
|
31
|
|
|
30
|
|
|
(1
|
)
|
|
(3
|
)%
|
|
$
|
1.17
|
|
|
$
|
1.37
|
|
|||
Total general and administrative
|
210
|
|
|
224
|
|
|
14
|
|
|
6
|
%
|
|
$
|
8.12
|
|
|
$
|
10.24
|
|
|||
Gas management, including charges for unutilized pipeline capacity
|
261
|
|
|
979
|
|
|
718
|
|
|
73
|
%
|
|
|
|
|
|||||||
Net (gain) loss on sales of assets and divestment of transportation contracts and impairment of producing properties (Note 5)
|
(349
|
)
|
|
15
|
|
|
364
|
|
|
NM
|
|
|
|
|
|
|||||||
Acquisition costs
|
23
|
|
|
—
|
|
|
(23
|
)
|
|
NM
|
|
|
|
|
|
|||||||
Other—net
|
63
|
|
|
13
|
|
|
(50
|
)
|
|
NM
|
|
|
|
|
|
|||||||
Total costs and expenses
|
$
|
1,092
|
|
|
$
|
1,997
|
|
|
$
|
905
|
|
|
45
|
%
|
|
|
|
|
||||
Operating income (loss)
|
$
|
274
|
|
|
$
|
526
|
|
|
$
|
(252
|
)
|
|
(48
|
)%
|
|
|
|
|
•
|
$165 million increase in depreciation, depletion and amortization expenses primarily due to a higher rate, higher oil production volumes and approximately $39 million related to the Delaware Basin. The higher rate is due in part to our adjustment of the proved reserves used for the calculation of depletion and amortization to reflect the impact of a decrease in the 12-month average price resulting in a $36 million addition to depreciation, depletion and amortization in 2015.
|
•
|
$2 million increase in lease and facility operating expenses primarily relates to higher oil production volumes and approximately $25 million related to the Delaware Basin since the Acquisition date substantially offset by lower natural gas volumes due to the sales of a portion of our Appalachian Basin assets in the first quarter of 2015, as well as cost reduction efforts across our basins.
|
•
|
$7 million decrease in gathering, processing and transportation expenses primarily relates to lower excess gathering capacity expense which was $8 million and $13 million in 2015 and 2014, respectively.
|
•
|
$26 million decrease in taxes other than income primarily relates to lower oil prices, partially offset by higher oil production volumes.
|
•
|
$16 million decrease in exploration expenses primarily relates to a decrease in unproved leasehold property impairments, amortization and expiration in 2015 compared to 2014 (see Note
5
of Notes to Consolidated Financial Statements).
|
•
|
$14 million decrease in general and administrative expenses is primarily due to reduced employee and related costs as a result of headcount reductions and the absence of $10 million of costs associated with an early exit program offered in 2014 partially offset by approximately $15 million of severance and relocation costs associated with the workforce reduction and office consolidation announced during the first quarter of 2015. Excluding the severance and relocation costs in 2015 and the costs of the early exit program in 2014, general and administrative expenses would have averaged $7.52 per Boe for 2015 and $9.79 per Boe for 2014.
|
•
|
$718 million decrease in gas management expenses, primarily due to lower average prices on physical natural gas cost of sales as well as lower commodity purchase volumes, as previously discussed. Additionally in 2014, we recognized a loss of approximately $14 million on the release of future storage capacity commitments and
|
•
|
$349 million net (gain) loss on sales of assets in 2015 primarily reflects $209 million from the sale of a package of marketing contracts and release of certain firm transportation capacity in the second quarter of 2015, $70 million from the sale of a North Dakota gathering system in the fourth quarter of 2015 and $69 million from the sale of a portion of our Appalachian Basin assets in the first quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements).
|
•
|
$23 million of acquisition costs in 2015 related to the Acquisition (see Note
2
of Notes to Consolidated Financial Statements).
|
•
|
$50 million increase in other expenses primarily relates to a $22 million charge associated with a contract termination in the first quarter of 2015 and a $23 million charge associated with gathering obligations in an area of the Appalachian Basin where we plugged and abandoned our remaining wells in the fourth quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements).
|
|
Years ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
|
Favorable (Unfavorable) % Change
|
|||||||||
|
2015
|
|
2014
|
|
||||||||||
|
(Millions)
|
|
|
|
|
|||||||||
Operating income (loss)
|
$
|
274
|
|
|
$
|
526
|
|
|
$
|
(252
|
)
|
|
(48
|
)%
|
Interest expense
|
(187
|
)
|
|
(123
|
)
|
|
(64
|
)
|
|
(52
|
)%
|
|||
Loss on extinguishment of debt
|
(65
|
)
|
|
—
|
|
|
(65
|
)
|
|
NM
|
|
|||
Investment income and other
|
(2
|
)
|
|
1
|
|
|
(3
|
)
|
|
NM
|
|
|||
Income (loss) from continuing operations before income taxes
|
20
|
|
|
404
|
|
|
(384
|
)
|
|
(95
|
)%
|
|||
Provision (benefit) for income taxes
|
24
|
|
|
148
|
|
|
124
|
|
|
84
|
%
|
|||
Income (loss) from continuing operations
|
(4
|
)
|
|
256
|
|
|
(260
|
)
|
|
NM
|
|
|||
Income (loss) from discontinued operations
|
(1,722
|
)
|
|
(85
|
)
|
|
(1,637
|
)
|
|
NM
|
|
|||
Net income (loss)
|
(1,726
|
)
|
|
171
|
|
|
(1,897
|
)
|
|
NM
|
|
|||
Less: Net income (loss) attributable to noncontrolling interests
|
1
|
|
|
7
|
|
|
(6
|
)
|
|
(86
|
)%
|
|||
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
$
|
(1,727
|
)
|
|
$
|
164
|
|
|
$
|
(1,891
|
)
|
|
NM
|
|
•
|
before considering the impact of the recently announced bolt-on acquisition, our planned capital expenditures are estimated to be approximately $835 million to $905 million in 2017;
|
•
|
the successful completion of the $775 million bolt-on acreage acquisition; and
|
•
|
we have hedged a portion of our of anticipated 2017 and 2018 oil and gas production as disclosed in Commodity Price Risk Management following this section.
|
•
|
lower than expected levels of cash flow from operations, primarily resulting from lower energy commodity prices or inflation on operating costs;
|
•
|
significantly lower than expected capital expenditures could result in the loss of undeveloped leasehold;
|
•
|
reduced access to our credit facility pursuant to our financial covenants; and
|
•
|
higher than expected development costs, including the impact of inflation.
|
Crude Oil
|
2017
|
|
2018
|
||||
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
|
Volume
(Bbls/d) |
|
Weighted Average
Price ($/Bbl) |
Fixed-price—WTI
|
39,554
|
|
$50.93
|
|
30,000
|
|
$54.61
|
Swaptions—WTI
|
1,764
|
|
$44.61
|
|
—
|
|
$—
|
Fixed Price Calls— WTI
|
4,500
|
|
$56.47
|
|
13,000
|
|
$58.89
|
Basis Swaps— Midland-Cushing
|
12,778
|
|
$(0.52)
|
|
13,000
|
|
$(0.94)
|
Natural Gas
|
2017
|
|
2018
|
||||
|
Volume
(BBtu/d)
|
|
Weighted Average
Price ($/MMBtu)
|
|
Volume
(BBtu/d)
|
|
Weighted Average
Price ($/MMBtu)
|
Fixed-price—Henry Hub
|
170
|
|
$3.02
|
|
155
|
|
$2.98
|
Swaptions—Henry Hub
|
—
|
|
$—
|
|
20
|
|
$3.33
|
Fixed Price Calls—Henry Hub
|
16
|
|
$4.50
|
|
16
|
|
$4.75
|
Basis swaps—San Juan
|
98
|
|
$(0.18)
|
|
50
|
|
$(0.34)
|
Basis swaps—Permian
|
73
|
|
$(0.20)
|
|
43
|
|
$(0.28)
|
Basis swaps—Waha
|
—
|
|
$—
|
|
63
|
|
$(0.16)
|
Standard and Poor’s
|
|
|
Corporate Credit Rating
|
|
B+
|
Senior Unsecured Debt Rating
|
|
B
|
Outlook
|
|
Stable
|
Moody’s Investors Service
|
|
|
LT Corporate Family Rating
|
|
B2
|
Senior Unsecured Debt Rating
|
|
B3
|
Outlook
|
|
Stable
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Net cash provided (used) by:
|
|
|
|
|
|
||||||
Operating activities
|
$
|
262
|
|
|
$
|
811
|
|
|
$
|
1,070
|
|
Investing activities
|
310
|
|
|
(1,316
|
)
|
|
(1,437
|
)
|
|||
Financing activities
|
(114
|
)
|
|
473
|
|
|
344
|
|
|||
Increase (decrease) in cash and cash equivalents
|
$
|
458
|
|
|
$
|
(32
|
)
|
|
$
|
(23
|
)
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(Millions)
|
||||||||||
Cash capital expenditures for drilling and completions:
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
431
|
|
|
$
|
730
|
|
|
$
|
873
|
|
Domestic discontinued operations
|
|
29
|
|
|
234
|
|
|
479
|
|
|||
Total
|
|
$
|
460
|
|
|
$
|
964
|
|
|
$
|
1,352
|
|
|
|
|
|
|
|
|
||||||
Capital expenditures incurred for drilling and completions:
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
450
|
|
|
$
|
563
|
|
|
$
|
957
|
|
Domestic discontinued operations
|
|
22
|
|
|
170
|
|
|
495
|
|
|||
Total
|
|
$
|
472
|
|
|
$
|
733
|
|
|
$
|
1,452
|
|
|
|
|
|
|
|
|
||||||
Land acquisitions(a)
|
|
$
|
85
|
|
|
$
|
59
|
|
|
$
|
297
|
|
Capital expenditures for international discontinued operations
|
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
85
|
|
(a)
|
Includes approximately $150 million related to the purchase of oil and natural gas properties in the San Juan Basin in 2014.
|
•
|
$862 million
for the sale of WPX Energy Rocky Mountain, LLC that held our Piceance Basin operations to Terra Energy Partners, LLC (see Note
3
of Notes to Consolidated Financial Statements); and
|
•
|
$280 million for the sale of our San Juan Basin gathering system to a portfolio company of ISQ Global Infrastructure Fund, a fund managed by I Squared Capital during the first quarter of 2016 (see Note
5
of Notes to Consolidated Financial Statements).
|
•
|
$291 million
after expenses but before
$17 million
of cash on hand at Apco as of the closing date, for the divestiture of our 69 percent controlling equity interest in Apco and additional Argentina-related assets to Pluspetrol (see Note
3
of Notes to Consolidated Financial Statements);
|
•
|
$271 million for the sale of a portion of our Appalachian Basin operations and release of certain firm transportation capacity to Southwestern Energy Company during the first quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements);
|
•
|
$182 million for the sale of a North Dakota gathering system that closed during the fourth quarter of 2015 (see Note
5
of Notes to Consolidated Financial Statements); and
|
•
|
$67 million for the sale of our Powder River Basin assets during fourth quarter of 2015 (see Note
3
of Notes to Consolidated Financial Statements).
|
•
|
Approximately $329 million for the sale of a portion of our working interests in certain Piceance Basin wells to Legacy during the second quarter of 2014 (see Note
3
of Notes to Consolidated Financial Statements).
|
•
|
On June 6, 2016, we completed an equity offering of 56.925 million shares of our common stock for net proceeds of approximately $538 million;
|
•
|
net repayments under the Credit Facility of $265 million;
|
•
|
$355 million repayment of our Senior Notes due 2017;
|
•
|
$18 million of preferred stock dividends; and
|
•
|
$10 million of cash paid as an inducement for the conversion of preferred stock to common stock.
|
•
|
Equity offerings of (a)
30 million
shares of our common stock for net proceeds of approximately $
292 million
and (b)
$350 million
of aggregate liquidation preference of
6.25%
series A mandatory convertible preferred stock for net proceeds of approximately
$339 million
(see Note
13
of Notes to Consolidated Financial Statements);
|
•
|
debt offering of (a)
$500 million
aggregate principal amount of
7.500%
senior unsecured notes due 2020 and (b)
$500 million
aggregate principal amount of
8.250%
senior unsecured notes due 2023 (see Note
8
of Notes to Consolidated Financial Statements);
|
•
|
payment of long term debt includes cash used to retire $600 million of outstanding debt on RKI’s revolving credit facility and $455 million for the satisfaction and discharge of RKI’s senior notes which includes a $55 million make-whole premium;
|
•
|
net payments under the Credit Facility of $15 million. In August 2015, we utilized borrowings under the Credit Facility for the Acquisition; and
|
•
|
$40 million in payments for debt issuance costs and acquisition bridge financing fees for the debt offerings and revolver amendments.
