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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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SANDRIDGE ENERGY, INC.
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(Exact name of registrant as specified in its charter)
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Delaware
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20-8084793
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
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73102
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(Address of principal executive offices)
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(Zip Code)
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(405) 429-5500
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(Registrant’s telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
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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, $0.001 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
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None
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
þ
(Do not check if smaller reporting company)
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Smaller reporting company
o
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Item
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Page
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PART I
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1.
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1A.
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1B.
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2.
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3.
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4.
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PART II
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5.
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6.
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7.
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7A.
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8.
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9.
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9A.
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9B.
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PART III
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10.
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11.
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12.
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13.
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14.
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PART IV
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15.
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16.
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•
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risks associated with drilling oil and natural gas wells;
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•
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the volatility of oil, natural gas and natural gas liquids (“NGL”) prices;
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•
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uncertainties in estimating oil, natural gas and NGL reserves;
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the need to replace the oil, natural gas and NGL reserves the Company produces;
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our ability to execute its growth strategy by drilling wells as planned;
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the amount, nature and timing of capital expenditures, including future development costs, required to develop our undeveloped areas;
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concentration of operations in the Mid-Continent region of the United States;
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limitations of seismic data;
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the potential adverse effect of commodity price declines on the carrying value of our oil and natural properties;
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severe or unseasonable weather that may adversely affect production;
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availability of satisfactory oil, natural gas and NGL marketing and transportation;
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availability and terms of capital to fund capital expenditures;
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amount and timing of proceeds of asset monetizations;
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potential financial losses or earnings reductions from commodity derivatives;
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potential elimination or limitation of tax incentives;
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competition in the oil and natural gas industry;
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general economic conditions, either internationally or domestically affecting the areas where we operate;
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costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; and
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the need to maintain adequate internal control over financial reporting.
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Estimated Net
Proved
Reserves
(MMBoe)
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Daily
Production
(MBoe/d)(1)
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Reserves/
Production
(Years)(2)
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Gross
Acreage
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Net
Acreage
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Capital Expenditures (In millions) (3)
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Area
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Mid-Continent
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127.8
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42.2
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8.3
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1,185,408
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793,471
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$
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105.6
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Rockies
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30.2
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1.4
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59.1
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140,216
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132,504
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87.4
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Other
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5.9
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1.6
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10.1
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38,785
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23,909
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—
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Total
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163.9
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45.2
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9.9
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1,364,409
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949,884
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$
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193.0
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(1)
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Average daily net production for the month of December
2016
.
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(2)
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Estimated net proved reserves as of
December 31, 2016
divided by production for the month of December
2016
annualized.
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(3)
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Capital expenditures for the year ended
December 31, 2016
on an accrual basis.
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•
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the quality and quantity of available data and the engineering and geological interpretation of that data;
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•
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estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
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•
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the accuracy of economic assumptions such as the future price of oil and natural gas; and
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•
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the judgment of the personnel preparing the estimates.
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•
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the Corporate Reservoir Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:
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•
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confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;
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reviewing and using data provided by other departments within the Company such as Accounting in the estimation process;
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communicating, collaborating, analytical engineering with technical personnel of our business units;
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comparing and reconciling the internally generated reserves estimates to those prepared by third parties.
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reserves estimates are prepared by experienced reservoir engineers or under their direct supervision; and
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•
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no employee’s compensation is tied to the amount of reserves recorded.
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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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Cawley, Gillespie & Associates, Inc.
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72.0
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%
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77.7
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%
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82.4
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%
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Ryder Scott Company, L.P.
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18.4
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%
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8.5
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%
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—
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%
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Netherland, Sewell & Associates, Inc.
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3.6
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%
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3.9
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%
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3.7
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%
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Total
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94.0
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%
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90.1
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%
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86.1
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%
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Geographic Locations—by Area by State
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Cawley, Gillespie & Associates, Inc.
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Mid-Continent—KS, OK
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Ryder Scott Company, L.P.
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Rockies—CO
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Netherland, Sewell & Associates, Inc.
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Permian Basin—TX
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•
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more than 25 years of practical experience in the estimation and evaluation of petroleum reserves;
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•
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a registered professional engineer in the state of Texas; and
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•
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Bachelor of Science Degree in Petroleum Engineering.
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•
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more than 30 years of practical experience in the estimation and evaluation of petroleum reserves;
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•
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a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and
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•
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Bachelor of Science Degree in Petroleum Engineering and MBA in Finance;
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practicing consulting petroleum engineering since 2013 and over 15 years of prior industry experience;
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•
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licensed professional engineers in the state of Texas; and
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•
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Bachelor of Science Degree in Chemical Engineering
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December 31,
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2016
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2015
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2014
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Estimated Proved Reserves(1)
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Developed
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Oil (MMBbls)
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25.9
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48.6
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79.0
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NGL (MMBbls)
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29.3
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51.1
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56.8
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Natural gas (Bcf)
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393.0
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964.6
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1,203.4
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Total proved developed (MMBoe)
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120.7
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260.5
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336.4
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Undeveloped
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Oil (MMBbls)
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27.0
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29.3
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47.0
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NGL (MMBbls)
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4.2
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9.9
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35.0
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Natural gas (Bcf)
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71.8
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149.2
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584.8
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Total proved undeveloped (MMBoe)
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43.2
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64.1
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179.5
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Total Proved
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Oil (MMBbls)
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52.9
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77.9
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126.0
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NGL (MMBbls)
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33.5
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61.0
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91.8
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Natural gas (Bcf)
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464.8
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1,113.8
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1,788.2
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Total proved (MMBoe)(2)
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163.9
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324.6
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515.9
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Standardized Measure of Discounted Net Cash Flows (in millions)(2)(3)
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$
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438.4
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$
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1,315.0
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$
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5,516.4
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PV-10 (in millions)(4)
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$
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438.4
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$
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1,314.6
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$
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4,087.8
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(1)
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Estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using a 12-month unweighted average of the first-day-of-the-month index price for each month of each year, and do not reflect actual prices at
December 31, 2016
or current prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the Company’s reserve reports are shown in the table below.
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Index prices (a)
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Weighted average
wellhead prices (b)
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Oil
(per Bbl) |
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Natural gas
(per Mcf) |
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Oil
(per Bbl)
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NGL (per Bbl)
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Natural gas
(per Mcf)
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December 31, 2016
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$
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39.25
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$
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2.48
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$
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38.59
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|
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$
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10.99
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$
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1.56
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December 31, 2015
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$
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46.79
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$
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2.59
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$
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45.29
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$
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12.68
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|
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$
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1.87
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December 31, 2014
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$
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91.48
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$
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4.35
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$
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91.65
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$
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32.79
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$
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3.61
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(a)
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Index prices are based on average West Texas Intermediate posted prices for oil and average Henry Hub spot market prices for natural gas.
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(b)
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Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.
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(2)
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Estimated total proved reserves and Standardized Measure attributable to noncontrolling interest for the years ended December 31, 2015 and 2014 are shown in the table below.
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(3)
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Standardized Measure represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes. At December 31, 2016, the present value of future income tax discounted at 10% was insignificant due to an excess of tax basis in the full cost pool over projected undiscounted future cash flows.
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(4)
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PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended
December 31, 2016
,
2015
and
2014
. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of our Standardized Measure to PV-10:
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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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||||||
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(In millions)
|
||||||||||
Standardized Measure of Discounted Net Cash Flows
|
$
|
438.4
|
|
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$
|
1,314.6
|
|
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$
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4,087.8
|
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Present value of future income tax discounted at 10%
|
—
|
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0.4
|
|
|
1,428.6
|
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PV-10
|
$
|
438.4
|
|
|
$
|
1,315.0
|
|
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$
|
5,516.4
|
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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
|
||||||
Reserves converted from proved undeveloped to proved developed (MMBoe)
|
6.8
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15.8
|
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31.4
|
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Drilling capital expended to convert proved undeveloped reserves to proved developed reserves (in millions)
|
$
|
64.5
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$
|
117.7
|
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$
|
343.6
|
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Oil
(MBbls)
|
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NGL (MBbls)
|
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Natural Gas
(MMcf)
|
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Total
(MBoe)
|
||||
Year Ended December 31, 2016
|
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|
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Mississippi Lime Horizontal
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5,029
|
|
|
4,357
|
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56,894
|
|
|
18,868
|
|
Niobrara
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
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Mississippi Lime Horizontal
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8,041
|
|
|
4,785
|
|
|
77,542
|
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25,750
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Year Ended December 31, 2014
|
|
|
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Mississippi Lime Horizontal
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8,234
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3,470
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65,839
|
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|
22,677
|
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Successor
|
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Predecessor
|
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Combined
|
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Predecessor
|
||||||||||||
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Period from October 2, 2016 through December 31,
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Period from January 1, 2016 through October 1,
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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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2016
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2016
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2015
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2014
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Production data (in thousands)
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Oil (MBbls)
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1,214
|
|
|
4,315
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|
5,529
|
|
|
9,600
|
|
|
10,876
|
|
|||||
NGL (MBbls)
|
999
|
|
|
3,358
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|
4,357
|
|
|
5,044
|
|
|
3,794
|
|
|||||
Natural gas (MMcf)
|
12,771
|
|
|
44,124
|
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56,895
|
|
|
92,105
|
|
|
85,697
|
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|||||
Total volumes (MBoe)
|
4,342
|
|
|
15,027
|
|
|
19,369
|
|
|
29,995
|
|
|
28,953
|
|
|||||
Average daily total volumes (MBoe/d)
|
47.7
|
|
|
54.6
|
|
|
52.9
|
|
|
82.2
|
|
|
79.3
|
|
|||||
Average prices—as reported(1)
|
|
|
|
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|
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|
||||||||||
Oil (per Bbl)
|
$
|
47.03
|
|
|
$
|
36.85
|
|
|
$
|
39.09
|
|
|
$
|
45.83
|
|
|
$
|
89.86
|
|
NGL (per Bbl)
|
$
|
14.77
|
|
|
$
|
12.67
|
|
|
$
|
13.15
|
|
|
$
|
14.36
|
|
|
$
|
33.41
|
|
Natural gas (per Mcf)
|
$
|
2.07
|
|
|
$
|
1.78
|
|
|
$
|
1.84
|
|
|
$
|
2.12
|
|
|
$
|
3.70
|
|
Total (per Boe)
|
$
|
22.64
|
|
|
$
|
18.63
|
|
|
$
|
19.53
|
|
|
$
|
23.59
|
|
|
$
|
49.08
|
|
(1)
|
Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
|
2016
|
|
2015
|
|
2014
|
||||||||
Expenses per Boe
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
|
|
|
|
|
|
|
|
||||||||
Transportation(1)
|
$
|
—
|
|
|
|
$
|
1.75
|
|
|
$
|
1.51
|
|
|
$
|
1.23
|
|
Processing, treating and gathering
|
0.02
|
|
|
|
0.03
|
|
|
0.88
|
|
|
1.16
|
|
||||
Other lease operating expenses(2)
|
5.67
|
|
|
|
6.71
|
|
|
7.67
|
|
|
9.27
|
|
||||
Total lease operating expenses
|
$
|
5.69
|
|
|
|
$
|
8.49
|
|
|
$
|
10.06
|
|
|
$
|
11.66
|
|
Production taxes(3)
|
$
|
0.61
|
|
|
|
$
|
0.41
|
|
|
$
|
0.51
|
|
|
$
|
1.10
|
|
Ad valorem taxes
|
$
|
0.07
|
|
|
|
$
|
0.14
|
|
|
$
|
0.23
|
|
|
$
|
0.29
|
|
(1)
|
The Successor Company transportation costs are presented as a deduction from revenues. See “Note 3 - Summary of Significant Accounting Policies” to the accompanying consolidated financial statements.
|
(2)
|
The years ended December 31,
2015
and
2014
include
$34.9 million
and
$33.9 million
, respectively, for amounts related to shortfalls in meeting annual CO
2
delivery obligations under a CO
2
treating agreement as described under “—2016 Divestiture and Release from Treating Agreement” above.
|
(3)
|
Net of severance tax refunds.
|
|
Oil
|
|
Natural Gas
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Area
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Mid-Continent
|
1,667
|
|
|
1,032.6
|
|
|
305
|
|
|
146.9
|
|
|
1,972
|
|
|
1,179.5
|
|
Rockies
|
25
|
|
|
25.0
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
25.0
|
|
Other
|
1,125
|
|
|
1,105.5
|
|
|
—
|
|
|
—
|
|
|
1,125
|
|
|
1,105.5
|
|
Total
|
2,817
|
|
|
2,163.1
|
|
|
305
|
|
|
146.9
|
|
|
3,122
|
|
|
2,310.0
|
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||||||||||||||
|
Gross
|
|
Percent
|
|
Net
|
|
Percent
|
|
Gross
|
|
Percent
|
|
Net
|
|
Percent
|
|
Gross
|
|
Percent
|
|
Net
|
|
Percent
|
||||||||||||
Completed Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Productive
|
32
|
|
|
100.0
|
%
|
|
27.0
|
|
|
100.0
|
%
|
|
167
|
|
|
100.0
|
%
|
|
117.0
|
|
|
100.0
|
%
|
|
626
|
|
|
97.5
|
%
|
|
482.3
|
|
|
97.4
|
%
|
Dry
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
16
|
|
|
2.5
|
%
|
|
13.0
|
|
|
2.6
|
%
|
Total
|
32
|
|
|
100.0
|
%
|
|
27.0
|
|
|
100.0
|
%
|
|
167
|
|
|
100.0
|
%
|
|
117.0
|
|
|
100.0
|
%
|
|
642
|
|
|
100.0
|
%
|
|
495.3
|
|
|
100.0
|
%
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Productive
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
9
|
|
|
100.0
|
%
|
|
7.0
|
|
|
100.0
|
%
|
|
6
|
|
|
60.0
|
%
|
|
4.6
|
|
|
60.5
|
%
|
Dry
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
4
|
|
|
40.0
|
%
|
|
3.0
|
|
|
39.5
|
%
|
Total
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
9
|
|
|
100.0
|
%
|
|
7.0
|
|
|
100.0
|
%
|
|
10
|
|
|
100.0
|
%
|
|
7.6
|
|
|
100.0
|
%
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Productive
|
32
|
|
|
100.0
|
%
|
|
27.0
|
|
|
100.0
|
%
|
|
176
|
|
|
100.0
|
%
|
|
124.0
|
|
|
100.0
|
%
|
|
632
|
|
|
96.9
|
%
|
|
486.9
|
|
|
96.8
|
%
|
Dry
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
20
|
|
|
3.1
|
%
|
|
16.0
|
|
|
3.2
|
%
|
Total
|
32
|
|
|
100.0
|
%
|
|
27.0
|
|
|
100.0
|
%
|
|
176
|
|
|
100.0
|
%
|
|
124.0
|
|
|
100.0
|
%
|
|
652
|
|
|
100.0
|
%
|
|
502.9
|
|
|
100.0
|
%
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Area
|
|
|
|
|
|
|
|
||||
Mid-Continent
|
629,965
|
|
|
410,000
|
|
|
555,443
|
|
|
383,471
|
|
Rockies
|
16,366
|
|
|
16,412
|
|
|
123,850
|
|
|
116,092
|
|
Other
|
17,944
|
|
|
14,956
|
|
|
20,841
|
|
|
8,953
|
|
Total
|
664,275
|
|
|
441,368
|
|
|
700,134
|
|
|
508,516
|
|
|
Acres Expiring
|
||||
|
Gross
|
|
Net
|
||
Twelve Months Ending
|
|
|
|
||
December 31, 2017
|
428,349
|
|
|
315,326
|
|
December 31, 2018
|
68,783
|
|
|
43,906
|
|
December 31, 2019
|
37,473
|
|
|
24,505
|
|
December 31, 2020 and later
|
8,161
|
|
|
5,776
|
|
Other(1)
|
157,368
|
|
|
119,003
|
|
Total
|
700,134
|
|
|
508,516
|
|
(1)
|
Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the timing of construction or drilling activities;
|
•
|
the rates of production, or “allowables”;
|
•
|
the use of surface or subsurface waters;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells; and
|
•
|
the notice to surface owners and other third parties.
|
(i)
|
Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
|
•
|
reductions in oil, natural gas and NGL prices;
|
•
|
delays imposed by or resulting from compliance with regulatory requirements including permitting;
|
•
|
unusual or unexpected geological formations and miscalculations;
|
•
|
shortages of or delays in obtaining equipment and qualified personnel;
|
•
|
shortages of or delays in obtaining water for hydraulic fracturing operations;
|
•
|
equipment malfunctions, failures or accidents;
|
•
|
lack of available gathering facilities or delays in construction of gathering facilities;
|
•
|
lack of available capacity on interconnecting transmission pipelines;
|
•
|
lack of adequate electrical infrastructure and water disposal capacity;
|
•
|
unexpected operational events and drilling conditions;
|
•
|
pipe or cement failures and casing collapses;
|
•
|
pressures, fires, blowouts and explosions;
|
•
|
lost or damaged drilling and service tools;
|
•
|
loss of drilling fluid circulation;
|
•
|
uncontrollable flows of oil, natural gas, brine, water or drilling fluids;
|
•
|
natural disasters;
|
•
|
environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
|
•
|
high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;
|
•
|
compliance with environmental and other governmental requirements;
|
•
|
adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;
|
•
|
oil and natural gas property title problems; and
|
•
|
market limitations for oil, natural gas and NGLs.
|
•
|
changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally;
|
•
|
the price and quantity of foreign imports;
|
•
|
the ability of other companies to complete and commission liquefied natural gas export facilities in the U.S.;
|
•
|
U.S. and worldwide political and economic conditions;
|
•
|
the level of global and U.S. inventories;
|
•
|
weather conditions and seasonal trends;
|
•
|
anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
|
•
|
natural disasters and other extraordinary events;
|
•
|
domestic and foreign governmental regulations and taxation;
|
•
|
energy conservation and environmental measures; and
|
•
|
the price and availability of alternative fuels.
|
•
|
the accuracy of our reserve estimates;
|
•
|
the actual cost of development and production expenditures;
|
•
|
the amount and timing of actual production;
|
•
|
supply of and demand for oil, natural gas and NGLs; and
|
•
|
changes in governmental regulation or taxation.
|
•
|
evacuation of personnel and curtailment of operations;
|
•
|
damage to drilling rigs or other facilities, resulting in suspension of operations;
|
•
|
inability to deliver materials to worksites; and
|
•
|
damage to, or shutting in of, pipelines and other transportation facilities.
|
•
|
the prices at which oil, natural gas and NGLs are sold;
|
•
|
our proved reserves;
|
•
|
the level of oil, natural gas and NGLs we are able to produce from existing wells;
|
•
|
our ability to acquire, locate and produce new reserves; and
|
•
|
our capital and operating costs.
|
•
|
production is less than expected;
|
•
|
the counterparty to the derivative contract defaults on its contract obligations; or
|
•
|
the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
High
|
|
Low
|
||||
2016
|
|
|
|
||||
Successor Company
|
|
|
|
||||
Fourth Quarter (from October 4, 2016 through December 31, 2016)
|
$
|
26.85
|
|
|
$
|
15.75
|
|
Predecessor Company
|
|
|
|
||||
Fourth Quarter (through October 3, 2016)
|
$
|
0.02
|
|
|
$
|
0.01
|
|
Third Quarter
|
$
|
0.06
|
|
|
$
|
—
|
|
Second Quarter
|
$
|
0.11
|
|
|
$
|
0.01
|
|
First Quarter
|
$
|
0.20
|
|
|
$
|
0.03
|
|
2015
|
|
|
|
||||
Fourth Quarter
|
$
|
0.56
|
|
|
$
|
0.17
|
|
Third Quarter
|
$
|
0.90
|
|
|
$
|
0.25
|
|
Second Quarter
|
$
|
2.30
|
|
|
$
|
0.81
|
|
First Quarter
|
$
|
2.53
|
|
|
$
|
1.13
|
|
|
Total Number of Shares Purchased(1)
|
|
Average Price
Paid per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Program
|
|
Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (In millions)
|
||||
Period
|
|
|
|
|
|
|
|
||||
October 1, 2016 — October 31, 2016
|
—
|
|
|
$
|
—
|
|
|
N/A
|
|
|
N/A
|
November 1, 2016 — November 30, 2016
|
—
|
|
|
$
|
—
|
|
|
N/A
|
|
|
N/A
|
December 1, 2016 — December 31, 2016
|
4,647
|
|
|
$
|
23.72
|
|
|
N/A
|
|
|
N/A
|
Total
|
4,647
|
|
|
|
|
—
|
|
|
|
(1)
|
Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards. Shares withheld are initially recorded as treasury shares, then immediately retired.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
Statement of Operations Data
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Revenues
|
$
|
98,456
|
|
|
|
$
|
293,809
|
|
|
$
|
768,709
|
|
|
$
|
1,558,758
|
|
|
$
|
1,983,388
|
|
|
$
|
1,934,642
|
|
Total operating expenses(1)
|
434,801
|
|
|
|
1,200,012
|
|
|
5,411,387
|
|
|
968,534
|
|
|
2,152,389
|
|
|
1,609,446
|
|
||||||
(Loss) income from operations
|
(336,345
|
)
|
|
|
(906,203
|
)
|
|
(4,642,678
|
)
|
|
590,224
|
|
|
(169,001
|
)
|
|
325,196
|
|
||||||
Other (expense) income
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
|
(372
|
)
|
|
|
(126,099
|
)
|
|
(321,421
|
)
|
|
(244,109
|
)
|
|
(270,234
|
)
|
|
(303,349
|
)
|
||||||
Bargain purchase gain
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
122,696
|
|
||||||
Gain (loss) on extinguishment of debt
|
—
|
|
|
|
41,179
|
|
|
641,131
|
|
|
—
|
|
|
(82,005
|
)
|
|
(3,075
|
)
|
||||||
Reorganization items
|
—
|
|
|
|
2,430,599
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Other income, net
|
2,744
|
|
|
|
1,332
|
|
|
2,040
|
|
|
3,490
|
|
|
12,445
|
|
|
4,741
|
|
||||||
Total other expense
|
2,372
|
|
|
|
2,347,011
|
|
|
321,750
|
|
|
(240,619
|
)
|
|
(339,794
|
)
|
|
(178,987
|
)
|
||||||
(Loss) income before income taxes
|
(333,973
|
)
|
|
|
1,440,808
|
|
|
(4,320,928
|
)
|
|
349,605
|
|
|
(508,795
|
)
|
|
146,209
|
|
||||||
Income tax expense (benefit)
|
9
|
|
|
|
11
|
|
|
123
|
|
|
(2,293
|
)
|
|
5,684
|
|
|
(100,362
|
)
|
||||||
Net (loss) income
|
(333,982
|
)
|
|
|
1,440,797
|
|
|
(4,321,051
|
)
|
|
351,898
|
|
|
(514,479
|
)
|
|
246,571
|
|
||||||
Less: net (loss) income attributable to noncontrolling interest
|
—
|
|
|
|
—
|
|
|
(623,506
|
)
|
|
98,613
|
|
|
39,410
|
|
|
105,000
|
|
||||||
Net (loss) income attributable to SandRidge Energy, Inc.