|
•
|
We issued
$500 million
of senior unsecured notes at an interest rate of
5.250%
. We used the proceeds from this offering to repay borrowings under our revolving credit facility and for related transaction fees and expenses (see Note
8
of Notes to Consolidated Financial Statements); and
|
•
|
net payments of $130 million on our Credit Facility.
|
|
2017
|
|
2018 –
2019
|
|
2020 –
2021
|
|
Thereafter
|
|
Total
|
||||||||||
|
(Millions)
|
||||||||||||||||||
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
2,100
|
|
|
$
|
2,601
|
|
Interest
|
171
|
|
|
342
|
|
|
305
|
|
|
194
|
|
|
1,012
|
|
|||||
Operating leases and associated service commitments:
|
|
|
|
|
|
|
|
|
|
||||||||||
Drilling rig commitments(a)
|
43
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|||||
Other
|
18
|
|
|
19
|
|
|
13
|
|
|
2
|
|
|
52
|
|
|||||
Transportation commitments(b)
|
38
|
|
|
59
|
|
|
23
|
|
|
1
|
|
|
121
|
|
|||||
Oil and gas activities(c)
|
169
|
|
|
199
|
|
|
166
|
|
|
247
|
|
|
781
|
|
|||||
Other
|
11
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|||||
Other long-term liabilities, including current portion:
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial derivatives(d)
|
125
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
155
|
|
|||||
Total obligations
|
$
|
576
|
|
|
$
|
669
|
|
|
$
|
1,007
|
|
|
$
|
2,544
|
|
|
$
|
4,796
|
|
(a)
|
Includes materials and services obligations associated with our drilling rig contracts.
|
(b)
|
Includes firm demand obligations of $107 million for which $91 million is recorded as a liability as of December 31, 2016. A liability was recorded in 2015 in conjunction with our exit from the Powder River Basin (see Note 3 of Notes to Consolidated Financial Statements). Excludes additional commitments totaling $17 million associated with projects for which the counterparty has not yet received satisfactory regulatory approvals.
|
(c)
|
Includes gathering, processing and other oil and gas related services commitments for which $56 million is recorded as a liability as of December 31, 2016. Liabilities were recorded in 2015 in conjunction with our exit from the Powder River Basin and associated with an abandoned area in the Appalachian Basin. Excluded are liabilities associated with asset retirement obligations totaling $107 million as of December 31, 2016. The ultimate settlement and timing of asset retirement obligations cannot be precisely determined in advance; however, we estimate that approximately 15 percent of this liability will be settled in the next five years.
|
(d)
|
Obligations for financial derivatives are based on market information as of
December 31, 2016
, and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.
|
•
|
an increase (decrease) in estimated proved oil, natural gas and NGL reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and
|
•
|
changes in oil, natural gas, and NGL reserves and estimated market prices both impact projected future cash flows from our properties. This, in turn, can impact our periodic impairment analyses.
|
Item 7A.
|
Quantitative and Qualitative Disclosures About Market Risk
|
Item 8.
|
Financial Statements and Supplementary Data
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
496
|
|
|
$
|
38
|
|
Accounts receivable, net of allowance of $3 million as of December 31, 2016 and $6 million as of December 31, 2015
|
168
|
|
|
300
|
|
||
Derivative assets
|
26
|
|
|
308
|
|
||
Inventories
|
36
|
|
|
46
|
|
||
Assets classified as held for sale
|
8
|
|
|
178
|
|
||
Other
|
20
|
|
|
23
|
|
||
Total current assets
|
754
|
|
|
893
|
|
||
Properties and equipment, net (successful efforts method of accounting)
|
6,474
|
|
|
6,522
|
|
||
Derivative assets
|
12
|
|
|
51
|
|
||
Assets classified as held for sale
|
—
|
|
|
894
|
|
||
Other noncurrent assets
|
24
|
|
|
33
|
|
||
Total assets
|
$
|
7,264
|
|
|
$
|
8,393
|
|
|
|
|
|
||||
Liabilities and Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
222
|
|
|
$
|
278
|
|
Accrued and other current liabilities
|
301
|
|
|
302
|
|
||
Liabilities associated with assets held for sale
|
2
|
|
|
140
|
|
||
Derivative liabilities
|
152
|
|
|
13
|
|
||
Total current liabilities
|
677
|
|
|
733
|
|
||
Deferred income taxes
|
251
|
|
|
465
|
|
||
Long-term debt, net
|
2,575
|
|
|
3,189
|
|
||
Derivative liabilities
|
63
|
|
|
2
|
|
||
Asset retirement obligations
|
100
|
|
|
99
|
|
||
Liabilities associated with assets held for sale
|
—
|
|
|
133
|
|
||
Other noncurrent liabilities
|
132
|
|
|
237
|
|
||
Contingent liabilities and commitments (Note 10)
|
|
|
|
||||
Equity:
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
||||
Preferred stock (100 million shares authorized at $0.01 par value; 4.8 million and 7 million shares outstanding at December 31, 2016 and 2015)
|
232
|
|
|
339
|
|
||
Common stock (2 billion shares authorized at $0.01 par value; 344.7 million and 275.4 million shares issued and outstanding at December 31, 2016 and 2015)
|
3
|
|
|
3
|
|
||
Additional paid-in-capital
|
6,803
|
|
|
6,164
|
|
||
Accumulated deficit
|
(3,572
|
)
|
|
(2,971
|
)
|
||
Total stockholders’ equity
|
3,466
|
|
|
3,535
|
|
||
Total liabilities and equity
|
$
|
7,264
|
|
|
$
|
8,393
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues:
|
(Millions, except per share amounts)
|
||||||||||
Product revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
551
|
|
|
$
|
494
|
|
|
$
|
669
|
|
Natural gas sales
|
125
|
|
|
138
|
|
|
282
|
|
|||
Natural gas liquid sales
|
46
|
|
|
23
|
|
|
20
|
|
|||
Total product revenues
|
722
|
|
|
655
|
|
|
971
|
|
|||
Net gain (loss) on derivatives
|
(207
|
)
|
|
418
|
|
|
434
|
|
|||
Gas management
|
177
|
|
|
286
|
|
|
1,110
|
|
|||
Other
|
1
|
|
|
7
|
|
|
8
|
|
|||
Total revenues
|
693
|
|
|
1,366
|
|
|
2,523
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
623
|
|
|
528
|
|
|
363
|
|
|||
Lease and facility operating
|
163
|
|
|
145
|
|
|
143
|
|
|||
Gathering, processing and transportation
|
76
|
|
|
64
|
|
|
71
|
|
|||
Taxes other than income
|
60
|
|
|
62
|
|
|
88
|
|
|||
Exploration
|
42
|
|
|
85
|
|
|
101
|
|
|||
General and administrative (including equity-based compensation of $33 million, $31 million and $30 million for the respective periods)
|
214
|
|
|
210
|
|
|
224
|
|
|||
Gas management, including charges for unutilized pipeline capacity (Note 5)
|
208
|
|
|
261
|
|
|
979
|
|
|||
Net (gain) loss on sales of assets, divestment of transportation contracts and impairment of producing properties (Note 5)
|
22
|
|
|
(349
|
)
|
|
15
|
|
|||
Acquisition costs (Note 2)
|
—
|
|
|
23
|
|
|
—
|
|
|||
Other—net
|
16
|
|
|
63
|
|
|
13
|
|
|||
Total costs and expenses
|
1,424
|
|
|
1,092
|
|
|
1,997
|
|
|||
Operating income (loss)
|
(731
|
)
|
|
274
|
|
|
526
|
|
|||
Interest expense
|
(207
|
)
|
|
(187
|
)
|
|
(123
|
)
|
|||
Loss on extinguishment of debt (Note 2)
|
(1
|
)
|
|
(65
|
)
|
|
—
|
|
|||
Investment income and other
|
2
|
|
|
(2
|
)
|
|
1
|
|
|||
Income (loss) from continuing operations before income taxes
|
(937
|
)
|
|
20
|
|
|
404
|
|
|||
Provision (benefit) for income taxes
|
(325
|
)
|
|
24
|
|
|
148
|
|
|||
Income (loss) from continuing operations
|
(612
|
)
|
|
(4
|
)
|
|
256
|
|
|||
Income (loss) from discontinued operations
|
11
|
|
|
(1,722
|
)
|
|
(85
|
)
|
|||
Net income (loss)
|
(601
|
)
|
|
(1,726
|
)
|
|
171
|
|
|||
Less: Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
1
|
|
|
7
|
|
|||
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
$
|
(601
|
)
|
|
$
|
(1,727
|
)
|
|
$
|
164
|
|
Less: Dividends on preferred stock
|
18
|
|
|
9
|
|
|
—
|
|
|||
Less: Loss on induced conversion of preferred stock
|
22
|
|
|
—
|
|
|
—
|
|
|||
Net income (loss) attributable to WPX Energy, Inc. common stockholders
|
$
|
(641
|
)
|
|
$
|
(1,736
|
)
|
|
$
|
164
|
|
|
|
|
|
|
|
||||||
(continued on next page)
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions, except per share amounts)
|
||||||||||
Amounts attributable to WPX Energy, Inc. common stockholders:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(652
|
)
|
|
$
|
(13
|
)
|
|
$
|
256
|
|
Income (loss) from discontinued operations
|
11
|
|
|
(1,723
|
)
|
|
(92
|
)
|
|||
Net income (loss)
|
$
|
(641
|
)
|
|
$
|
(1,736
|
)
|
|
$
|
164
|
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.26
|
|
Income (loss) from discontinued operations
|
0.03
|
|
|
(7.36
|
)
|
|
(0.45
|
)
|
|||
Net income (loss)
|
$
|
(2.05
|
)
|
|
$
|
(7.42
|
)
|
|
$
|
0.81
|
|
Basic weighted-average shares
|
313.3
|
|
|
234.2
|
|
|
202.7
|
|
|||
Diluted earnings (loss) per common share:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.24
|
|
Income (loss) from discontinued operations
|
0.03
|
|
|
(7.36
|
)
|
|
(0.44
|
)
|
|||
Net income (loss)
|
$
|
(2.05
|
)
|
|
$
|
(7.42
|
)
|
|
$
|
0.80
|
|
Diluted weighted-average shares
|
313.3
|
|
|
234.2
|
|
|
206.3
|
|
|
|
|
WPX Energy, Inc., Stockholders
|
|
|
|
|
||||||||||||||||||||||||
|
Preferred
Stock |
|
Common
Stock
|
|
Capital in
Excess of
Par Value
|
|
Accumulated
Deficit
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total
Stockholders’
Equity
|
|
Noncontrolling
Interests(a)
|
|
Total
|
||||||||||||||||
|
(Millions)
|
||||||||||||||||||||||||||||||
Balance at December 31, 2013
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
5,516
|
|
|
$
|
(1,408
|
)
|
|
$
|
(1
|
)
|
|
$
|
4,109
|
|
|
$
|
101
|
|
|
$
|
4,210
|
|
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
—
|
|
|
—
|
|
|
—
|
|
|
164
|
|
|
—
|
|
|
164
|
|
|
7
|
|
|
171
|
|
||||||||
Contribution from noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
||||||||||||||
Stock based compensation, net of tax benefit
|
—
|
|
|
—
|
|
|
46
|
|
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
46
|
|
|||||||||
Balance at December 31, 2014
|
—
|
|
|
2
|
|
|
5,562
|
|
|
(1,244
|
)
|
|
(1
|
)
|
|
4,319
|
|
|
109
|
|
|
4,428
|
|
||||||||
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,727
|
)
|
|
|
|
(1,727
|
)
|
|
1
|
|
|
(1,726
|
)
|
|||||||||
Stock based compensation, net of tax benefit
|
—
|
|
|
—
|
|
|
26
|
|
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|||||||||
Dividends on preferred stock
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
(11
|
)
|
|
—
|
|
|
(11
|
)
|
||||||||||||
Issuance of common stock to public, net of offering costs
|
|
|
|
|
292
|
|
|
|
|
|
|
292
|
|
|
—
|
|
|
292
|
|
||||||||||||
Issuance of common stock related to an acquisition
|
|
|
1
|
|
|
295
|
|
|
|
|
|
|
296
|
|
|
—
|
|
|
296
|
|
|||||||||||
Issuance of preferred stock to public, net of offering costs
|
339
|
|
|
|
|
|
|
|
|
|
|
339
|
|
|
—
|
|
|
339
|
|
||||||||||||
Impact of divestitures
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
|
(110
|
)
|
|
(109
|
)
|
||||||||||||
Balance at December 31, 2015
|
339
|
|
|
3
|
|
|
6,164
|
|
|
(2,971
|
)
|
|
—
|
|
|
3,535
|
|
|
—
|
|
|
3,535
|
|
||||||||
Comprehensive income (loss) attributable to WPX Energy, Inc.