|
(333,982
|
)
|
|
|
1,440,797
|
|
|
(3,697,545
|
)
|
|
253,285
|
|
|
(553,889
|
)
|
|
141,571
|
|
||||||
Preferred stock dividends
|
—
|
|
|
|
16,321
|
|
|
37,950
|
|
|
50,025
|
|
|
55,525
|
|
|
55,525
|
|
||||||
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders
|
$
|
(333,982
|
)
|
|
|
$
|
1,424,476
|
|
|
$
|
(3,735,495
|
)
|
|
$
|
203,260
|
|
|
$
|
(609,414
|
)
|
|
$
|
86,046
|
|
(Loss) earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Basic
|
$
|
(17.61
|
)
|
|
|
$
|
2.01
|
|
|
$
|
(7.16
|
)
|
|
$
|
0.42
|
|
|
$
|
(1.27
|
)
|
|
$
|
0.19
|
|
Diluted
|
$
|
(17.61
|
)
|
|
|
$
|
2.01
|
|
|
$
|
(7.16
|
)
|
|
$
|
0.42
|
|
|
$
|
(1.27
|
)
|
|
$
|
0.19
|
|
(1)
|
Includes full cost ceiling limitation impairments of $319.1 million, $657.4 million, $4.5 billion and $164.8 million for the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. No full cost ceiling limitation impairments were recorded for the years ended December 31, 2013 or 2012.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
As of December 31,
|
|
|
As of December 31,
|
||||||||||||||||
|
2016
|
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Balance Sheet Data
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
121,231
|
|
|
|
$
|
435,588
|
|
|
$
|
181,253
|
|
|
$
|
814,663
|
|
|
$
|
309,766
|
|
Property, plant and equipment, net
|
$
|
817,932
|
|
|
|
$
|
2,234,702
|
|
|
$
|
6,215,057
|
|
|
$
|
6,307,675
|
|
|
$
|
8,479,977
|
|
Total assets(1)
|
$
|
1,081,392
|
|
|
|
$
|
2,922,027
|
|
|
$
|
7,211,823
|
|
|
$
|
7,630,307
|
|
|
$
|
9,716,787
|
|
Total debt(1)
|
$
|
305,308
|
|
|
|
$
|
3,562,378
|
|
|
$
|
3,148,034
|
|
|
$
|
3,140,419
|
|
|
$
|
4,227,139
|
|
Total stockholders’ equity (deficit)
|
$
|
512,917
|
|
|
|
$
|
(1,187,733
|
)
|
|
$
|
3,209,820
|
|
|
$
|
3,175,627
|
|
|
$
|
3,862,455
|
|
Total liabilities and stockholders’ equity (deficit)
|
$
|
1,081,392
|
|
|
|
$
|
2,922,027
|
|
|
$
|
7,211,823
|
|
|
$
|
7,630,307
|
|
|
$
|
9,716,787
|
|
(1)
|
Reflects the reclassification of certain debt issuance costs from other assets to long-term debt of $69.1 million, $47.4 million, $54.5 million and $73.9 million for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, as a result of the retrospective adoption of ASU 2015-03 on January 1, 2016. See “Note 3 - Accounting Policies and Procedures” included in Item 8 of this report for further discussion.
|
•
|
Overview;
|
•
|
Consolidated Results of Operations;
|
•
|
Liquidity and Capital Resources;
|
•
|
Valuation Allowance; and
|
•
|
Critical Accounting Policies and Estimates.
|
•
|
Depreciation, depletion and amortization
|
•
|
Accretion of asset retirement obligations
|
•
|
Impairment
|
•
|
Interest Expense
|
•
|
Net (loss) income
|
•
|
First Lien Credit Agreement.
All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0
|
•
|
Cash Collateral Account.
We deposited
$50.0 million
of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i)
$12.5 million
will be released to us upon delivery of an acceptable business plan to the administrative agent, (ii)
$12.5 million
will be released to us upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to us, up to
$25.0 million
will be released to us upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017. The $50.0 million cash collateral account was subsequently released to us in February 2017 in conjunction with the refinancing of the New First Lien Exit Facility as discussed in “Liquidity and Capital Resources.”
|
•
|
Senior Secured Notes
. All outstanding obligations under the Senior Secured Notes were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of the Successor Company’s Common Stock, (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately
$281.8 million
principal value of New Convertible Notes, which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which was the refinancing of the First Lien Exit Facility.
|
•
|
General Unsecured Claims.
The Predecessor Company’s general unsecured claims, including the 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022, and 7.5% Senior Notes due 2023 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, the “Unsecured Notes”), became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately
5.7 million
shares of New Common Stock,
5.2 million
of which was issued immediately upon emergence, and (c)
4.9 million
Series A Warrants and
2.1 million
Series B Warrants, with initial exercise prices of
$41.34
and
$42.03
per share, respectively, which expire on October 4, 2022, (the “Warrants”). Approximately 4.5 million Series A Warrants and 1.9 million Series B Warrants were issued immediately upon emergence.
|
•
|
New Building Note
. A note with a principal amount of
$35.0 million
($36.6 million fair value on the Emergence Date), which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) was issued and purchased on the Emergence Date for
$26.8 million
in cash, net of certain fees and expenses, by certain holders of the Unsecured Senior Notes.
|
•
|
Preferred and Common Stock.
The Predecessor Company’s
7.0%
and
8.5%
convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof.
|
•
|
Total production for
2016
was comprised of approximately
28.5%
oil,
49.0%
natural gas and
22.5%
NGLs compared to
32.0%
oil,
51.2%
natural gas and
16.8%
NGLs in
2015
.
|
•
|
Reduced the total rigs drilling to
one
at
December 31, 2016
from four at December 31, 2015.
|
•
|
Drilled 16 wells in the Mid-Continent and 10 wells in the Rockies in 2016 compared to drilling 161 wells, excluding salt water disposal wells, in the Mid-Continent and no wells in the Rockies in 2015, respectively.
|
•
|
Discontinued all remaining drilling and oilfield services operations in 2016, and as a result, our drilling and oilfield services operations no longer constituted a reportable segment in 2016.
|
•
|
Transferred substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement between the companies. This resulted in a substantial decrease in our marketing and midstream operations throughout 2016, and accordingly, our midstream and marketing operations no longer constituted a reportable segment at December 31, 2016.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Oil (per Bbl)
|
$
|
43.47
|
|
|
$
|
48.75
|
|
|
$
|
92.91
|
|
|
$
|
98.05
|
|
|
$
|
94.15
|
|
Natural gas (per Mcf)
|
$
|
2.55
|
|
|
$
|
2.62
|
|
|
$
|
4.26
|
|
|
$
|
3.73
|
|
|
$
|
2.83
|
|
|
Year Ended December 31,
|
||
|
2014(1)
|
||
Production (MBoe)
|
1,321
|
|
|
Revenues (in thousands)
|
$
|
90,920
|
|
Expenses (in thousands)
|
$
|
63,674
|
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Production data (in thousands)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbls)
|
1,214
|
|
|
4,315
|
|
|
5,529
|
|
|
9,600
|
|
|
10,876
|
|
|||||
NGL (MBbls)
|
999
|
|
|
3,358
|
|
|
4,357
|
|
|
5,044
|
|
|
3,794
|
|
|||||
Natural gas (MMcf)
|
12,771
|
|
|
44,124
|
|
|
56,895
|
|
|
92,105
|
|
|
85,697
|
|
|||||
Total volumes (MBoe)
|
4,342
|
|
|
15,027
|
|
|
19,369
|
|
|
29,995
|
|
|
28,953
|
|
|||||
Average daily total volumes (MBoe/d)
|
47.7
|
|
|
54.6
|
|
|
52.9
|
|
|
82.2
|
|
|
79.3
|
|
|||||
Average prices—as reported(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
47.03
|
|
|
$
|
36.85
|
|
|
$
|
39.09
|
|
|
$
|
45.83
|
|
|
$
|
89.86
|
|
NGL (per Bbl)
|
$
|
14.77
|
|
|
$
|
12.67
|
|
|
$
|
13.15
|
|
|
$
|
14.36
|
|
|
$
|
33.41
|
|
Natural gas (per Mcf)
|
$
|
2.07
|
|
|
$
|
1.78
|
|
|
$
|
1.84
|
|
|
$
|
2.12
|
|
|
$
|
3.70
|
|
Total (per Boe)
|
$
|
22.64
|
|
|
$
|
18.63
|
|
|
$
|
19.53
|
|
|
$
|
23.59
|
|
|
$
|
49.08
|
|
Average prices—including impact of derivative contract settlements(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (per Bbl)
|
$
|
54.59
|
|
|
$
|
51.05
|
|
|
$
|
51.83
|
|
|
$
|
76.80
|
|
|
$
|
94.18
|
|
NGL (per Bbl)
|
$
|
14.77
|
|
|
$
|
12.67
|
|
|
$
|
13.15
|
|
|
$
|
14.36
|
|
|
$
|
33.41
|
|
Natural gas (per Mcf)
|
$
|
1.96
|
|
|
$
|
1.77
|
|
|
$
|
1.81
|
|
|
$
|
2.45
|
|
|
$
|
3.58
|
|
Total (per Boe)
|
$
|
24.41
|
|
|
$
|
22.70
|
|
|
$
|
23.08
|
|
|
$
|
34.51
|
|
|
$
|
50.36
|
|
(1)
|
Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.
|
(2)
|
Excludes settlements of commodity derivative contracts prior to their contractual maturity, if any.
|
|
Successor
|
|
Predecessor
|
||||||||||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
|
Production (MBoe)
|
|
% of Total Production
|
||||||||
Mid-Continent
|
4,018
|
|
|
92.5
|
%
|
|
14,119
|
|
|
94.0
|
%
|
|
26,558
|
|
|
88.5
|
%
|
|
23,423
|
|
|
80.9
|
%
|
Rockies
|
180
|
|
|
4.1
|
%
|
|
320
|
|
|
2.1
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
Gulf of Mexico / Gulf Coast
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
1,321
|
|
|
4.6
|
%
|
Permian Basin
|
144
|
|
|
3.4
|
%
|
|
489
|
|
|
3.3
|
%
|
|
1,567
|
|
|
5.2
|
%
|
|
2,076
|
|
|
7.2
|
%
|
Other
|
—
|
|
|
—
|
%
|
|
99
|
|
|
0.6
|
%
|
|
1,870
|
|
|
6.3
|
%
|
|
2,133
|
|
|
7.3
|
%
|
Total
|
4,342
|
|
|
100.0
|
%
|
|
15,027
|
|
|
100.0
|
%
|
|
29,995
|
|
|
100.0
|
%
|
|
28,953
|
|
|
100.0
|
%
|
|
Successor
|
|
Predecessor
|
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Combined
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Revenues
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil
|
$
|
57,093
|
|
|
$
|
159,023
|
|
|
$
|
216,116
|
|
|
$
|
439,927
|
|
|
$
|
977,269
|
|
NGL
|
14,756
|
|
|
42,541
|
|
|
57,297
|
|
|
72,440
|
|
|
126,759
|
|
|||||
Natural gas
|
26,458
|
|
|
78,407
|
|
|
104,865
|
|
|
195,067
|
|
|
316,851
|
|
|||||
Other
|
149
|
|
|
13,838
|
|
|
13,987
|
|
|
61,275
|
|
|
137,879
|
|
|||||
Total revenues(1)
|
$
|
98,456
|
|
|
$
|
293,809
|
|
|
$
|
392,265
|
|
|
$
|
768,709
|
|
|
$
|
1,558,758
|
|
(1)
|
Includes
$57.0 million
and
$150.4 million
of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31,
2015
and
2014
, respectively.
|
2014 oil, natural gas and NGL revenues
|
$
|
1,420,879
|
|
Change due to production volumes in 2015
|
(49,143
|
)
|
|
Change due to average prices in 2015
|
(664,302
|
)
|
|
2015 oil, natural gas and NGL revenues
|
707,434
|
|
|
Change due to production volumes in 2016
|
(270,688
|
)
|
|
Change due to average prices in 2016
|
(58,468
|
)
|
|
2016 oil, natural gas and NGL revenues (Supplemental pro forma combined)
|
$
|
378,278
|
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Expenses
|
|
|
|
|
|
|
|
|
|
||||||||||
Production
|
$
|
24,997
|
|
|
$
|
129,608
|
|
|
$
|
154,605
|
|
|
$
|
308,701
|
|
|
$
|
346,088
|
|
Production taxes
|
2,643
|
|
|
6,107
|
|
|
8,750
|
|
|
15,440
|
|
|
31,731
|
|
|||||
Depreciation and depletion—oil and natural gas
|
33,971
|
|
|
86,613
|
|
|
120,584
|
|
|
319,913
|
|
|
434,295
|
|
|||||
Depreciation and amortization—other
|
3,922
|
|
|
21,323
|
|
|
25,245
|
|
|
47,382
|
|
|
59,636
|
|
|||||
Accretion of asset retirement obligations
|
2,090
|
|
|
4,365
|
|
|
6,455
|
|
|
4,477
|
|
|
9,092
|
|
|||||
Impairment
|
319,087
|
|
|
718,194
|
|
|
1,037,281
|
|
|
4,534,689
|
|
|
192,768
|
|
|||||
General and administrative
|
9,837
|
|
|
116,091
|
|
|
125,928
|
|
|
137,715
|
|
|
113,991
|
|
|||||
Employee termination benefits
|
12,334
|
|
|
18,356
|
|
|
30,690
|
|
|
12,451
|
|
|
8,874
|
|
|||||
Loss (gain) on derivative contracts
|
25,652
|
|
|
4,823
|
|
|
30,475
|
|
|
(73,061
|
)
|
|
(334,011
|
)
|
|||||
Loss on settlement of contract
|
—
|
|
|
90,184
|
|
|
90,184
|
|
|
50,976
|
|
|
—
|
|
|||||
Other operating expenses
|
268
|
|
|
4,348
|
|
|
4,616
|
|
|
52,704
|
|
|
106,070
|
|
|||||
Total expenses(1)
|
$
|
434,801
|
|
|
$
|
1,200,012
|
|
|
$
|
1,634,813
|
|
|
$
|
5,411,387
|
|
|
$
|
968,534
|
|
(1)
|
Includes
$679.9 million
and
$51.0 million
of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31,
2015
and
2014
, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs include
$655.9 million
and
$29.9 million
of allocated full cost ceiling impairment for the years ended December 31, 2015 and 2014, respectively.
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Impairment
|
|
|
|
|
|
|
|
|
|
||||||||||
Full cost pool ceiling limitation
|
$
|
319,087
|
|
|
$
|
657,392
|
|
|
$
|
976,479
|
|
|
$
|
4,473,787
|
|
|
$
|
164,779
|
|
Drilling assets
|
—
|
|
|
3,511
|
|
|
3,511
|
|
|
37,646
|
|
|
27,428
|
|
|||||
Electrical transmission system
|
—
|
|
|
55,600
|
|
|
55,600
|
|
|
—
|
|
|
—
|
|
|||||
Midstream assets
|
—
|
|
|
1,691
|
|
|
1,691
|
|
|
7,148
|
|
|
561
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
16,108
|
|
|
—
|
|
|||||
Total impairment
|
$
|
319,087
|
|
|
$
|
718,194
|
|
|
$
|
1,037,281
|
|
|
$
|
4,534,689
|
|
|
$
|
192,768
|
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Other income (expense)
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
(372
|
)
|
|
$
|
(126,099
|
)
|
|
$
|
(126,471
|
)
|
|
$
|
(321,421
|
)
|
|
$
|
(244,109
|
)
|
Gain on extinguishment of debt
|
—
|
|
|
41,179
|
|
|
41,179
|
|
|
641,131
|
|
|
—
|
|
|||||
Reorganization items
|
—
|
|
|
2,430,599
|
|
|
2,430,599
|
|
|
—
|
|
|
—
|
|
|||||
Other income, net
|
2,744
|
|
|
1,332
|
|
|
4,076
|
|
|
2,040
|
|
|
3,490
|
|
|||||
Total other income (expense)
|
2,372
|
|
|
2,347,011
|
|
|
2,349,383
|
|
|
321,750
|
|
|
(240,619
|
)
|
|||||
(Loss) income before income taxes
|
(333,973
|
)
|
|
1,440,808
|
|
|
1,106,835
|
|
|
(4,320,928
|
)
|
|
349,605
|
|
|||||
Income tax expense (benefit)
|
9
|
|
|
11
|
|
|
20
|
|
|
123
|
|
|
(2,293
|
)
|
|||||
Net (loss) income
|
(333,982
|
)
|
|
1,440,797
|
|
|
1,106,815
|
|
|
(4,321,051
|
)
|
|
351,898
|
|
|||||
Less: net (loss) income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(623,506
|
)
|
|
98,613
|
|
|||||
Net (loss) income attributable to SandRidge Energy, Inc.