|
|
|
|
|
|
|
(601
|
)
|
|
|
|
(601
|
)
|
|
|
|
(601
|
)
|
|||||||||||||
Stock based compensation, net of tax benefit
|
|
|
|
|
23
|
|
|
|
|
|
|
23
|
|
|
|
|
23
|
|
|||||||||||||
Issuance of common stock to public, net of offering costs
|
|
|
|
|
538
|
|
|
|
|
|
|
538
|
|
|
|
|
538
|
|
|||||||||||||
Conversion of preferred stock to common stock
|
(107
|
)
|
|
|
|
118
|
|
|
|
|
|
|
11
|
|
|
|
|
11
|
|
||||||||||||
Loss on induced conversion of preferred stock and related conversion costs
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
(22
|
)
|
|
|
|
(22
|
)
|
|||||||||||||
Dividends on preferred stock
|
|
|
|
|
(18
|
)
|
|
|
|
|
|
(18
|
)
|
|
|
|
(18
|
)
|
|||||||||||||
Balance at December 31, 2016
|
$
|
232
|
|
|
$
|
3
|
|
|
$
|
6,803
|
|
|
$
|
(3,572
|
)
|
|
$
|
—
|
|
|
$
|
3,466
|
|
|
$
|
—
|
|
|
$
|
3,466
|
|
(a)
|
Primarily represented the 31 percent of Apco Oil and Gas International Inc. owned by others.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Operating Activities(a)
|
(Millions)
|
||||||||||
Net income (loss)
|
$
|
(601
|
)
|
|
$
|
(1,726
|
)
|
|
$
|
171
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
631
|
|
|
940
|
|
|
863
|
|
|||
Deferred income tax provision (benefit)
|
(281
|
)
|
|
(1,005
|
)
|
|
46
|
|
|||
Provision for impairment of properties and equipment (including certain exploration expenses) and investments
|
38
|
|
|
2,426
|
|
|
236
|
|
|||
Net (gain) loss on derivatives in continuing operations
|
207
|
|
|
(418
|
)
|
|
(434
|
)
|
|||
Net settlements related to derivatives in continuing operations
|
302
|
|
|
617
|
|
|
(125
|
)
|
|||
Net loss on derivatives included in discontinued operations
|
46
|
|
|
—
|
|
|
—
|
|
|||
Amortization of stock-based awards
|
36
|
|
|
35
|
|
|
36
|
|
|||
Loss on extinguishment of debt and acquisition bridge financing fees
|
1
|
|
|
81
|
|
|
—
|
|
|||
Net (gain) loss on sales of assets and divestment of transportation contracts
|
(29
|
)
|
|
(385
|
)
|
|
196
|
|
|||
Cash provided (used) by operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
126
|
|
|
233
|
|
|
51
|
|
|||
Inventories
|
10
|
|
|
(2
|
)
|
|
19
|
|
|||
Margin deposits and customer margin deposits payable
|
(1
|
)
|
|
26
|
|
|
(10
|
)
|
|||
Other current assets
|
5
|
|
|
—
|
|
|
8
|
|
|||
Accounts payable
|
(72
|
)
|
|
(247
|
)
|
|
4
|
|
|||
Federal income taxes payable
|
(19
|
)
|
|
—
|
|
|
—
|
|
|||
Accrued and other current liabilities
|
(51
|
)
|
|
79
|
|
|
(1
|
)
|
|||
Payments on liabilities accrued in 2015 for retained transportation and gathering contracts related to discontinued operations
|
(53
|
)
|
|
(14
|
)
|
|
—
|
|
|||
Other, including changes in other noncurrent assets and liabilities
|
(33
|
)
|
|
171
|
|
|
10
|
|
|||
Net cash provided by operating activities(a)
|
262
|
|
|
811
|
|
|
1,070
|
|
|||
Investing Activities(a)
|
|
|
|
|
|
||||||
Capital expenditures(b)
|
(578
|
)
|
|
(1,124
|
)
|
|
(1,807
|
)
|
|||
Proceeds from sale of assets
|
1,127
|
|
|
810
|
|
|
374
|
|
|||
Proceeds (payments) related to divestment of transportation contracts
|
(238
|
)
|
|
209
|
|
|
—
|
|
|||
Purchases of a business, net of cash acquired
|
—
|
|
|
(1,212
|
)
|
|
—
|
|
|||
Other
|
(1
|
)
|
|
1
|
|
|
(4
|
)
|
|||
Net cash provided by (used in) investing activities(a)
|
310
|
|
|
(1,316
|
)
|
|
(1,437
|
)
|
|||
Financing Activities
|
|
|
|
|
|
||||||
Proceeds from common stock
|
540
|
|
|
295
|
|
|
16
|
|
|||
Proceeds from preferred stock
|
—
|
|
|
339
|
|
|
—
|
|
|||
Dividends paid on preferred stock
|
(18
|
)
|
|
(6
|
)
|
|
—
|
|
|||
Payments related to induced conversion of preferred stock to common stock
|
(10
|
)
|
|
—
|
|
|
—
|
|
|||
Borrowings on credit facility
|
380
|
|
|
841
|
|
|
1,947
|
|
|||
Payments on credit facility
|
(645
|
)
|
|
(856
|
)
|
|
(2,077
|
)
|
|||
Proceeds from long-term debt
|
—
|
|
|
1,000
|
|
|
500
|
|
|||
Payments for retirement of long-term debt
|
(356
|
)
|
|
(1,100
|
)
|
|
—
|
|
|||
Payments for credit facility amendment fees, debt issuance costs and acquisition bridge financing fees
|
(5
|
)
|
|
(40
|
)
|
|
(13
|
)
|
|||
Other
|
—
|
|
|
—
|
|
|
(29
|
)
|
|||
Net cash (used in) provided by financing activities
|
(114
|
)
|
|
473
|
|
|
344
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
458
|
|
|
(32
|
)
|
|
(23
|
)
|
|||
Effect of exchange rate changes on international cash and cash equivalents
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||
Cash and cash equivalents at beginning of period
|
38
|
|
|
70
|
|
|
99
|
|
|||
Cash and cash equivalents at end of period
|
$
|
496
|
|
|
$
|
38
|
|
|
$
|
70
|
|
__________
|
|
|
|
|
|
||||||
(a) Amounts reflect continuing and discontinued operations unless otherwise noted. See Note 3 of Notes to Consolidated Financial Statements for discussion of discontinued operations.
|
|||||||||||
(b) Increase to properties and equipment
|
$
|
(584
|
)
|
|
$
|
(865
|
)
|
|
$
|
(1,934
|
)
|
Changes in related accounts payable and accounts receivable
|
6
|
|
|
(259
|
)
|
|
127
|
|
|||
Capital expenditures
|
$
|
(578
|
)
|
|
$
|
(1,124
|
)
|
|
$
|
(1,807
|
)
|
•
|
impairment assessments of long-lived assets;
|
•
|
valuations of derivatives;
|
•
|
estimation of oil and natural gas reserves;
|
•
|
assessments of litigation-related contingencies;
|
•
|
asset retirement obligations; and
|
•
|
valuation of deferred tax assets.
|
|
Years ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Material, supplies and other
|
$
|
34
|
|
|
$
|
44
|
|
Crude oil production in transit
|
2
|
|
|
2
|
|
||
|
$
|
36
|
|
|
$
|
46
|
|
|
Derivative Treatment
|
|
Accounting Method
|
|
Normal purchases and normal sales exception
|
|
Accrual accounting
|
|
Designated in a qualifying hedging relationship
|
|
Hedge accounting
|
|
All other derivatives
|
|
Mark-to-market accounting
|
•
|
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to production and for which we have not elected the normal purchases and normal sales exception;
|
•
|
unrealized gains and losses on all derivatives that are not designated as cash flow hedges related to gas management and for which we have not elected the normal purchases and normal sales exception;
|
•
|
realized gains and losses on all derivatives that settle financially;
|
•
|
realized gains and losses on derivatives held for trading purposes; and
|
•
|
realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
|
|
|
Years Ended December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(Millions)
|
||||||
Revenues
|
|
$
|
1,578
|
|
|
$
|
2,905
|
|
Net income (loss) from continuing operations attributable to WPX Energy, Inc.
|
|
$
|
81
|
|
|
$
|
278
|
|
|
|
Purchase Price Allocation
|
||
|
|
(Millions)
|
||
Consideration:
|
|
|
||
Cash, net of an estimated post-close settlement
|
|
$
|
1,251
|
|
Fair value of WPX common stock issued
|
|
296
|
|
|
Total consideration
|
|
$
|
1,547
|
|
Fair value of liabilities assumed:
|
|
|
||
Accounts payable
|
|
$
|
104
|
|
Accrued liabilities
|
|
74
|
|
|
Deferred income taxes
|
|
752
|
|
|
Long-term debt
|
|
990
|
|
|
Asset retirement obligation
|
|
23
|
|
|
Total liabilities assumed as of the acquisition date
|
|
1,943
|
|
|
Fair value of assets acquired:
|
|
|
||
Cash and cash equivalents
|
|
51
|
|
|
Accounts receivable, net
|
|
80
|
|
|
Derivative assets, current
|
|
97
|
|
|
Derivative assets, noncurrent
|
|
34
|
|
|
Inventories
|
|
12
|
|
|
Other current assets
|
|
3
|
|
|
Properties and equipment(a)
|
|
3,209
|
|
|
Other noncurrent assets
|
|
4
|
|
|
Total assets acquired as of the acquisition date
|
|
3,490
|
|
|
Net fair value of assets and liabilities
|
|
$
|
1,547
|
|
Proved properties
|
|
$
|
881
|
|
Unproved properties
|
|
2,168
|
|
|
Gathering, processing and other facilities
|
|
157
|
|
|
Other
|
|
3
|
|
|
Total
|
|
$
|
3,209
|
|
•
|
$52 million
gain recorded on the sale of the Piceance Basin in 2016.
|
•
|
As a result of market conditions including oil and natural gas prices in the fourth quarter of 2015, we performed impairment assessments of our proved producing properties. As a result of these assessments, which included the possibility of cash flows from a divestiture of the Piceance Basin, we recorded a total of
$2,334 million
in impairment charges associated with the Piceance Basin, of which approximately
$2,308 million
is recorded in Impairment of assets held for sale in the table below and
$26 million
is included in exploration expenses.
|
•
|
During the second quarter of 2014, we completed the sale of a portion of our working interests in certain Piceance Basin wells. Based on an estimated total value received at closing of
$329 million
which represented estimated final cash proceeds and an estimated fair value of incentive distribution rights we received, we recorded a
$195 million
loss on the sale in the second quarter of 2014. An additional
$1 million
loss on sale was recorded in the third quarter of 2014.