|
$
|
(333,982
|
)
|
|
$
|
1,440,797
|
|
|
$
|
1,106,815
|
|
|
$
|
(3,697,545
|
)
|
|
$
|
253,285
|
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense on debt
|
$
|
1,590
|
|
|
$
|
123,350
|
|
|
$
|
124,940
|
|
|
$
|
304,020
|
|
|
$
|
254,475
|
|
Amortization of debt issuance costs, premium and discounts
|
(81
|
)
|
|
7,730
|
|
|
7,649
|
|
|
15,014
|
|
|
9,954
|
|
|||||
Write off of debt issuance costs
|
—
|
|
|
—
|
|
|
—
|
|
|
7,108
|
|
|
—
|
|
|||||
(Gain) loss on long-term debt derivatives
|
—
|
|
|
(1,324
|
)
|
|
(1,324
|
)
|
|
10,377
|
|
|
—
|
|
|||||
Capitalized interest
|
—
|
|
|
(2,240
|
)
|
|
(2,240
|
)
|
|
(14,018
|
)
|
|
(19,718
|
)
|
|||||
Total
|
1,509
|
|
|
127,516
|
|
|
129,025
|
|
|
322,501
|
|
|
244,711
|
|
|||||
Less: interest income
|
(1,137
|
)
|
|
(1,417
|
)
|
|
(2,554
|
)
|
|
(1,080
|
)
|
|
(602
|
)
|
|||||
Total interest expense
|
$
|
372
|
|
|
$
|
126,099
|
|
|
$
|
126,471
|
|
|
$
|
321,421
|
|
|
$
|
244,109
|
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Cash flows provided by (used in) operating activities
|
$
|
65,595
|
|
|
$
|
(112,077
|
)
|
|
$
|
(46,482
|
)
|
|
$
|
373,537
|
|
|
$
|
621,114
|
|
Cash flows used in investing activities
|
(39,835
|
)
|
|
(167,690
|
)
|
|
(207,525
|
)
|
|
(1,039,640
|
)
|
|
(857,241
|
)
|
|||||
Cash flows (used in) provided by financing activities
|
(415,061
|
)
|
|
407,551
|
|
|
(7,510
|
)
|
|
920,438
|
|
|
(397,283
|
)
|
|||||
Net (decrease) increase in cash and cash equivalents
|
$
|
(389,301
|
)
|
|
$
|
127,784
|
|
|
$
|
(261,517
|
)
|
|
$
|
254,335
|
|
|
$
|
(633,410
|
)
|
|
Successor
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31,
|
|
Period from January 1, 2016 through October 1,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
|
||||||||||
Exploration and production
|
$
|
38,062
|
|
|
$
|
155,627
|
|
|
$
|
193,689
|
|
|
$
|
656,022
|
|
|
$
|
1,508,100
|
|
Drilling and oilfield services
|
—
|
|
|
23
|
|
|
23
|
|
|
4,632
|
|
|
18,385
|
|
|||||
Midstream services
|
2,901
|
|
|
3,085
|
|
|
5,986
|
|
|
21,556
|
|
|
44,606
|
|
|||||
Other
|
83
|
|
|
2,672
|
|
|
2,755
|
|
|
19,405
|
|
|
37,798
|
|
|||||
Capital expenditures, excluding acquisitions
|
41,046
|
|
|
161,407
|
|
|
202,453
|
|
|
701,615
|
|
|
1,608,889
|
|
|||||
Acquisitions
|
—
|
|
|
1,328
|
|
|
1,328
|
|
|
241,165
|
|
|
18,384
|
|
|||||
Total
|
$
|
41,046
|
|
|
$
|
162,735
|
|
|
$
|
203,781
|
|
|
$
|
942,780
|
|
|
$
|
1,627,273
|
|
First Lien Exit Facility
|
$
|
—
|
|
New Convertible Notes
|
268,780
|
|
|
New Building Note
|
36,528
|
|
|
Total debt
|
$
|
305,308
|
|
•
|
increased the principal amount of commitments to $600.0 million from $425.0 million;
|
•
|
extended the maturity date to March 31, 2020 from February 4, 2020;
|
•
|
borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;
|
•
|
reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to a pricing grid tied to borrowing base utilization of (A) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (B) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum;
|
•
|
reduced the LIBOR floor from 1% to 0%;
|
•
|
eliminated the minimum proved developing producing reserves asset coverage ratio;
|
•
|
removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;
|
•
|
eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and
|
•
|
eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.
|
|
Payments Due by Period
|
||||||||||||||||||
|
Total
|
|
Less than
1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than
5 years
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Long-term debt obligations(1)
|
$
|
322,462
|
|
|
$
|
2,305
|
|
|
$
|
7,545
|
|
|
$
|
312,612
|
|
|
$
|
—
|
|
Third-party drilling rig agreements(2)
|
1,115
|
|
|
1,115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
106,481
|
|
|
66,154
|
|
|
6,785
|
|
|
5,395
|
|
|
28,147
|
|
|||||
Operating leases and other(3)
|
18,187
|
|
|
5,650
|
|
|
7,437
|
|
|
900
|
|
|
4,200
|
|
|||||
Total
|
$
|
448,245
|
|
|
$
|
75,224
|
|
|
$
|
21,767
|
|
|
$
|
318,907
|
|
|
$
|
32,347
|
|
(1)
|
Includes interest on long-term debt (if any) in the years which it will be incurred, and assumes debt principal amounts are outstanding until their latest contractual maturity, with no additional conversions of New Convertible Notes to common stock.
|
(2)
|
Includes drilling contracts with third-party drilling rig operators at specified day or footage rates and termination fees associated with our hydraulic fracturing services agreements. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.
|
(3)
|
Includes the obligation for employee and employer match contributions to the participants of our non-qualified deferred compensation plan for eligible highly compensated employees who elect to defer income exceeding the Internal Revenue Service (“IRS”) annual limitations on qualified 401(k) retirement plans.
|
|
Notional (MBbls)
|
|
Weighted Average
Fixed Price
|
|||
January 2017 - December 2017
|
3,285
|
|
|
$
|
52.24
|
|
January 2018 - December 2018
|
1,825
|
|
|
$
|
55.34
|
|
|
Notional (MMcf)
|
|
Weighted Average
Fixed Price
|
|||
January 2017 - December 2017
|
32,850
|
|
|
$
|
3.20
|
|
January 2018 - December 2018
|
3,650
|
|
|
$
|
3.12
|
|
|
Page(s)
|
|
|
|
/s/ J
AMES
D. B
ENNETT
|
|
/s/ J
ULIAN
B
OTT
|
James D. Bennett
President and Chief Executive Officer
|
|
Julian Bott
Executive Vice President and Chief Financial Officer
|
/s/ PricewaterhouseCoopers LLP
|
|
PricewaterhouseCoopers LLP
|
|
Oklahoma City, Oklahoma
|
|
March 3, 2017
|
|
/s/ PricewaterhouseCoopers LLP
|
|
PricewaterhouseCoopers LLP
|
|
Oklahoma City, Oklahoma
|
|
March 3, 2017
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
$
|
121,231
|
|
|
|
$
|
435,588
|
|
Restricted cash - collateral
|
50,000
|
|
|
|
—
|
|
||
Restricted cash - other
|
2,840
|
|
|
|
—
|
|
||
Accounts receivable, net
|
74,097
|
|
|
|
127,387
|
|
||
Derivative contracts
|
—
|
|
|
|
84,349
|
|
||
Prepaid expenses
|
5,375
|
|
|
|
6,833
|
|
||
Other current assets
|
3,633
|
|
|
|
19,931
|
|
||
Total current assets
|
257,176
|
|
|
|
674,088
|
|
||
Oil and natural gas properties, using full cost method of accounting
|
|
|
|
|
||||
Proved (includes development and project costs excluded from amortization of $16.7 million and $34.6 million at December 31, 2016 and 2015, respectively)
|
840,201
|
|
|
|
12,529,681
|
|
||
Unproved
|
74,937
|
|
|
|
363,149
|
|
||
Less: accumulated depreciation, depletion and impairment
|
(353,030
|
)
|
|
|
(11,149,888
|
)
|
||
|
562,108
|
|
|
|
1,742,942
|
|
||
Other property, plant and equipment, net
|
255,824
|
|
|
|
491,760
|
|
||
Other assets
|
6,284
|
|
|
|
13,237
|
|
||
Total assets
|
$
|
1,081,392
|
|
|
|
$
|
2,922,027
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
116,517
|
|
|
|
$
|
428,417
|
|
Derivative contracts
|
27,538
|
|
|
|
573
|
|
||
Asset retirement obligations
|
66,154
|
|
|
|
8,399
|
|
||
Other current liabilities
|
3,497
|
|
|
|
—
|
|
||
Total current liabilities
|
213,706
|
|
|
|
437,389
|
|
||
Long-term debt
|
305,308
|
|
|
|
3,562,378
|
|
||
Derivative contracts
|
2,176
|
|
|
|
—
|
|
||
Asset retirement obligations
|
40,327
|
|
|
|
95,179
|
|
||
Other long-term obligations
|
6,958
|
|
|
|
14,814
|
|
||
Total liabilities
|
568,475
|
|
|
|
4,109,760
|
|
||
Commitments and contingencies (Note 14)
|
|
|
|
|
||||
Equity
|
|
|
|
|
||||
SandRidge Energy, Inc. stockholders’ equity (deficit)
|
|
|
|
|
||||
Predecessor preferred stock, $0.001 par value, 50,000 shares authorized
|
|
|
|
|
||||
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
|
—
|
|
|
|
3
|
|
||
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
|
—
|
|
|
|
3
|
|
||
Predecessor common stock, $0.001 par value; 1,800,000 shares authorized, 635,584 issued and 633,471 outstanding at December 31, 2015
|
—
|
|
|
|
630
|
|
||
Predecessor additional paid-in capital
|
—
|
|
|
|
5,301,136
|
|
||
Predecessor additional paid-in capital—stockholder receivable
|
—
|
|
|
|
(1,250
|
)
|
||
Predecessor treasury stock, at cost
|
—
|
|
|
|
(5,742
|
)
|
||
Successor common stock, $0.001 par value; 250,000 shares authorized; 21,042 issued and 19,635 outstanding at December 31, 2016
|
20
|
|
|
|
—
|
|
||
Successor warrants
|
88,381
|
|
|
|
—
|
|
||
Successor additional paid-in capital
|
758,498
|
|
|
|
—
|
|
||
Accumulated deficit
|
(333,982
|
)
|
|
|
(6,992,697
|
)
|
||
Total SandRidge Energy, Inc. stockholders’ equity (deficit)
|
512,917
|
|
|
|
(1,697,917
|
)
|
||
Noncontrolling interest
|
—
|
|
|
|
510,184
|
|
||
Total stockholders’ equity (deficit)
|
512,917
|
|
|
|
(1,187,733
|
)
|
||
Total liabilities and stockholders’ equity (deficit)
|
$
|
1,081,392
|
|
|
|
$
|
2,922,027
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Revenues
|
|
|
|
|
|
|
|
|
||||||||
Oil, natural gas and NGL
|
$
|
98,307
|
|
|
|
$
|
279,971
|
|
|
$
|
707,434
|
|
|
$
|
1,420,879
|
|
Other
|
149
|
|
|
|
13,838
|
|
|
61,275
|
|
|
137,879
|
|
||||
Total revenues
|
98,456
|
|
|
|
293,809
|
|
|
768,709
|
|
|
1,558,758
|
|
||||
Expenses
|
|
|
|
|
|
|
|
|
||||||||
Production
|
24,997
|
|
|
|
129,608
|
|
|
308,701
|
|
|
346,088
|
|
||||
Production taxes
|
2,643
|
|
|
|
6,107
|
|
|
15,440
|
|
|
31,731
|
|
||||
Depreciation and depletion—oil and natural gas
|
33,971
|
|
|
|
86,613
|
|
|
319,913
|
|
|
434,295
|
|
||||
Depreciation and amortization—other
|
3,922
|
|
|
|
21,323
|
|
|
47,382
|
|
|
59,636
|
|
||||
Accretion of asset retirement obligations
|
2,090
|
|
|
|
4,365
|
|
|
4,477
|
|
|
9,092
|
|
||||
Impairment
|
319,087
|
|
|
|
718,194
|
|
|
4,534,689
|
|
|
192,768
|
|
||||
General and administrative
|
9,837
|
|
|
|
116,091
|
|
|
137,715
|
|
|
113,991
|
|
||||
Employee termination benefits
|
12,334
|
|
|
|
18,356
|
|
|
12,451
|
|
|
8,874
|
|
||||
Loss (gain) on derivative contracts
|
25,652
|
|
|
|
4,823
|
|
|
(73,061
|
)
|
|
(334,011
|
)
|
||||
Loss on settlement of contract
|
—
|
|
|
|
90,184
|
|
|
50,976
|
|
|
—
|
|
||||
Other operating expenses
|
268
|
|
|
|
4,348
|
|
|
52,704
|
|
|
106,070
|
|
||||
Total expenses
|
434,801
|
|
|
|
1,200,012
|
|
|
5,411,387
|
|
|
968,534
|
|
||||
(Loss) income from operations
|
(336,345
|
)
|
|
|
(906,203
|
)
|
|
(4,642,678
|
)
|
|
590,224
|
|
||||
Other (expense) income
|
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
(372
|
)
|
|
|
(126,099
|
)
|
|
(321,421
|
)
|
|
(244,109
|
)
|
||||
Gain on extinguishment of debt
|
—
|
|
|
|
41,179
|
|
|
641,131
|
|
|
—
|
|
||||
Gain on reorganization items, net
|
—
|
|
|
|
2,430,599
|
|
|
—
|
|
|
—
|
|
||||
Other income, net
|
2,744
|
|
|
|
1,332
|
|
|
2,040
|
|
|
3,490
|
|
||||
Total other income (expense)
|
2,372
|
|
|
|
2,347,011
|
|
|
321,750
|
|
|
(240,619
|
)
|
||||
(Loss) income before income taxes
|
(333,973
|
)
|
|
|
1,440,808
|
|
|
(4,320,928
|
)
|
|
349,605
|
|
||||
Income tax expense (benefit)
|
9
|
|
|
|
11
|
|
|
123
|
|
|
(2,293
|
)
|
||||
Net (loss) income
|
(333,982
|
)
|
|
|
1,440,797
|
|
|
(4,321,051
|
)
|
|
351,898
|
|
||||
Less: net (loss) income attributable to noncontrolling interest
|
—
|
|
|
|
—
|
|
|
(623,506
|
)
|
|
98,613
|
|
||||
Net (loss) income attributable to SandRidge Energy, Inc.