|
•
|
Impairments of exploratory well costs and dry hole costs for 2014 include
$67 million
of impairment related to our Niobrara Shale well costs in the Piceance Basin.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
|
(Millions)
|
|
|
||||||
Total revenues(a)
|
$
|
64
|
|
|
$
|
592
|
|
|
$
|
1,322
|
|
Costs and expenses:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
$
|
9
|
|
|
$
|
412
|
|
|
$
|
500
|
|
Lease and facility operating
|
18
|
|
|
103
|
|
|
179
|
|
|||
Gathering, processing and transportation
|
49
|
|
|
257
|
|
|
328
|
|
|||
Taxes other than income
|
2
|
|
|
21
|
|
|
82
|
|
|||
Exploration
|
—
|
|
|
26
|
|
|
76
|
|
|||
General and administrative
|
9
|
|
|
45
|
|
|
67
|
|
|||
Gas management
|
—
|
|
|
1
|
|
|
8
|
|
|||
Accrual for contract obligations retained
|
—
|
|
|
187
|
|
|
—
|
|
|||
Impairment of assets held for sale
|
—
|
|
|
2,324
|
|
|
50
|
|
|||
Loss on sale of working interest in the Piceance Basin
|
—
|
|
|
—
|
|
|
196
|
|
|||
Other—net
|
8
|
|
|
(7
|
)
|
|
11
|
|
|||
Total costs and expenses(b)
|
95
|
|
|
3,369
|
|
|
1,497
|
|
|||
Operating income (loss)
|
(31
|
)
|
|
(2,777
|
)
|
|
(175
|
)
|
|||
Investment income and other
|
—
|
|
|
6
|
|
|
26
|
|
|||
Gain (loss) on sales of domestic assets
|
51
|
|
|
(15
|
)
|
|
—
|
|
|||
Gain (loss) on sale of international assets
|
—
|
|
|
41
|
|
|
—
|
|
|||
Income (loss) from discontinued operations before income taxes
|
20
|
|
|
(2,745
|
)
|
|
(149
|
)
|
|||
Provision (benefit) for income taxes
|
9
|
|
|
(1,023
|
)
|
|
(64
|
)
|
|||
Income (loss) from discontinued operations (c)
|
$
|
11
|
|
|
$
|
(1,722
|
)
|
|
$
|
(85
|
)
|
|
Total
|
||
|
(Millions)
|
||
Assets classified as held for sale
|
|
||
Current assets:
|
|
||
Accounts receivable (including an affiliate receivable)
|
$
|
55
|
|
Derivative assets
|
68
|
|
|
Inventories
|
13
|
|
|
Other
|
2
|
|
|
Total current assets
|
138
|
|
|
Properties and equipment, net(a)
|
880
|
|
|
Derivative assets
|
14
|
|
|
Total assets classified as held for sale—discontinued operations
|
$
|
1,032
|
|
Total assets classified as held for sale—continuing operations (Note 5)
|
40
|
|
|
Total assets classified as held for sale on the Consolidated Balance Sheets
|
$
|
1,072
|
|
|
|
||
Liabilities associated with assets held for sale
|
|
||
Current liabilities:
|
|
||
Accounts payable
|
$
|
93
|
|
Accrued and other current liabilities
|
47
|
|
|
Total current liabilities
|
140
|
|
|
Asset retirement obligations
|
133
|
|
|
Total liabilities associated with assets held for sale on the Consolidated Balance Sheets
|
$
|
273
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
|
(Millions)
|
|
|
||||||
Cash provided by operating activities(a)
|
$
|
25
|
|
|
$
|
187
|
|
|
$
|
650
|
|
Capital expenditures within investing activities
|
$
|
(35
|
)
|
|
$
|
(266
|
)
|
|
$
|
(597
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions, except per-share amounts)
|
||||||||||
Income (loss) from continuing operations attributable to WPX Energy, Inc.
|
$
|
(612
|
)
|
|
$
|
(4
|
)
|
|
$
|
256
|
|
Less: Dividends on preferred stock
|
18
|
|
|
9
|
|
|
—
|
|
|||
Less: Loss on induced conversion of preferred stock
|
22
|
|
|
—
|
|
|
—
|
|
|||
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
|
$
|
(652
|
)
|
|
$
|
(13
|
)
|
|
$
|
256
|
|
Basic weighted-average shares
|
313.3
|
|
|
234.2
|
|
|
202.7
|
|
|||
Effect of dilutive securities(a):
|
|
|
|
|
|
||||||
Nonvested restricted stock units and awards
|
—
|
|
|
—
|
|
|
2.7
|
|
|||
Stock options
|
—
|
|
|
—
|
|
|
0.9
|
|
|||
Diluted weighted-average shares
|
313.3
|
|
|
234.2
|
|
|
206.3
|
|
|||
Earnings (loss) per common share from continuing operations:
|
|
|
|
|
|
||||||
Basic
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.26
|
|
Diluted
|
$
|
(2.08
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
1.24
|
|
|
Years Ended December 31,
|
||||
|
2016
|
|
2015
|
||
|
(Millions)
|
||||
Weighted-average nonvested restricted stock units and awards
|
2.2
|
|
|
1.3
|
|
Weighted-average stock options
|
0.1
|
|
|
0.1
|
|
Common shares issuable upon assumed conversion of 6.25% Series A mandatory convertible preferred stock (Note 13)
|
23.8
|
|
|
15.5
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Options excluded (millions)
|
2.0
|
|
|
2.6
|
|
|
1.4
|
|
|||
Weighted-average exercise price of options excluded
|
$
|
17.42
|
|
|
$
|
16.16
|
|
|
$
|
18.42
|
|
Exercise price range of options excluded
|
$14.41 - $21.81
|
|
|
$11.46 - $21.81
|
|
|
$16.46 - $21.81
|
|
|||
Fourth quarter weighted-average market price
|
$
|
13.23
|
|
|
$
|
7.43
|
|
|
$
|
15.96
|
|
•
|
$11 million
impairment in the fourth quarter in the Green River Basin; and
|
•
|
$4 million
of impairments in the fourth quarter of other properties.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Geologic and geophysical costs
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
6
|
|
Impairments of exploratory area well costs and dry hole costs
|
1
|
|
|
24
|
|
|
21
|
|
|||
Unproved leasehold property impairments, amortization and expiration
|
38
|
|
|
54
|
|
|
74
|
|
|||
Total exploration expenses
|
$
|
42
|
|
|
$
|
85
|
|
|
$
|
101
|
|
|
Estimated
Useful
Life(a)
(Years)
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||||
|
|
|
(Millions)
|
||||||
Proved properties
|
(b)
|
|
$
|
6,335
|
|
|
$
|
5,520
|
|
Unproved properties
|
(c)
|
|
2,069
|
|
|
2,342
|
|
||
Gathering, processing and other facilities
|
15-25
|
|
232
|
|
|
217
|
|
||
Construction in progress
|
(c)
|
|
180
|
|
|
198
|
|
||
Other
|
3-40
|
|
113
|
|
|
138
|
|
||
Total properties and equipment, at cost
|
|
|
8,929
|
|
|
8,415
|
|
||
Accumulated depreciation, depletion and amortization
|
|
|
(2,455
|
)
|
|
(1,893
|
)
|
||
Properties and equipment—net
|
|
|
$
|
6,474
|
|
|
$
|
6,522
|
|
(a)
|
Estimated useful lives are presented as of December 31,
2016
.
|
(b)
|
Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note
1
).
|
(c)
|
Unproved properties and construction in progress are not yet subject to depreciation and depletion.
|
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Balance, January 1
|
$
|
102
|
|
|
$
|
77
|
|
Liabilities incurred
|
5
|
|
|
26
|
|
||
Liabilities settled
|
(6
|
)
|
|
(2
|
)
|
||
Estimate revisions
|
—
|
|
|
(4
|
)
|
||
Accretion expense(a)
|
6
|
|
|
5
|
|
||
Balance, December 31
|
$
|
107
|
|
|
$
|
102
|
|
Amount reflected as current
|
$
|
7
|
|
|
$
|
3
|
|
(a)
|
Accretion expense is included in lease and facility operating expense on the Consolidated Statements of Operations.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Trade
|
$
|
64
|
|
|
$
|
85
|
|
Accrual for capital expenditures
|
72
|
|
|
65
|
|
||
Royalties
|
69
|
|
|
71
|
|
||
Affiliate payable for revenue related to assets held for sale
|
—
|
|
|
43
|
|
||
Other
|
17
|
|
|
14
|
|
||
|
$
|
222
|
|
|
$
|
278
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Taxes other than income taxes
|
$
|
15
|
|
|
$
|
25
|
|
Accrued interest
|
72
|
|
|
82
|
|
||
Compensation and benefit related accruals
|
51
|
|
|
61
|
|
||
Gathering and transportation
|
14
|
|
|
8
|
|
||
Gathering and transportation related to exited areas
|
57
|
|
|
56
|
|
||
Future construction obligations related to sales of gathering systems
|
25
|
|
|
3
|
|
||
Deferred gain on sales of gathering systems
|
41
|
|
|
4
|
|
||
Accrued income taxes
|
—
|
|
|
41
|
|
||
Other, including other loss contingencies
|
26
|
|
|
22
|
|
||
|
$
|
301
|
|
|
$
|
302
|
|
|
December 31,
|
||||||
|
2016 (a)
|
|
2015 (a)
|
||||
|
(Millions)
|
||||||
Credit facility agreement
|
$
|
—
|
|
|
$
|
265
|
|
5.250% Senior Notes due 2017
|
—
|
|
|
355
|
|
||
7.500% Senior Notes due 2020
|
500
|
|
|
500
|
|
||
6.000% Senior Notes due 2022
|
1,100
|
|
|
1,100
|
|
||
8.250% Senior Notes due 2023
|
500
|
|
|
500
|
|
||
5.250% Senior Notes due 2024
|
500
|
|
|
500
|
|
||
Other
|
1
|
|
|
1
|
|
||
Total debt
|
$
|
2,601
|
|
|
$
|
3,221
|
|
Less: Current portion of long-term debt
|
—
|
|
|
1
|
|
||
Total long-term debt
|
$
|
2,601
|
|
|
$
|
3,220
|
|
Less: Debt issuance costs(b)
|
26
|
|
|
31
|
|
||
Total long-term debt, net(b)
|
$
|
2,575
|
|
|
$
|
3,189
|
|
(a)
|
Interest paid on debt totaled
$194 million
,
$120 million
and
$97 million
for
2016
,
2015
and
2014
, respectively.
|
(b)
|
Debt issuance costs related to our Credit Facility are recorded in other noncurrent assets on the Consolidated Balance Sheets.
|
(1)
|
(i) the Company’s Corporate Rating is BBB- or better by S&P (without negative outlook or negative watch) or (ii) Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two Corporate Ratings is at least BB+ by S&P or Ba1 by Moody’s; or
|
(2)
|
both (i) the ratio of Consolidated Net Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) is less than or equal to
3.00
to 1.00 and (ii) the Corporate Rating is (A) at least Ba1 by Moody’s and at least BB by S&P or (B) at least Ba2 by Moody’s and at least BB+ by S&P.
|
•
|
ratio of Consolidated Secured Indebtedness to Consolidated EBITDAX (for the most recently ended four consecutive fiscal quarters) of not greater than
3.25
to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and
3.00
to 1.00 thereafter; and
|
•
|
a ratio of consolidated current assets (including the unused amount of the Borrowing Base) of the Company and its consolidated subsidiaries to the consolidated current liabilities of the Company and its consolidated subsidiaries as of the last day of any fiscal quarter of at least
1.0
to 1.0.
|
•
|
non-payment of principal, interest or fees;
|
•
|
inaccuracy of representations and warranties in any material respect when made or when deemed made;
|
•
|
violation of covenants;
|
•
|
cross payment-defaults;
|
•
|
cross acceleration;
|
•
|
bankruptcy and insolvency events;
|
•
|
certain unsatisfied judgments;
|
•
|
a change of control; and
|
•
|
during any secured period, the failure of the collateral documents to be in effect or a lien to be valid and perfected.
|
Senior Note
|
|
Face Value (Millions)
|
|
Maturity Date
|
|
Interest Payment Dates
|
|
Optional Redemption Period(a)
|
||
7.500% Senior Notes due 2020 (the “2020 Notes”)
|
|
$
|
500
|
|
|
August 1, 2020
|
|
February 1, August 1
|
|
July 1, 2020
|
6.000% Senior Notes due 2022 (the “2022 Notes”)
|
|
$
|
1,100
|
|
|
January 15, 2022
|
|
January 15, July 15
|
|
October 15, 2021
|
8.250% Senior Notes due 2023 (the “2023 Notes”)
|
|
$
|
500
|
|
|
August 1, 2023
|
|
February 1, August 1
|
|
June 1, 2023
|
5.250% Senior Notes due 2024 (the “2024 Notes”)
|
|
$
|
500
|
|
|
September 15, 2024
|
|
March 15, September 15
|
|
June 15, 2024
|
(a)
|
At any time prior to these dates, we have the option to redeem some or all of the notes at a specified “make whole” premium as described in the indenture(s) governing the notes to be redeemed. On or after these dates, we have the option to redeem the notes, in whole or in part, at a redemption price equal to
100%
of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date as more fully described in the indenture.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Provision (benefit):
|
|
|
|
|
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
(26
|
)
|
|
$
|
(4
|
)
|
|
$
|
8
|
|
State
|
(7
|
)
|
|
7
|
|
|
1
|
|
|||
|
(33
|
)
|
|
3
|
|
|
9
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
(301
|
)
|
|
12
|
|
|
134
|
|
|||
State
|
9
|
|
|
9
|
|
|
5
|
|
|||
|
(292
|
)
|
|
21
|
|
|
139
|
|
|||
Total provision (benefit)
|
$
|
(325
|
)
|
|
$
|
24
|
|
|
$
|
148
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Provision (benefit) at statutory rate
|
$
|
(328
|
)
|
|
$
|
7
|
|
|
$
|
141
|
|
Increases (decreases) in taxes resulting from:
|
|
|
|
|
|
||||||
State income taxes (net of federal benefit)
|
(40
|
)
|
|
3
|
|
|
4
|
|
|||
Valuation allowance on current year state income taxes (net of federal benefit)
|
18
|
|
|
1
|
|
|
—
|
|
|||
Valuation allowance on state income taxes resulting from sale (net of federal benefit)
|
8
|
|
|
—
|
|
|
—
|
|
|||
Effective state income tax rate change (net of federal benefit)
|
15
|
|
|
7
|
|
|
(9
|
)
|
|||
State income tax legislation change (net of federal benefit)
|
—
|
|
|
—
|
|
|
9
|
|
|||
Other
|
2
|
|
|
6
|
|
|
3
|
|
|||
Provision (benefit) for income taxes
|
$
|
(325
|
)
|
|
$
|
24
|
|
|
$
|
148
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
$
|
1,277
|
|
|
$
|
988
|
|
Derivatives, net
|
—
|
|
|
155
|
|
||
Other, net
|
2
|
|
|
1
|
|
||
Total deferred tax liabilities
|
1,279
|
|
|
1,144
|
|
||
Deferred tax assets:
|
|
|
|
||||
Accrued liabilities and other
|
178
|
|
|
248
|
|
||
Alternative minimum tax credits
|
104
|
|
|
114
|
|
||
Loss carryovers
|
849
|
|
|
441
|
|
||
Derivatives, net
|
48
|
|
|
—
|
|
||
Total deferred tax assets
|
1,179
|
|
|
803
|
|
||
Less: valuation allowance
|
151
|
|
|
124
|
|
||
Total net deferred tax assets
|
1,028
|
|
|
679
|
|
||
Net deferred tax liabilities
|
$
|
251
|
|
|
$
|
465
|
|
|
Midstream Services
|
|
Transportation
|
|
Total
|
||||||
|
(Millions)
|
||||||||||
2017
|
$
|
126
|
|
|
$
|
38
|
|
|
$
|
164
|
|
2018
|
101
|
|
|
35
|
|
|
136
|
|
|||
2019
|
96
|
|
|
24
|
|
|
120
|
|
|||
2020
|
89
|
|
|
21
|
|
|
110
|
|
|||
2021
|
76
|
|
|
2
|
|
|
78
|
|
|||
Thereafter
|
244
|
|
|
1
|
|
|
245
|
|
|||
Total commitments
|
$
|
732
|
|
|
$
|
121
|
|
|
$
|
853
|
|
|
|
|
|
|
|
||||||
Accrued liabilities
|
$
|
56
|
|
|
$
|
91
|
|
|
$
|
147
|
|
Restricted Stock Units
|
Shares
|
|
Weighted-
Average
Fair Value(a)
|
|||
|
(Millions)
|
|
|
|||
Nonvested at December 31, 2015
|
5.9
|
|
|
$
|
13.34
|
|
Granted
|
3.4
|
|
|
$
|
10.99
|
|
Forfeited
|
(0.1
|
)
|
|
$
|
10.35
|
|
Vested
|
(2.7
|
)
|
|
$
|
13.79
|
|
Nonvested at December 31, 2016
|
6.5
|
|
|
$
|
11.92
|
|
(a)
|
Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.
|
|
2016
|
|
2015
|
|
2014
|
||||||
Weighted-average grant date fair value of restricted stock units granted during the year, per share
|
$
|
10.99
|
|
|
$
|
10.24
|
|
|
$
|
18.37
|
|
Total fair value of restricted stock units vested during the year (millions)
|
$
|
37
|
|
|
$
|
40
|
|
|
$
|
33
|
|
Stock Options
|
Options
|
|
Weighted-
Average
Exercise
Price
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate
Intrinsic
Value
|
|||||
|
(Millions)
|
|
|
|
(Years)
|
|
(Millions)
|
|||||
Outstanding at December 31, 2015
|
2.9
|
|
|
$
|
15.07
|
|
|
|
|
$
|
—
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
Exercised
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
Forfeited
|
(0.2
|
)
|
|
$
|
12.45
|
|
|
|
|
|
||
Outstanding at December 31, 2016
|
2.7
|
|
|
$
|
15.31
|
|
|
2.7
|
|
$
|
4
|
|
Exercisable at December 31, 2016
|
2.6
|
|
|
$
|
15.13
|
|
|
2.5
|
|
$
|
4
|
|
|
2014
|
||
Weighted-average grant date fair value of options granted
|
$
|
18.94
|
|
Weighted-average assumptions:
|
|
||
Dividend yield
|
—
|
|
|
Volatility
|
43.0
|
%
|
|
Risk-free interest rate
|
1.85
|
%
|
|
Expected life (years)
|
5.9
|
|
•
|
Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.
|
•
|
Level 2—Inputs are other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (“OTC”) instruments such as forwards, swaps and options. These options, which hedge future sales of production, are structured as costless collars, calls or swaptions and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings.
|
•
|
Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||
|
|
|
(Millions)
|
|
|
|
(Millions)
|
||||||||||||||||||||||||
Energy derivative assets
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
359
|
|
|
$
|
—
|
|
|
$
|
359
|
|
Energy derivative liabilities
|
$
|
—
|
|
|
$
|
215
|
|
|
$
|
—
|
|
|
$
|
215
|
|
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
15
|
|
Total debt(a)
|
$
|
—
|
|
|
$
|
2,702
|
|
|
$
|
—
|
|
|
$
|
2,702
|
|
|
$
|
—
|
|
|
$
|
2,495
|
|
|
$
|
—
|
|
|
$
|
2,495
|
|
(a)
|
The carrying value of total debt, excluding capital leases and debt issuance costs, was
$2,600 million
and
$3,220 million
as of
December 31, 2016
and
2015
, respectively.
|
|
Total losses for the years ended December31,
|
||||||||||
|
|
2015 (a)
|
|
|
|
2014 (b)
|
|
||||
|
|
|
|||||||||
Impairments:
|
|
|
|
|
|
|
|
||||
Producing properties and costs of acquired unproved reserves (Note 3 and Note 5)
|
|
$
|
2,308
|
|
|
|
|
$
|
20
|
|
|
Unproved leasehold
|
|
26
|
|
|
|
|
—
|
|
|
||
|
|
$
|
2,334
|
|
|
|
|
$
|
20
|
|
|
(a)
|
As a result of our impairment assessment in 2015, we recorded the following significant impairment charges that are reported in discontinued operations, for which the fair value measured for these properties at December 31, 2015 was estimated to be approximately
$880 million
:
|
•
|
$2,308 million
impairment charge related to natural gas-producing properties in the Piceance Basin, reported in discontinued operations. Significant assumptions in valuing these properties included estimated cash flows from a potential divestment.
|
•
|
$26 million
impairment charge on our unproved leasehold acreage in the Piceance Basin, reported in discontinued operations, as a result of the impairment of the producing properties in conjunction with a potential divestment.
|
(b)
|
As a result of our impairment assessment in 2014, we recorded the following significant impairment charges, including those reflected in discontinued operations, for which the fair value measured for these properties at December 31, 2014 was estimated to be approximately
$11 million
:
|
•
|
$11 million
impairment charge related to natural gas-producing properties in the Green River Basin. Significant assumptions in valuing these properties included proved reserves quantities of more than
23.0
billion cubic feet of gas equivalent, forward weighted average prices averaging approximately
$4.77
per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rates of
9 percent
and
11 percent
.
|
•
|
$9 million
of impairment charges related to costs of acquired unproved reserves and other insignificant producing properties including
$5 million
of which is reflected in discontinued operations.
|
Commodity
|
|
Period
|
|
Contract Type (a)
|
|
Location
|
|
Notional Volume (b)
|
|
Weighted Average
Price (c)
|
|||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|||
Crude Oil
|
|
2017
|
|
Fixed Price Swaps
|
|
WTI
|
|
(39,554)
|
|
$
|
50.93
|
|
|
Crude Oil
|
|
2017
|
|
Basis Swaps
|
|
Midland
|
|
(12,778)
|
|
$
|
(0.52
|
)
|
|
Crude Oil
|
|
2017
|
|
Fixed Price Calls
|
|
WTI
|
|
(4,500)
|
|
$
|
56.47
|
|
|
Crude Oil
|
|
2017
|
|
Swaptions
|
|
WTI
|
|
(1,764)
|
|
$
|
44.61
|
|
|
Crude Oil
|
|
2018
|
|
Fixed Price Swaps
|
|
WTI
|
|
(30,000)
|
|
$
|
54.61
|
|
|
Crude Oil
|
|
2018
|
|
Basis Swaps
|
|
Midland
|
|
(13,000)
|
|
$
|
(0.94
|
)
|
|
Crude Oil
|
|
2018
|
|
Fixed Price Calls
|
|
WTI
|
|
(13,000)
|
|
$
|
58.89
|
|
|
Crude Oil
|
|
2019
|
|
Basis Swaps
|
|
Midland
|
|
(7,000)
|
|
$
|
(1.00
|
)
|
|
Crude Oil
|
|
2020
|
|
Basis Swaps
|
|
Midland
|
|
(1,000)
|
|
$
|
(1.10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas
|
|
2017
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(170)
|
|
$
|
3.02
|
|
|
Natural Gas
|
|
2017
|
|
Basis Swaps
|
|
San Juan
|
|
(98)
|
|
$
|
(0.18
|
)
|
|
Natural Gas
|
|
2017
|
|
Basis Swaps
|
|
Permian
|
|
(73)
|
|
$
|
(0.20
|
)
|
|
Natural Gas
|
|
2017
|
|
Fixed Price Calls
|
|
Henry Hub
|
|
(16)
|
|
$
|
4.50
|
|
|
Natural Gas
|
|
2018
|
|
Fixed Price Swaps
|
|
Henry Hub
|
|
(125)
|
|
$
|
2.95
|
|
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
San Juan
|
|
(20)
|
|
$
|
(0.30
|
)
|
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
Permian
|
|
(43)
|
|
$
|
(0.28
|
)
|
|
Natural Gas
|
|
2018
|
|
Basis Swaps
|
|
Waha
|
|
(63)
|
|
$
|
(0.16
|
)
|
|
Natural Gas
|
|
2018
|
|
Fixed Price Calls
|
|
Henry Hub
|
|
(16)
|
|
$
|
4.75
|
|
|
Natural Gas
|
|
2018
|
|
Swaptions
|
|
Henry Hub
|
|
(20)
|
|
$
|
3.33
|
|
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Permian
|
|
(5)
|
|
$
|
(0.32
|
)
|
|
Natural Gas
|
|
2019
|
|
Basis Swaps
|
|
Waha
|
|
(60)
|
|
$
|
(0.19
|
)
|
|
Commodity
|
|
Period
|
|
Contract Type (d)
|
|
Location (e)
|
|
Notional Volume (b)
|
|
Weighted Average
Price
|
|||
Physical Derivatives
|
|
|
|
|
|
|
|
|
|
|
|||
Natural Gas
|
|
2017
|
|
Index
|
|
Multiple
|
|
(16
|
)
|
|
(f)
|
(a)
|
Derivatives related to crude oil production are fixed price swaps settled on the business day, average basis swaps, fixed price calls and swaptions. The derivatives related to natural gas production are fixed price swaps, basis swaps, fixed price calls and swaptions. In connection with several crude oil and natural gas swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil and natural gas swaps. These swaptions grant the counterparty the option to enter into future swaps with us.
|
(b)
|
Crude oil volumes are reported in Bbl/day and natural gas volumes are reported in BBtu/day.
|
(c)
|
The weighted average price for crude oil is reported in $/Bbl and the natural gas is reported in $/MMBtu.