|
(333,982
|
)
|
|
|
1,440,797
|
|
|
(3,697,545
|
)
|
|
253,285
|
|
||||
Preferred stock dividends
|
—
|
|
|
|
16,321
|
|
|
37,950
|
|
|
50,025
|
|
||||
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders
|
$
|
(333,982
|
)
|
|
|
$
|
1,424,476
|
|
|
$
|
(3,735,495
|
)
|
|
$
|
203,260
|
|
(Loss) earnings per share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(17.61
|
)
|
|
|
$
|
2.01
|
|
|
$
|
(7.16
|
)
|
|
$
|
0.42
|
|
Diluted
|
$
|
(17.61
|
)
|
|
|
$
|
2.01
|
|
|
$
|
(7.16
|
)
|
|
$
|
0.42
|
|
Weighted average number of common shares outstanding
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
18,967
|
|
|
|
708,928
|
|
|
521,936
|
|
|
479,644
|
|
||||
Diluted
|
18,967
|
|
|
|
708,928
|
|
|
521,936
|
|
|
499,743
|
|
|
Convertible
Perpetual
Preferred Stock
|
|
Common Stock
|
|
Additional
Paid-In
Capital
|
|
Treasury
Stock
|
|
Accumulated
Deficit
|
|
Non-controlling
Interest
|
|
Total
|
||||||||||||||||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||
Balance at December 31, 2013 - Predecessor
|
7,650
|
|
|
$
|
8
|
|
|
490,290
|
|
|
$
|
483
|
|
|
$
|
5,294,551
|
|
|
$
|
(8,770
|
)
|
|
$
|
(3,460,462
|
)
|
|
$
|
1,349,817
|
|
|
$
|
3,175,627
|
|
Sale of royalty trust units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,091
|
|
|
—
|
|
|
—
|
|
|
18,028
|
|
|
22,119
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(193,807
|
)
|
|
(193,807
|
)
|
|||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,373
|
)
|
|
—
|
|
|
—
|
|
|
(6,373
|
)
|
|||||||
Retirement of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,373
|
)
|
|
6,373
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Stock distributions, net of purchases - retirement plans
|
—
|
|
|
—
|
|
|
206
|
|
|
—
|
|
|
(1,781
|
)
|
|
1,790
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,665
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,665
|
|
|||||||
Stock-based compensation excess tax provision
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|||||||
Payment received on shareholder receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,250
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,250
|
|
|||||||
Issuance of restricted stock awards, net of cancellations
|
—
|
|
|
—
|
|
|
3,311
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Acquisition of ownership interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,074
|
)
|
|
—
|
|
|
—
|
|
|
(656
|
)
|
|
(2,730
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
(27,411
|
)
|
|
(27
|
)
|
|
(111,800
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(111,827
|
)
|
|||||||
Conversion of 6% preferred stock
|
(2,000
|
)
|
|
(2
|
)
|
|
18,423
|
|
|
18
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
253,285
|
|
|
98,613
|
|
|
351,898
|
|
|||||||
Convertible perpetual preferred stock dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50,025
|
)
|
|
—
|
|
|
(50,025
|
)
|
|||||||
Balance at December 31, 2014 - Predecessor
|
5,650
|
|
|
6
|
|
|
484,819
|
|
|
477
|
|
|
5,201,524
|
|
|
(6,980
|
)
|
|
(3,257,202
|
)
|
|
1,271,995
|
|
|
3,209,820
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(138,305
|
)
|
|
(138,305
|
)
|
|||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,428
|
)
|
|
—
|
|
|
—
|
|
|
(2,428
|
)
|
|||||||
Retirement of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,428
|
)
|
|
2,428
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Stock distributions, net of purchases - retirement plans
|
—
|
|
|
—
|
|
|
(1,000
|
)
|
|
—
|
|
|
(916
|
)
|
|
1,238
|
|
|
—
|
|
|
—
|
|
|
322
|
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,123
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,123
|
|
|||||||
Payment received on shareholder receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,250
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,250
|
|
|||||||
Issuance of restricted stock awards, net of cancellations
|
—
|
|
|
—
|
|
|
1,514
|
|
|
5
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Common stock issued for debt
|
—
|
|
|
—
|
|
|
120,881
|
|
|
121
|
|
|
63,178
|
|
|
—
|
|
|
—
|
|
|
|
|
63,299
|
|
||||||||
Conversion of preferred stock to common stock
|
(230
|
)
|
|
—
|
|
|
2,968
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,697,545
|
)
|
|
(623,506
|
)
|
|
(4,321,051
|
)
|
|||||||
Convertible perpetual preferred stock dividends
|
—
|
|
|
—
|
|
|
24,289
|
|
|
24
|
|
|
16,163
|
|
|
—
|
|
|
(37,950
|
)
|
|
—
|
|
|
(21,763
|
)
|
|||||||
Balance at December 31, 2015 - Predecessor
|
5,420
|
|
|
$
|
6
|
|
|
633,471
|
|
|
$
|
630
|
|
|
$
|
5,299,886
|
|
|
$
|
(5,742
|
)
|
|
$
|
(6,992,697
|
)
|
|
$
|
510,184
|
|
|
$
|
(1,187,733
|
)
|
|
Convertible
Perpetual
Preferred Stock
|
|
Common Stock
|
|
Additional
Paid-In
Capital
|
|
Treasury
Stock
|
|
Accumulated
Deficit
|
|
Non-controlling
Interest
|
|
Total
|
||||||||||||||||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||
Balance at December 31, 2015 - Predecessor
|
5,420
|
|
|
$
|
6
|
|
|
633,471
|
|
|
$
|
630
|
|
|
$
|
5,299,886
|
|
|
$
|
(5,742
|
)
|
|
$
|
(6,992,697
|
)
|
|
$
|
510,184
|
|
|
$
|
(1,187,733
|
)
|
Cumulative effect of adoption of ASU 2015-02
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
257,081
|
|
|
(510,205
|
)
|
|
(253,124
|
)
|
|||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|||||||
Retirement of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Stock distributions, net of purchases - retirement plans
|
—
|
|
|
—
|
|
|
603
|
|
|
—
|
|
|
(860
|
)
|
|
524
|
|
|
—
|
|
|
—
|
|
|
(336
|
)
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,102
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,102
|
|
|||||||
Cancellations of restricted stock awards, net of issuance
|
—
|
|
|
—
|
|
|
(2,184
|
)
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Common stock issued for debt
|
—
|
|
|
—
|
|
|
84,390
|
|
|
84
|
|
|
4,325
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,409
|
|
|||||||
Conversion of preferred stock to common stock
|
(173
|
)
|
|
—
|
|
|
2,220
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,440,797
|
|
|
—
|
|
|
1,440,797
|
|
|||||||
Convertible perpetual preferred stock dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,321
|
)
|
|
—
|
|
|
(16,321
|
)
|
|||||||
Balance at October 1, 2016 - Predecessor
|
5,247
|
|
|
6
|
|
|
718,500
|
|
|
718
|
|
|
5,314,405
|
|
|
(5,218
|
)
|
|
(5,311,140
|
)
|
|
(21
|
)
|
|
(1,250
|
)
|
|||||||
Cancellation of Predecessor equity
|
(5,247
|
)
|
|
(6
|
)
|
|
(718,500
|
)
|
|
(718
|
)
|
|
(5,314,405
|
)
|
|
5,218
|
|
|
5,311,140
|
|
|
21
|
|
|
1,250
|
|
|||||||
Balance at October 1, 2016 - Predecessor
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Common Stock
|
|
Warrants
|
|
Additional
Paid-In
Capital
|
|
Treasury
Stock
|
|
Accumulated
Deficit
|
|
Total
|
||||||||||||||||||
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||
Balance at October 1, 2016 - Predecessor
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Issuance of Successor common stock
|
18,932
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
575,144
|
|
|
—
|
|
|
—
|
|
|
575,163
|
|
||||||
Issuance of Successor warrants
|
—
|
|
|
—
|
|
|
6,442
|
|
|
88,382
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
88,382
|
|
||||||
Convertible note premium
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
163,879
|
|
|
—
|
|
|
—
|
|
|
163,879
|
|
||||||
Balance at October 1, 2016 - Predecessor
|
18,932
|
|
|
$
|
19
|
|
|
6,442
|
|
|
$
|
88,382
|
|
|
$
|
739,023
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
827,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Balance at October 1, 2016 - Successor
|
18,932
|
|
|
$
|
19
|
|
|
6,442
|
|
|
$
|
88,382
|
|
|
$
|
739,023
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
827,424
|
|
Issuance of stock awards, net of cancellations
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Common stock issued for debt
|
693
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
13,000
|
|
|
—
|
|
|
—
|
|
|
13,001
|
|
||||||
Common stock issued for warrants
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,581