|
(d)
|
We enter into exchange traded fixed price and basis swaps, over-the-counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
|
(e)
|
We transact at multiple locations primarily around our core assets to maximize the economic value of our transportation and asset management agreements.
|
(f)
|
Weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
||||||||||
Gain (loss) from derivatives related to production(a)
|
$
|
(207
|
)
|
|
$
|
438
|
|
|
$
|
515
|
|
Gain (loss) from derivatives related to physical marketing agreements(b)
|
—
|
|
|
(20
|
)
|
|
(81
|
)
|
|||
Net gain (loss) on derivatives
|
$
|
(207
|
)
|
|
$
|
418
|
|
|
$
|
434
|
|
(a)
|
Includes settlements totaling
$301 million
and
$650 million
for the years ended
December 31, 2016
and
2015
, respectively, and payments totaling
$4 million
for the year ended
December 31, 2014
.
|
(b)
|
Includes settlements totaling
$1 million
for the year ended
December 31, 2016
and payments totaling
$33 million
and
$121 million
for the years ended
December 31, 2015
and
2014
, respectively.
|
|
Gross Amount Presented on Balance Sheet
|
|
Netting Adjustments (a)
|
|
Net Amount
|
||||||
December 31, 2016
|
(Millions)
|
||||||||||
Derivative assets with right of offset or master netting agreements
|
$
|
38
|
|
|
$
|
(33
|
)
|
|
$
|
5
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(215
|
)
|
|
$
|
33
|
|
|
$
|
(182
|
)
|
|
|
|
|
|
|
||||||
December 31, 2015
|
|
|
|
|
|
||||||
Derivative assets with right of offset or master netting agreements
|
$
|
359
|
|
|
$
|
(14
|
)
|
|
$
|
345
|
|
Derivative liabilities with right of offset or master netting agreements
|
$
|
(15
|
)
|
|
$
|
14
|
|
|
$
|
(1
|
)
|
(a)
|
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Receivables by product or service:
|
|
|
|
||||
Sale of natural gas, crude and related products and services
|
$
|
122
|
|
|
$
|
171
|
|
Joint interest owners
|
23
|
|
|
90
|
|
||
Other
|
23
|
|
|
39
|
|
||
Total
|
$
|
168
|
|
|
$
|
300
|
|
(a)
|
Revenues for purchaser were less than 10 percent of total consolidated revenues adjusted for net gain (loss) on derivatives.
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
|
(Millions, except per-share amounts)
|
||||||||||||||
2016
|
|
||||||||||||||
Product revenues
|
$
|
127
|
|
|
$
|
176
|
|
|
$
|
188
|
|
|
$
|
231
|
|
Net gain (loss) on derivatives
|
$
|
57
|
|
|
$
|
(154
|
)
|
|
$
|
38
|
|
|
$
|
(148
|
)
|
Gas management
|
$
|
31
|
|
|
$
|
116
|
|
|
$
|
25
|
|
|
$
|
5
|
|
Total revenues
|
$
|
216
|
|
|
$
|
138
|
|
|
$
|
251
|
|
|
$
|
88
|
|
Operating costs and expenses
|
$
|
269
|
|
|
$
|
384
|
|
|
$
|
264
|
|
|
$
|
255
|
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
—
|
|
|
$
|
(223
|
)
|
|
$
|
(218
|
)
|
|
$
|
(171
|
)
|
Income (loss) from discontinued operations
|
(12
|
)
|
|
25
|
|
|
(1
|
)
|
|
(1
|
)
|
||||
Net income (loss)
|
$
|
(12
|
)
|
|
$
|
(198
|
)
|
|
$
|
(219
|
)
|
|
$
|
(172
|
)
|
Amounts attributable to WPX Energy, Inc. common stockholders:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(5
|
)
|
|
$
|
(229
|
)
|
|
$
|
(244
|
)
|
|
$
|
(174
|
)
|
Income (loss) from discontinued operations
|
(12
|
)
|
|
25
|
|
|
(1
|
)
|
|
(1
|
)
|
||||
Net income (loss)
|
$
|
(17
|
)
|
|
$
|
(204
|
)
|
|
$
|
(245
|
)
|
|
$
|
(175
|
)
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(0.02
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.51
|
)
|
Income (loss) from discontinued operations
|
(0.04
|
)
|
|
0.08
|
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
(0.06
|
)
|
|
$
|
(0.68
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.51
|
)
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
(0.02
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.51
|
)
|
Income (loss) from discontinued operations
|
(0.04
|
)
|
|
0.08
|
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
(0.06
|
)
|
|
$
|
(0.68
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.51
|
)
|
2015
|
|
|
|
|
|
|
|
||||||||
Product revenues
|
$
|
156
|
|
|
$
|
169
|
|
|
$
|
163
|
|
|
$
|
167
|
|
Net gain (loss) on derivatives
|
$
|
105
|
|
|
$
|
(71
|
)
|
|
$
|
205
|
|
|
$
|
179
|
|
Gas management
|
$
|
157
|
|
|
$
|
56
|
|
|
$
|
35
|
|
|
$
|
38
|
|
Total revenues
|
$
|
420
|
|
|
$
|
154
|
|
|
$
|
407
|
|
|
$
|
385
|
|
Operating costs and expenses
|
$
|
300
|
|
|
$
|
251
|
|
|
$
|
300
|
|
|
$
|
294
|
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
52
|
|
|
$
|
23
|
|
|
$
|
(70
|
)
|
|
$
|
(9
|
)
|
Income (loss) from discontinued operations
|
16
|
|
|
(53
|
)
|
|
(160
|
)
|
|
(1,525
|
)
|
||||
Net income (loss)
|
$
|
68
|
|
|
$
|
(30
|
)
|
|
$
|
(230
|
)
|
|
$
|
(1,534
|
)
|
Amounts attributable to WPX Energy, Inc. common stockholders:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
52
|
|
|
$
|
23
|
|
|
$
|
(74
|
)
|
|
$
|
(14
|
)
|
Income (loss) from discontinued operations
|
15
|
|
|
(53
|
)
|
|
(160
|
)
|
|
(1,525
|
)
|
||||
Net income (loss)
|
$
|
67
|
|
|
$
|
(30
|
)
|
|
$
|
(234
|
)
|
|
$
|
(1,539
|
)
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
0.26
|
|
|
$
|
0.11
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.06
|
)
|
Income (loss) from discontinued operations
|
0.07
|
|
|
(0.25
|
)
|
|
(0.64
|
)
|
|
(5.53
|
)
|
||||
Net income (loss)
|
$
|
0.33
|
|
|
$
|
(0.14
|
)
|
|
$
|
(0.93
|
)
|
|
$
|
(5.59
|
)
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
$
|
0.25
|
|
|
$
|
0.11
|
|
|
$
|
(0.29
|
)
|
|
$
|
(0.06
|
)
|
Income (loss) from discontinued operations
|
0.07
|
|
|
(0.25
|
)
|
|
(0.64
|
)
|
|
(5.53
|
)
|
||||
Net income (loss)
|
$
|
0.32
|
|
|
$
|
(0.14
|
)
|
|
$
|
(0.93
|
)
|
|
$
|
(5.59
|
)
|
•
|
$199 million
gain on the sale of our San Juan Basin gathering system (see Note
5
).
|
•
|
$14 million
increase of our deferred tax liability as of the beginning of the year resulting from an increase to our state effective rate.
|
•
|
$52 million
gain included in discontinued operations for the sale of the Piceance Basin (see Note
3
).
|
•
|
$5 million
recognition of a deferred gain on the sale of our San Juan Basin gathering system.
|
•
|
$238 million
net loss on divestment of the remaining transportation contracts (see Note
5
).
|
•
|
$11 million
recognition of a deferred gain on the sale of our San Juan Basin gathering system.
|
•
|
$41 million
gain related to our divestment of APCO (see Note
3
).
|
•
|
$69 million
gain recorded for the sale of a portion of our Appalachian Basin operations (see Note
5
).
|
•
|
Approximately
$22 million
associated with a contract termination and settlement agreement (see Note
5
).
|
•
|
$209 million
gain recorded for the sale of a package of marketing contracts and release of certain related firm transportation capacity in the Northeast (see Note
5
).
|
•
|
We completed the acquisition of privately held RKI and incurred additional
$104 million
costs related to this (see Note
2
).
|
•
|
Discontinued operations had
$187 million
additional expense related to contract obligations as a result of the Powder River Basin sale closing (see Note
3
).
|
•
|
$47 million
exploratory impairments comprised of dry hole costs, impairments of exploratory area well costs and impairments of leasehold costs primarily associated with exploratory plays for which management has decided to cease any further exploration activities.
|
•
|
$2.3 billion
of impairments costs on discontinued operation producing properties and leasehold (see Note
3
).
|
•
|
$70 million
gain on sale of a North Dakota gathering system (see Note
5
).
|
•
|
$23 million
related to gathering obligations in an area of the Appalachian Basin we exited in the fourth quarter of 2015 (see Note
5
).
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Proved Properties
|
$
|
6,508
|
|
|
$
|
5,703
|
|
Unproved properties
|
2,069
|
|
|
2,342
|
|
||
|
8,577
|
|
|
8,045
|
|
||
Accumulated depreciation, depletion and amortization and valuation provisions
|
(2,334
|
)
|
|
(1,763
|
)
|
||
Net capitalized costs
|
$
|
6,243
|
|
|
$
|
6,282
|
|
•
|
Excluded from capitalized costs are equipment and facilities in support of oil and gas production of
$203 million
and
$202 million
, net, as of December 31,
2016
and
2015
, respectively.
|
•
|
Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.
|
•
|
Unproved properties consist primarily of unproved leasehold costs.
|
|
For the years ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Acquisition
|
$
|
84
|
|
|
$
|
3,208
|
|
|
$
|
294
|
|
Exploration
|
5
|
|
|
84
|
|
|
92
|
|
|||
Development
|
471
|
|
|
657
|
|
|
1,376
|
|
|||
|
$
|
560
|
|
|
$
|
3,949
|
|
|
$
|
1,762
|
|
•
|
Costs incurred include capitalized and expensed items.
|
•
|
Acquisition costs are as follows: Costs in 2016 primarily relates to purchases of additional acreage in the Delaware Basin and included approximately
2.5
MMboe of proved reserves. Costs in 2015 primarily relate to the allocated purchase price of RKI properties in the Permian-Delaware Basin (see Note 2 of Notes to Consolidated Financial Statements) and includes
53
MMboe of proved developed reserves. Costs in 2014 primarily relate to purchases of oil acreage in the San Juan Basin and include approximately
5
MMboe of proved reserves.
|
•
|
Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds. The 2015 amount primarily related to the drilling of Piceance Niobrara wells.
|
•
|
Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our Piceance Basin operations were
$27 million
,
$106 million
and
$430 million
for
2016
,
2015
and
2014
, respectively.