|
|
|
—
|
|
|
—
|
|
|
6,581
|
|
||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(110
|
)
|
|
—
|
|
|
(110
|
)
|
||||||
Retirement of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(110
|
)
|
|
110
|
|
|
—
|
|
|
—
|
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(333,982
|
)
|
|
(333,982
|
)
|
||||||
Balance at December 31, 2016 - Successor
|
19,635
|
|
|
$
|
20
|
|
|
6,442
|
|
|
$
|
88,381
|
|
|
$
|
758,498
|
|
|
$
|
—
|
|
|
$
|
(333,982
|
)
|
|
$
|
512,917
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
||||||||
Net (loss) income
|
$
|
(333,982
|
)
|
|
|
$
|
1,440,797
|
|
|
$
|
(4,321,051
|
)
|
|
$
|
351,898
|
|
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
|
|
|
|
|
|
|
|
|
||||||||
Provision for doubtful accounts
|
(13,166
|
)
|
|
|
16,704
|
|
|
—
|
|
|
—
|
|
||||
Depreciation, depletion and amortization
|
37,893
|
|
|
|
107,936
|
|
|
367,295
|
|
|
493,931
|
|
||||
Accretion of asset retirement obligations
|
2,090
|
|
|
|
4,365
|
|
|
4,477
|
|
|
9,092
|
|
||||
Impairment
|
319,087
|
|
|
|
718,194
|
|
|
4,534,689
|
|
|
192,768
|
|
||||
Gain on reorganization items, net
|
—
|
|
|
|
(2,442,436
|
)
|
|
—
|
|
|
—
|
|
||||
Debt issuance costs amortization
|
—
|
|
|
|
4,996
|
|
|
11,884
|
|
|
9,425
|
|
||||
Amortization of discount, net of premium, on debt
|
(81
|
)
|
|
|
2,734
|
|
|
3,130
|
|
|
529
|
|
||||
Gain on extinguishment of debt
|
—
|
|
|
|
(41,179
|
)
|
|
(641,131
|
)
|
|
—
|
|
||||
Write off of debt issuance costs
|
—
|
|
|
|
—
|
|
|
7,108
|
|
|
—
|
|
||||
(Gain) loss on debt derivatives
|
—
|
|
|
|
(1,324
|
)
|
|
10,377
|
|
|
—
|
|
||||
Cash paid for early conversion of convertible notes
|
—
|
|
|
|
(33,452
|
)
|
|
(32,741
|
)
|
|
—
|
|
||||
Loss (gain) on derivative contracts
|
25,652
|
|
|
|
4,823
|
|
|
(73,061
|
)
|
|
(334,011
|
)
|
||||
Cash received on settlement of derivative contracts
|
7,698
|
|
|
|
72,608
|
|
|
327,702
|
|
|
11,796
|
|
||||
Loss on settlement of contract
|
—
|
|
|
|
90,184
|
|
|
50,976
|
|
|
—
|
|
||||
Cash paid on settlement of contract
|
—
|
|
|
|
(11,000
|
)
|
|
(24,889
|
)
|
|
—
|
|
||||
Stock-based compensation
|
6,250
|
|
|
|
9,075
|
|
|
18,380
|
|
|
19,994
|
|
||||
Other
|
717
|
|
|
|
(3,260
|
)
|
|
2,842
|
|
|
417
|
|
||||
Changes in operating assets and liabilities increasing (decreasing) cash
|
|
|
|
|
|
|
|
|
||||||||
Deconsolidation of noncontrolling interest
|
—
|
|
|
|
(9,654
|
)
|
|
—
|
|
|
—
|
|
||||
Receivables
|
12,872
|
|
|
|
36,116
|
|
|
201,907
|
|
|
(63,492
|
)
|
||||
Prepaid expenses
|
(1,079
|
)
|
|
|
(5,681
|
)
|
|
1,148
|
|
|
9,549
|
|
||||
Other current assets
|
(260
|
)
|
|
|
(181
|
)
|
|
12,710
|
|
|
3,164
|
|
||||
Other assets and liabilities, net
|
1,505
|
|
|
|
(7,542
|
)
|
|
2,239
|
|
|
(1,132
|
)
|
||||
Accounts payable and accrued expenses
|
990
|
|
|
|
(61,305
|
)
|
|
(86,470
|
)
|
|
(66,492
|
)
|
||||
Asset retirement obligations
|
(591
|
)
|
|
|
(3,595
|
)
|
|
(3,984
|
)
|
|
(16,322
|
)
|
||||
Net cash provided by (used in) operating activities
|
65,595
|
|
|
|
(112,077
|
)
|
|
373,537
|
|
|
621,114
|
|
||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures for property, plant and equipment
|
(51,676
|
)
|
|
|
(186,452
|
)
|
|
(879,201
|
)
|
|
(1,553,332
|
)
|
||||
Acquisitions of assets
|
—
|
|
|
|
(1,328
|
)
|
|
(216,943
|
)
|
|
(18,384
|
)
|
||||
Proceeds from sale of assets
|
11,841
|
|
|
|
20,090
|
|
|
56,504
|
|
|
714,475
|
|
||||
Net cash used in investing activities
|
(39,835
|
)
|
|
|
(167,690
|
)
|
|
(1,039,640
|
)
|
|
(857,241
|
)
|
||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
||||||||
Proceeds from borrowings
|
—
|
|
|
|
489,198
|
|
|
2,065,000
|
|
|
—
|
|
||||
Repayments of borrowings
|
(414,954
|
)
|
|
|
(74,243
|
)
|
|
(939,466
|
)
|
|
—
|
|
||||
Debt issuance costs
|
—
|
|
|
|
(333
|
)
|
|
(53,244
|
)
|
|
(3,947
|
)
|
||||
Proceeds from building mortgage
|
—
|
|
|
|
26,847
|
|
|
—
|
|
|
—
|
|
||||
Payment of mortgage proceeds and cash recovery to debt holders
|
—
|
|
|
|
(33,874
|
)
|
|
—
|
|
|
—
|
|
||||
Proceeds from the sale of royalty trust units
|
—
|
|
|
|
—
|
|
|
—
|
|
|
22,119
|
|
||||
Noncontrolling interest distributions
|
—
|
|
|
|
—
|
|
|
(138,305
|
)
|
|
(193,807
|
)
|
||||
Purchase of treasury stock
|
(110
|
)
|
|
|
(44
|
)
|
|
(3,535
|
)
|
|
(8,702
|
)
|
||||
Repurchase of common stock
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(111,827
|
)
|
||||
Dividends paid—preferred
|
—
|
|
|
|
—
|
|
|
(11,262
|
)
|
|
(55,525
|
)
|
||||
Cash paid on settlement of financing derivative contracts
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(44,128
|
)
|
||||
Other
|
3
|
|
|
|
—
|
|
|
1,250
|
|
|
(1,466
|
)
|
||||
Net cash (used in) provided by financing activities
|
(415,061
|
)
|
|
|
407,551
|
|
|
920,438
|
|
|
(397,283
|
)
|
||||
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH
|
(389,301
|
)
|
|
|
127,784
|
|
|
254,335
|
|
|
(633,410
|
)
|
||||
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year
|
563,372
|
|
|
|
435,588
|
|
|
181,253
|
|
|
814,663
|
|
||||
CASH, CASH EQUIVALENTS and RESTRICTED CASH end of year
|
$
|
174,071
|
|
|
|
$
|
563,372
|
|
|
$
|
435,588
|
|
|
$
|
181,253
|
|
•
|
First Lien Credit Agreement.
All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and claims under the senior credit facility received their proportionate share of (a)
$35.0 million
in cash and (b) participation in the newly established
$425.0 million
reserve-based revolving credit facility (the “New First Lien Exit Facility”). Refer to Note
11
for additional information.
|
•
|
Cash Collateral Account.
The Company deposited
$50.0 million
of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i)
$12.5 million
will be released to the Company upon delivery of an acceptable business plan to the administrative agent, (ii)
$12.5 million
will be released to the Company upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to the Company, up to
$25.0 million
will be released to the Company upon meeting a minimum
2.00
:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017.
|
•
|
Senior Secured Notes
. All outstanding obligations under the
8.75%
Senior Secured Notes due 2020 issued in June 2015 and the
$78.0 million
principal
8.75%
Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC (“PGC) in October 2015, (the “PGC Senior Secured Notes”) (collectively, “Senior Secured Notes”) were canceled and exchanged for approximately
13.7 million
of the
18.9 million
shares of common stock in the Successor Company (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately
$281.8 million
principal amount of newly issued, non-interest bearing
0.00%
convertible senior subordinated notes due 2020, (the “New Convertible Notes”), which are mandatorily convertible into approximately
15.0 million
shares of New Common Stock upon the first to occur of several triggering events, one of which is refinancing of the New First Lien Exit Facility. Refer to Note
11
and Note
15
for additional information.
|
•
|
General Unsecured Claims.
The Company’s general unsecured claims, including the
8.75%
Senior Notes due 2020,
7.5%
Senior Notes due 2021,
8.125%
Senior Notes due 2022, and
7.5%
Senior Notes due 2023 (collectively, the “Senior Unsecured Notes”) and the
8.125%
Convertible Senior Notes due 2022 and
7.5%
Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, the “Unsecured Notes”), became entitled to receive their proportionate share of (a) approximately
$36.7 million
in cash, (b) approximately
5.7 million
shares of New Common Stock,
5.2 million
of which was issued immediately upon emergence, and (c)
4.9 million
Series A Warrants,
4.5 million
issued immediately upon emergence, and
2.1 million
Series B Warrants,
1.9 million
|
•
|
New Building Note
. A note with a principal amount of
$35.0 million
, which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) was issued and purchased on the emergence date for
$26.8 million
in cash, net of certain fees and expenses, by certain holders of the Unsecured Senior Notes. Refer to Note
11
for additional information.
|
•
|
Preferred and Common Stock.