|
|
Oil (MMBbls)
|
|
Natural Gas (Bcf)
|
|
NGLs (MMBbls)
|
|
All Products (MMBoe)
|
||||
Proved reserves at December 31, 2013
|
102.9
|
|
|
3,629.8
|
|
|
85.7
|
|
|
793.6
|
|
Revisions
|
(7.7
|
)
|
|
(198.3
|
)
|
|
(13.4
|
)
|
|
(54.1
|
)
|
Purchases
|
4.2
|
|
|
6.0
|
|
|
0.8
|
|
|
6.0
|
|
Divestitures
|
(1.8
|
)
|
|
(314.6
|
)
|
|
(8.5
|
)
|
|
(62.7
|
)
|
Extensions and discoveries
|
42.4
|
|
|
362.1
|
|
|
12.5
|
|
|
115.2
|
|
Production
|
(9.2
|
)
|
|
(335.4
|
)
|
|
(6.3
|
)
|
|
(71.4
|
)
|
Proved reserves at December 31, 2014
|
130.8
|
|
|
3,149.6
|
|
|
70.8
|
|
|
726.6
|
|
Revisions
|
(31.9
|
)
|
|
(624.6
|
)
|
|
(14.0
|
)
|
|
(150.0
|
)
|
Purchases
|
39.8
|
|
|
205.6
|
|
|
20.7
|
|
|
94.7
|
|
Divestitures
|
—
|
|
|
(380.3
|
)
|
|
—
|
|
|
(63.4
|
)
|
Extensions and discoveries
|
17.1
|
|
|
116.9
|
|
|
5.1
|
|
|
41.6
|
|
Production
|
(13.1
|
)
|
|
(277.0
|
)
|
|
(7.3
|
)
|
|
(66.5
|
)
|
Proved reserves at December 31, 2015
|
142.7
|
|
|
2,190.2
|
|
|
75.3
|
|
|
583.0
|
|
Revisions
|
(3.8
|
)
|
|
(50.2
|
)
|
|
(2.9
|
)
|
|
(15.2
|
)
|
Purchases
|
1.6
|
|
|
4.4
|
|
|
0.4
|
|
|
2.8
|
|
Divestitures
|
(5.5
|
)
|
|
(1,505.9
|
)
|
|
(38.3
|
)
|
|
(294.8
|
)
|
Extensions and discoveries
|
54.9
|
|
|
214.6
|
|
|
19.8
|
|
|
110.5
|
|
Production
|
(15.3
|
)
|
|
(118.6
|
)
|
|
(4.8
|
)
|
|
(39.9
|
)
|
Proved reserves at December 31, 2016
|
174.6
|
|
|
734.5
|
|
|
49.5
|
|
|
346.4
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
60.0
|
|
|
2,090.0
|
|
|
43.9
|
|
|
452.3
|
|
December 31, 2015
|
83.0
|
|
|
1,618.2
|
|
|
49.5
|
|
|
402.2
|
|
December 31, 2016
|
84.4
|
|
|
440.2
|
|
|
24.1
|
|
|
181.8
|
|
|
|
|
|
|
|
|
|
||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
70.8
|
|
|
1,059.6
|
|
|
26.9
|
|
|
274.3
|
|
December 31, 2015
|
59.7
|
|
|
572.0
|
|
|
25.8
|
|
|
180.8
|
|
December 31, 2016
|
90.2
|
|
|
294.2
|
|
|
25.4
|
|
|
164.6
|
|
•
|
Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit
.
|
•
|
Revisions in 2016 primarily reflect
49
MMBoe of negative revisions due to the decrease in the 12 month average price partially offset by
34
MMboe of positive revisions due to decreased costs and well improvements. Revisions in 2015 primarily reflect
209
MMboe of negative revisions related to the decrease in the 12 month average prices partially offset by
59
MMboe of positive revisions due to decreased costs and well improvements. The 2015 revisions comprised
108
MMboe net negative revisions related to proved undeveloped locations and
42
MMboe net negative revisions related to proved developed locations. Revisions in 2014 primarily reflect
16
MMboe of net positive revisions to developed reserves and
70
MMboe of net negative revisions to undeveloped reserves. The
70
MMboe of net negative revisions were primarily due to a reduction in near-term drilling capital estimates and the related limitations imposed by the SEC five year rules.
|
•
|
Purchases in 2015 reflects the RKI acquisition of which
53.4
MMboe is proved developed and
41.3
MMboe is associated with proved undeveloped locations.
|
•
|
Divestitures in 2016 relate to the sale of the Piceance Basin which included proved developed reserves and proved undeveloped reserves of
222
MMboe and
67
MMboe, respectively. Divestitures in 2015 relate to sales of properties in the Powder River Basin (
28
MMboe) and the Appalachian Basin (
35
MMboe). Divestitures in 2014 primarily relate to the sale of working interests in the Piceance Basin (see Note 3 of Notes to Consolidated Financial Statements).
|
•
|
Extensions and discoveries in 2016 reflect
26
MMboe added for proved developed locations and
84
MMboe for proved undeveloped locations primarily in the Delaware Basin. Extensions and discoveries in 2015 reflect
20.9
MMboe added for proved developed locations and
20.7
MMboe for proved undeveloped locations primarily related to
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Future cash inflows
|
$
|
8,072
|
|
|
$
|
12,391
|
|
Less:
|
|
|
|
||||
Future production costs
|
4,076
|
|
|
7,757
|
|
||
Future development costs
|
1,518
|
|
|
1,761
|
|
||
Future income tax provisions
|
—
|
|
|
—
|
|
||
Future net cash flows
|
2,478
|
|
|
2,873
|
|
||
Less 10 percent annual discount for estimated timing of cash flows
|
1,440
|
|
|
1,589
|
|
||
Standardized measure of discounted future net cash inflows
|
$
|
1,038
|
|
|
$
|
1,284
|
|
•
|
Our historical tax basis (i.e. future deductions for taxable income calculation) of proved properties at December 31, 2016 and 2015 are greater than the total standardized measure of future net cash flows before taxes; therefore, future taxable income as calculated in the standardized measure of cash flows would be less than zero.
|
•
|
Included in the
$1,284 million
of discounted future net cash inflows as of December 31, 2015 is
$270 million
related to the properties in the Piceance Basin.
|
|
For the years ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Beginning of year
|
$
|
1,284
|
|
|
$
|
3,883
|
|
|
$
|
2,964
|
|
Sales of oil and gas produced, net of operating costs
|
(458
|
)
|
|
(541
|
)
|
|
(1,324
|
)
|
|||
Net change in prices and production costs
|
(261
|
)
|
|
(5,231
|
)
|
|
303
|
|
|||
Extensions, discoveries and improved recovery, less estimated future costs
|
735
|
|
|
254
|
|
|
1,761
|
|
|||
Development costs incurred during year
|
142
|
|
|
276
|
|
|
592
|
|
|||
Changes in estimated future development costs
|
(211
|
)
|
|
1,213
|
|
|
143
|
|
|||
Purchase of reserves in place, less estimated future costs
|
20
|
|
|
657
|
|
|
147
|
|
|||
Sale of reserves in place, less estimated future costs
|
(253
|
)
|
|
(397
|
)
|
|
(391
|
)
|
|||
Revisions of previous quantity estimates
|
(78
|
)
|
|
(374
|
)
|
|
(536
|
)
|
|||
Accretion of discount
|
136
|
|
|
489
|
|
|
383
|
|
|||
Net change in income taxes
|
—
|
|
|
1,073
|
|
|
(142
|
)
|
|||
Other
|
(18
|
)
|
|
(18
|
)
|
|
(17
|
)
|
|||
Net changes
|
(246
|
)
|
|
(2,599
|
)
|
|
919
|
|
|||
End of year
|
$
|
1,038
|
|
|
$
|
1,284
|
|
|
$
|
3,883
|
|
|
Beginning
Balance
|
|
Charged
(Credited)
to Costs and
Expenses
|
|
Other
|
|
Deductions
|
|
Ending
Balance
|
||||||||||
|
|
||||||||||||||||||
2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts—accounts and notes receivable(a)
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
3
|
|
Deferred tax asset valuation(b)
|
124
|
|
|
26
|
|
|
1
|
|
|
—
|
|
|
151
|
|
|||||
Price-risk management credit reserves—assets(a)(d)
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||||
Price-risk management credit reserves—liabilities(c)(d)
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|||||
2015:
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts—accounts and notes receivable(a)
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
(5
|
)
|
|
$
|
6
|
|
Deferred tax asset valuation(b)(e)
|
118
|
|
|
3
|
|
|
3
|
|
|
—
|
|
|
124
|
|
|||||
Price-risk management credit reserves—assets(a)(d)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
2014:
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts—accounts and notes receivable(a)
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
6
|
|
Deferred tax asset valuation(b)
|
102
|
|
|
(1
|
)
|
|
17
|
|
|
—
|
|
|
118
|
|
|||||
Price-risk management credit reserves—assets(a)(d)
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
(a)
|
Deducted from related assets.
|
(b)
|
Deducted from related assets with a portion included in assets held for sale.
|
(c)
|
Deducted from related liabilities.
|
(d)
|
Included in revenues.
|
(e)
|
Includes RKI Acquisition.
|
Item 9.
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|
Item 9A.
|
Controls and Procedures
|
Item 9B.
|
Other Information
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
Item 11.
|
Executive Compensation
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence
|
Item 14.
|
Principal Accountant Fees and Services
|
|
|
|
|
|
Item 15.
|
Exhibits and Financial Statement Schedules
|
|
|
|
Page
|
Covered by report of Independent Registered Public Accounting Firm:
|
|
Consolidated Balance Sheets as of December 31, 2016 and 2015
|
|
Consolidated Statement of Operations and Comprehensive Income (Loss) for each year in the three-year period ended December 31, 2016
|
|
Consolidated Statements of Changes in Equity for each year in the three-year period ended December 31, 2016
|
|
Consolidated Statements of Cash Flows for each year in the three-year period ended December 31, 2016
|
|
Notes to consolidated financial statements
|
|
Schedule for each year in the three-year period ended December 31, 2016:
|
|
II — Valuation and qualifying accounts
|
|
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.
|
|
Not covered by report of independent auditors:
|
|
Quarterly financial data (unaudited)
|
|
Supplemental oil and gas disclosures (unaudited)
|
|
|
|
Exhibit
No.
|
|
Description
|
|
|
|
2.1**
|
|
Agreement and Plan of Merger, dated October 2, 2014, by and among Pluspetrol Resources Corporation, Pluspetrol Black River Corporation and Apco Oil and Gas International Inc. (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on October 7, 2014)
|
|
|
|
2.2**
|
|
Agreement and Plan of Merger, dated as of July 13, 2015, by and among RKI Exploration & Production, LLC, WPX Energy, Inc. and Thunder Merger Sub LLC (incorporated herein by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
|
|
|
2.3**
|
|
Membership Interest Purchase Agreement by and Among WPX Energy Holdings, LLC, as Seller, WPX Energy, Inc., solely for purposes of Section 14.15, and Terra Energy Partners LLC, as Purchaser, dated February 8, 2016 (incorporated by reference to Exhibit 2.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2016)
|
|
|
|
3.1
|
|
Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
|
|
|
|
3.2
|
|
Certificate of Amendment of Amended and Restated Certificate of Incorporation of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
|
|
|
3.3
|
|
Amended and Restated Bylaws of WPX Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 21, 2014)
|
|
|
|
3.4
|
|
Certificate of Designations for 6.25% Series A Mandatory Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
4.1
|
|
Indenture, dated as of November 14, 2011, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) filed with the SEC on November 15, 2011)
|
|
|
|
4.2
|
|
Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
|
|
|
|
4.3
|
|
First Supplemental Indenture, dated as of September 8, 2014, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 8, 2014)
|
|
|
|
4.4
|
|
Second Supplemental Indenture, dated as of July 22, 2015, between WPX Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
10.1
|
|
Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011)
|
|
|
|
10.2
|
|
Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
|
|
|
|
10.3
|
|
Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K (File No. 001-35322) filed with the SEC on January 6, 2012)
|
|
|
|
10.4
|
|
WPX Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 4.1 to WPX Energy, Inc.’s Current Report on Form 8-K (File No. 001-35322) filed with the SEC on May 29, 2013)(1)
|
|
|
|
10.5
|
|
WPX Energy, Inc. 2011 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 4.4 to WPX Energy, Inc.’s registration statement on Form S-8 (File No. 333-178388) filed with the SEC on December 8, 2011)(1)
|
|
|
|
10.6
|
|
Form of Restricted Stock Agreement between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011) (1)
|
|
|
|
Exhibit
No.
|
|
Description
|
|
|
|
10.7
|
|
Form of Restricted Stock Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.13 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
|
|
|
|
10.8
|
|
Form of Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.14 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2014) (1)
|
|
|
|
10.9
|
|
Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)(1)
|
|
|
|
10.10
|
|
Form of Stock Option Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.15 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)(1)
|
|
|
|
10.11
|
|
WPX Energy Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.16 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012)(1)
|
|
|
|
10.12
|
|
WPX Energy Board of Directors Nonqualified Deferred Compensation Plan, effective January 1, 2013 (incorporated herein by reference to Exhibit 10.17 to WPX Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2012) (1)
|
|
|
|
10.13
|
|
Retirement Agreement, dated December 16, 2013, between WPX Energy, Inc. and Ralph A. Hill (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on December 17, 2013)
|
|
|
|
10.14
|
|
Employment Agreement, dated April 29, 2014, between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.15
|
|
Form of Nonqualified Stock Option Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.16
|
|
Form of 2014 Time-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.17
|
|
Form of 2014 Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.4 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.18
|
|
Form of Time-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.5 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.19
|
|
Form of Performance-Based Restricted Stock Unit Inducement Award Agreement between WPX Energy, Inc. and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.6 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 2, 2014) (1)
|
|
|
|
10.20
|
|
Form of Restricted Stock Unit Award between WPX Energy, Inc. and Non-Employee Directors (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
|
|
|
|
10.21
|
|
Separation and Release Agreement, dated July 28, 2014, between WPX Energy, Inc. and James J. Bender (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 3, 2014) (1)
|
|
|
|
10.22
|
|
Amended and Restated Credit Agreement, dated as of October 28, 2014, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 3, 2014)
|
|
|
|
10.23
|
|
Form of Voting and Support Agreement, dated as of July 13, 2015, by and between WPX Energy, Inc. and the Member signatory thereto (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 14, 2015)
|
Exhibit
No.
|
|
Description
|
|
|
|
10.24
|
|
First Amendment to the Amended and Restated Credit Agreement, dated as of July 16, 2015, by and among WPX Energy, Inc., the lenders party thereto, and Citibank, N.A., as existing Administrative Agent and existing Swingline Lender, and Wells Fargo Bank, National Association, as successor Administrative Agent and successor Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on July 22, 2015)
|
|
|
|
10.25
|
|
Commitment Increase Agreement for Amended and Restated Credit Agreement, dated as of July 31, 2015, among WPX Energy, Inc., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the Issuing Banks thereto (incorporated by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on August 6, 2015)
|
|
|
|
10.26
|
|
Registration Rights Agreement dated August 17, 2015, among WPX Energy, Inc. and the signatories thereto (incorporated herein by reference to Exhibit 10.35 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015)
|
|
|
|
10.27
|
|
Second Amendment to the Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among WPX Energy, Inc., as the borrower thereunder, the financial institutions party thereto from time to time, as lenders, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on March 22, 2016)
|
|
|
|
10.28
|
|
Form of Performance-Based Restricted Stock Unit Agreement between WPX Energy, Inc. and Executive Officers (incorporated herein by reference to Exhibit 10.32 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
|
|
|
|
10.29
|
|
Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Marcia MacLeod (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016) (1)
|
|
|
|
10.30
|
|
Form of Severance and Restrictive Covenant Agreement between WPX Energy, Inc. and Michael Fiser (incorporated herein by reference to Exhibit 10.33 to WPX Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016) (1)
|
|
|
|
10.31
|
|
Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and CEO (incorporated herein by reference to Exhibit 10.1 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 9, 2016) (1)
|
|
|
|
10.32
|
|
Form of Amended and Restated Change in Control Agreement between WPX Energy, Inc. and Tier One Executives (incorporated herein by reference to Exhibit 10.2 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 9, 2016) (1)
|
|
|
|
10.33
|
|
Amended and Restated WPX Energy Executive Severance Pay Plan (incorporated herein by reference to Exhibit 10.3 to WPX Energy, Inc.’s Current Report on Form 8-K filed with the SEC on November 9, 2016) (1)
|
|
|
|
12*
|
|
Statement of Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
21.1*
|
|
List of Subsidiaries
|
|
|
|
23.1*
|
|
Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP
|
|
|
|
23.2*
|
|
Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
|
|
|
|
24.1*
|
|
Powers of Attorney
|
|
|
|
31.1*
|
|
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
31.2*
|
|
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
32.1*
|
|
Certification by the Chief Executive Officer and the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
99.1*
|
|
Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
|
|
|
|
101.INS*
|
|
XBRL Instance Document
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase
|
|
|
|
Exhibit
No.
|
|
Description
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase
|
*
|
Filed herewith
|
**
|
All schedules to the Merger Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the SEC upon request.
|
(1)
|
Management contract or compensatory plan or arrangement
|
WPX ENERGY, Inc.
|
|
(Registrant)
|
|
|
|
By:
|
/s/ Stephen L. Faulkner
|
|
Stephen L. Faulkner
Controller
(Principal Accounting Officer)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
||
/s/ Richard E. Muncrief
|
|
President, Chief Executive Officer
and Chairman of the Board
(Principal Executive Officer)
|
|
February 23, 2017
|
|
|
|
||
/s/ J. Kevin Vann
|
|
Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
|
|
February 23, 2017
|
|
|
|
||
/s/ Stephen L. Faulkner
|
|
Controller
(Principal Accounting Officer)
|
|
February 23, 2017
|
|
|
|
||
/s/ John A. Carrig*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ William R. Granberry*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ Robert K. Herdman*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ Kelt Kindick*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ Karl F. Kurz*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ Henry E. Lentz*
|
|
Director
|
|
February 23, 2017
|
|
|
|
|
|
/s/ George A. Lorch*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ William G. Lowrie*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ Kimberly S. Lubel*
|
|
Director
|
|
February 23, 2017
|
|
|
|
||
/s/ David F. Work*
|
|
Director
|
|
February 23, 2017
|
|
|
|
|
|
|
|
|
|
/s/ Stephen E. Brilz
|
|
|
|
|
*By:
|
|
Attorney-in-Fact
|
|
|
|
February 23, 2017
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
|
(Millions)
|
||||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
(937
|
)
|
|
20
|
|
|
404
|
|
|
$
|
(1,572
|
)
|
|
$
|
13
|
|
|||
Less: Equity earnings, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||
Income (loss) from continuing operations before income taxes and equity earnings
|
|
(936
|
)
|
|
21
|
|
|
405
|
|
|
(1,571
|
)
|
|
14
|
|
|||||
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)
|
|
207
|
|
|
187
|
|
|
123
|
|
|
108
|
|
|
102
|
|
|||||
Capitalized Interest
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Rental expense representative of interest factor
|
|
6
|
|
|
5
|
|
|
5
|
|
|
5
|
|
|
4
|
|
|||||
Total fixed charges
|
|
213
|
|
|
193
|
|
|
128
|
|
|
113
|
|
|
107
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capitalized interest
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||
Total earnings as adjusted
|
|
$
|
(723
|
)
|
|
$
|
213
|
|
|
$
|
533
|
|
|
$
|
(1,458
|
)
|
|
$
|
120
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
|
(b)
|
|
|
1.10
|
|
|
4.16
|
|
|
(d)
|
|
|
1.12
|
|
|||||
Preferred stock dividend requirement
|
|
6
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Combined fixed charges and preferred dividends
|
|
219
|
|
|
208
|
|
|
128
|
|
|
113
|
|
|
107
|
|
|||||
Ratio of earnings to combined fixed charges and preferred dividends
|
|
(c)
|
|
|
1.02
|
|
|
4.16
|
|
|
(d)
|
|
|
1.12
|
|
(a)
|
Does not include interest related to income taxes, including interest related to liabilities for uncertain tax positions, which is included in provision (benefit) for income taxes in our Consolidated Statements of Operations.
|
(b)
|
Earnings are inadequate to cover fixed charges by $936 million.
|
(c)
|
Earnings are inadequate to cover combined fixed charges and preferred dividends by $942 million.
|
(d)
|
Earnings are inadequate to cover fixed charges by $1,571 million.
|
1.
|
Betterit Land & Title Holding Company, LLC - a New Mexico Limited Liability Company
|
|
Fictitious name in Oklahoma: WPX Energy Chaco Slope, LLC
|
|
|
2.
|
Cardinal Oil and Gas Holdings, LLC
|
|
DBA in New Mexico and Texas as: Cardinal Exploration & Production, LLC
|
|
|
3.
|
Red Eagle Gathering, LLC
|
|
|
4.
|
RKI Exploration & Production, LLC
|
|
|
5.
|
RW Gathering, LLC
|
|
|
6.
|
Stateline Crude, LLC - an Oklahoma LLC
|
|
|
7.
|
Stateline Gathering, LLC - an Oklahoma LLC
|
|
|
8.
|
Stateline Processing, LLC - an Oklahoma LLC
|
|
|
9.
|
Stateline Water, LLC - an Oklahoma LLC
|
|
|
10.
|
WPX Energy Appalachia, LLC
|
|
|
11.
|
WPX Energy Gulf Coast, LP
|
|
Assumed name in Texas: Williams Prod. Gulf Coast, L.P.
|
|
|
12.
|
WPX Energy Holdings, LLC
|
|
|
13.
|
WPX Energy Keystone, LLC
|
|
|
14.
|
WPX Energy Marketing, LLC
|
|
|
15.
|
WPX Energy Mid-Continent Company, an Oklahoma corporation
|
|
|
16.
|
WPX Energy Production, LLC
|
|
Fictitious name in Oklahoma: WEG-Production Company, LLC
|
|
|
17.
|
WPX Energy RM Company
|
|
|
18.
|
WPX Energy Services Company, LLC
|
|
|
19.
|
WPX Energy Williston, LLC
|
|
Trade name in North Dakota: D3 E & P LLC
|
1.
|
WPX Energy International Oil & Gas (Venezuela), Ltd. – a Cayman Islands corporation
|
(1)
|
Registration Statement (Form S-3 No 333-208552) and related Prospectus of WPX Energy, Inc. pertaining to the registration of 40,000,000 shares of its common stock
|
(2)
|
Registration Statement (Form S-8 No 333-204355) pertaining to the WPX Energy, Inc. 2013 Incentive Plan, as amended effective May 21, 2015
|
(3)
|
Registration Statement (Form S-3 No 333-198523) and the related post-effective amendment No.1 and related Prospectus of WPX Energy, Inc. pertaining to the registration of common stock, preferred stock and debt securities
|
(4)
|
Registration Statement (Form S-3 No 333-197905) and related Prospectus of WPX Energy, Inc. pertaining to the registration of 481,157 shares of its common stock
|
(5)
|
Registration Statement (Form S-8 No 333-188767) pertaining to the WPX Energy, Inc. 2013 Incentive Plan
|
(6)
|
Registration Statement (Form S-8 No 333-178388) and the related post-effective amendment No. 1 pertaining to the WPX Energy, Inc. 2011 Incentive Plan and the WPX Energy, Inc. 2011 Employee Stock Purchase Plan
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
|
|
By:
|
|
/s/ C.H. (Scott) Rees III
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
Chairman and Chief Executive Officer
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
|
|
|
|
|
/s/ John A. Carrig
|
|
|
|
/s/ William R. Granberry
|
John A. Carrig
|
|
|
|
William R. Granberry
|
|
|
|
||
/s/ Robert K. Herdman
|
|
|
|
/s/ Karl F. Kurz
|
Robert K. Herdman
|
|
|
|
Karl F. Kurz
|
|
|
|
||
/s/ Kelt Kindick
|
|
|
|
/s/ Henry E. Lentz
|
Kelt Kindick
|
|
|
|
Henry E. Lentz
|
|
|
|
||
/s/ George A. Lorch
|
|
|
|
/s/ William G. Lowrie
|
George A. Lorch
|
|
|
|
William G. Lowrie
|
|
|
|
||
/s/ Kimberly S. Lubel
|
|
|
|
/s/ David F. Work
|
Kimberly S. Lubel
|
|
|
|
David F. Work
|
|
|
|
|
|
1.
|
I have reviewed this annual report on Form 10-K of WPX Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Richard E. Muncrief
|
Richard E. Muncrief
Chief Executive Officer
|
(Principal Executive Officer)
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ J. Kevin Vann
|
J. Kevin Vann
Chief Financial Officer
|
(Principal Financial Officer)
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Richard E. Muncrief
|
Richard E. Muncrief
Chief Executive Officer
|
February 23, 2017
|
|
/s/ J. Kevin Vann
|
J. Kevin Vann
Senior Vice President and Chief Financial Officer
|
February 23, 2017
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
|||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
|||||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|||||
Proved Developed
|
|
84,296
|
|
|
23,869
|
|
|
402,782
|
|
|
1,397,164
|
|
|
841,374
|
|
Proved Undeveloped
|
|
90,172
|
|
|
25,332
|
|
|
291,560
|
|
|
1,085,431
|
|
|
204,749
|
|
Total Proved
|
|
174,469
|
|
|
49,201
|
|
|
694,342
|
|
|
2,482,596
|
|
|
1,046,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sincerely,
|
||
|
|
|
|
|||||
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
|
|
|
Texas Registered Engineering Firm F-2699
|
||
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
|
|
By:
|
|
|
|
|
|
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
||||
|
|
/s/ Dan Paul Smith
|
|
|
|
|
|
/s/ John G. Hattner
|
By:
|
|
|
|
|
|
By:
|
|
|
|
|
Dan Paul Smith, P.E. 49093
|
|
|
|
|
|
John G. Hattner, P.G. 559
|
|
|
Senior Vice President
|
|
|
|
|
|
Senior Vice President
|
|
|
|
||||||
Date Signed: February 15, 2017
|
|
|
|
Date Signed: February 15, 2017
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
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