The Company’s existing
7.0%
and
8.5%
convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof. Refer to Note
15
for additional information.
|
Enterprise value
|
|
$
|
1,089,808
|
|
Plus: Cash and cash equivalents
|
|
563,372
|
|
|
Less: Fair value of New Building Note
|
|
(36,610
|
)
|
|
Less: Asset retirement obligation
|
|
(92,412
|
)
|
|
Less: Fair value of New First Lien Exit Facility
|
|
(414,954
|
)
|
|
Less: Fair value of New Convertible Notes
|
|
(445,660
|
)
|
|
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims
|
|
(95,794
|
)
|
|
Fair value of Successor common stock issued upon emergence
|
|
$
|
567,750
|
|
|
|
|
||
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims
|
|
19,371
|
|
|
Per share value
|
|
$
|
29.31
|
|
Enterprise value
|
|
$
|
1,089,808
|
|
Plus: cash and cash equivalents
|
|
563,372
|
|
|
Plus: other working capital liabilities
|
|
131,766
|
|
|
Plus: other long-term liabilities
|
|
8,549
|
|
|
Reorganization value of Successor assets
|
|
$
|
1,793,495
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
||||||||
ASSETS
|
|
|
|
|
|
|
|
||||||||
Current assets
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
652,680
|
|
|
$
|
(142,148
|
)
|
(1)
|
$
|
—
|
|
|
$
|
510,532
|
|
Restricted cash - collateral
|
—
|
|
|
50,000
|
|
(2)
|
—
|
|
|
50,000
|
|
||||
Restricted cash - other
|
—
|
|
|
2,840
|
|
(2)
|
—
|
|
|
2,840
|
|
||||
Accounts receivable, net
|
61,446
|
|
|
12,356
|
|
(3)
|
—
|
|
|
73,802
|
|
||||
Derivative contracts
|
10,192
|
|
|
—
|
|
|
(669
|
)
|
(12)
|
9,523
|
|
||||
Prepaid expenses
|
12,514
|
|
|
(8,218
|
)
|
(4)
|
—
|
|
|
4,296
|
|
||||
Other current assets
|
1,003
|
|
|
—
|
|
|
3,217
|
|
(13)
|
4,220
|
|
||||
Total current assets
|
737,835
|
|
|
(85,170
|
)
|
|
2,548
|
|
|
655,213
|
|
||||
Oil and natural gas properties, using full cost method of accounting
|
|
|
|
|
|
|
|
||||||||
Proved
|
12,093,492
|
|
|
—
|
|
|
(11,344,684
|
)
|
(14)
|
748,808
|
|
||||
Unproved
|
322,580
|
|
|
—
|
|
|
(205,578
|
)
|
(14)
|
117,002
|
|
||||
Less: accumulated depreciation, depletion and impairment
|
(11,637,538
|
)
|
|
—
|
|
|
11,637,538
|
|
(14)
|
—
|
|
||||
|
778,534
|
|
|
—
|
|
|
87,276
|
|
|
865,810
|
|
||||
Other property, plant and equipment, net
|
357,528
|
|
|
(41
|
)
|
|
(93,782
|
)
|
(15)
|
263,705
|
|
||||
Derivative contracts
|
70
|
|
|
—
|
|
|
(70
|
)
|
(12)
|
—
|
|
||||
Other assets
|
12,537
|
|
|
(3,770
|
)
|
(5)
|
—
|
|
|
8,767
|
|
||||
Total assets
|
$
|
1,886,504
|
|
|
$
|
(88,981
|
)
|
|
$
|
(4,028
|
)
|
|
$
|
1,793,495
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
||||||||
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
|
|
|
|
|
|
|
||||||||
Accounts payable and accrued expenses
|
$
|
140,448
|
|
|
$
|
(14,820
|
)
|
(6)
|
$
|
—
|
|
|
$
|
125,628
|
|
Derivative contracts
|
2,982
|
|
|
—
|
|
|
1,666
|
|
(12)
|
4,648
|
|
||||
Asset retirement obligations
|
8,573
|
|
|
—
|
|
|
57,105
|
|
(16)
|
65,678
|
|
||||
Total current liabilities
|
152,003
|
|
|
(14,820
|
)
|
|
58,771
|
|
|
195,954
|
|
||||
Long-term debt
|
—
|
|
|
731,735
|
|
(7)
|
1,610
|
|
(17)
|
733,345
|
|
||||
Derivative contracts
|
935
|
|
|
—
|
|
|
304
|
|
(12)
|
1,239
|
|
||||
Asset retirement obligations
|
62,896
|
|
|
—
|
|
|
(36,161
|
)
|
(16)
|
26,735
|
|
||||
Other long-term obligations
|
3
|
|
|
8,798
|
|
(8)
|
(3
|
)
|
|
8,798
|
|
||||
Liabilities subject to compromise
|
4,346,188
|
|
|
(4,346,188
|
)
|
(9)
|
—
|
|
|
—
|
|
||||
Total liabilities
|
4,562,025
|
|
|
(3,620,475
|
)
|
|
24,521
|
|
|
966,071
|
|
||||
Equity
|
|
|
|
|
|
|
|
||||||||
SandRidge Energy, Inc. stockholders’ equity (deficit)
|
|
|
|
|
|
|
|
||||||||
Predecessor preferred stock
|
6
|
|
|
—
|
|
|
(6
|
)
|
(18)
|
—
|
|
||||
Predecessor common stock
|
718
|
|
|
—
|
|
|
(718
|
)
|
(18)
|
—
|
|
||||
Predecessor additional paid-in capital
|
5,315,655
|
|
|
—
|
|
|
(5,315,655
|
)
|
(18)
|
—
|
|
||||
Predecessor additional paid-in capital—stockholder receivable
|
(1,250
|
)
|
|
1,250
|
|
(10)
|
—
|
|
|
—
|
|
||||
Predecessor treasury stock, at cost
|
(5,218
|
)
|
|
—
|
|
|
5,218
|
|
(18)
|
—
|
|
||||
Successor common stock
|
—
|
|
|
19
|
|
(11)
|
—
|
|
|
19
|
|
||||
Successor warrants
|
—
|
|
|
88,382
|
|
(11)
|
—
|
|
|
88,382
|
|
||||
Successor additional paid-in capital
|
—
|
|
|
739,023
|
|
(11)
|
—
|
|
|
739,023
|
|
||||
Accumulated deficit
|
(7,985,411
|
)
|
|
2,702,820
|
|
(9)
|
5,282,591
|
|
(19)
|
—
|
|
||||
Total SandRidge Energy, Inc. stockholders’ (deficit) equity
|
(2,675,500
|
)
|
|
3,531,494
|
|
|
(28,570
|
)
|
|
827,424
|
|
||||
Noncontrolling interest
|
(21
|
)
|
|
—
|
|
|
21
|
|
(20)
|
—
|
|
||||
Total stockholders’ (deficit) equity
|
(2,675,521
|
)
|
|
3,531,494
|
|
|
(28,549
|
)
|
|
827,424
|
|
||||
Total liabilities and stockholders’ equity (deficit)
|
$
|
1,886,504
|
|
|
$
|
(88,981
|
)
|
|
$
|
(4,028
|
)
|
|
$
|
1,793,495
|
|
1.
|
Reflects the net cash payments made upon emergence (in thousands):
|
Sources:
|
|
|
||
Proceeds from New Building Note
|
|
$
|
26,847
|
|
Total sources
|
|
$
|
26,847
|
|
|
|
|
||
Uses and transfers:
|
|
|
||
Cash transferred to restricted accounts (collateral and general unsecured claims)
|
|
$
|
52,840
|
|
Payments and funding of escrow account related to professional fees
|
|
43,770
|
|
|
Payment on Senior Credit facility (principal and interest)
|
|
35,238
|
|
|
Repayment of Senior Secured Notes and Unsecured Notes
|
|
33,874
|
|
|
Payment of certain contract cures and other
|
|
3,273
|
|
|
Total uses and transfers
|
|
168,995
|
|
|
Net uses and transfers
|
|
$
|
(142,148
|
)
|
2.
|
Funding of
$50.0 million
Cash Collateral account and the funding of
$2.8 million
to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.
|
3.
|
Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.
|
4.
|
Write-off of prepaid expenses primarily related to
$7.5 million
of prepaid premium for the Predecessor Company’s directors and officers insurance policy.
|
5.
|
Application of a
$3.8 million
deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.
|
6.
|
Includes a
$43.8 million
decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.
|
7.
|
Principal balances of
$35.0 million
of the New Building Note,
$281.8 million
of the New Convertible Notes, and the
$415.0 million
drawn on the New First Lien Exit Facility.
|
8.
|
Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.
|
9.
|
Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):
|
Current maturities of long-term debt and accrued interest
|
|
$
|
4,179,483
|
|
Accounts payable and accrued expenses
|
|
157,422
|
|
|
Other long-term liabilities
|
|
9,283
|
|
|
Liabilities subject to compromise of the Predecessor
|
|
4,346,188
|
|
|
|
|
|
||
Cash payments at emergence
|
|
(72,385
|
)
|
|
Cash proceeds from building mortgage
|
|
26,847
|
|
|
Write-off of prepaid accounts upon emergence
|
|
(8,218
|
)
|
|
Accrual for future reimbursement from professional fees escrow account and other receivables
|
|
12,356
|
|
|
|
|
|
||
Total consideration given pursuant to the Plan:
|
|
|
||
Fair value of equity issued
|
|
(827,424
|
)
|
|
Principal value of long-term debt issued and reinstated at emergence
|
|
(731,735
|
)
|
|
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses
|
|
(37,789
|
)
|
|
Release of stockholder receivable
|
|
(1,250
|
)
|
|
Application of deposit held by utility services
|
|
(3,770
|
)
|
|
Gain on settlement of liabilities subject to compromise
|
|
$
|
2,702,820
|
|
10.
|
Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.
|
11.
|
The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):
|
Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)
|
|
$
|
19
|
|
Fair value of warrants issued to holders of the Unsecured Notes(1)
|
|
88,382
|
|
|
Additional paid in capital - New Common Stock
|
|
575,144
|
|
|
Additional paid in capital - premium on New Convertible Notes(2)
|
|
163,879
|
|
|
Total Successor Company equity issued on Emergence Date
|
|
$
|
827,424
|
|
(1)
|
The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of
$41.34
and
$42.03
for Warrant classes A and B, respectively; expected volatility of
59.26%
; risk free interest rate, continuously compounded, of
1.36%
; and holding period of
six
years.
|
(2)
|
The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of
56.06%
; risk free interest rate, continuously compounded, of
1.08%
; recovery rate of
15.00%
; hazard rate of
12.41%
; drop on default of
100.00%
; and termination period after
four
years. The premium is the difference between the fair value of the New Convertible Notes of
$445.7 million
and the principal value of the New Convertible Notes of
$281.8 million
.
|
12.
|
Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.
|
13.
|
Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.
|
14.
|
Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.
|
15.
|
Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.
|
16.
|
Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.
|
17.
|
Fair value adjustment to record premium on the New Building Note.
|
18.
|
Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.
|
19.
|
Adjustment to reset retained deficit to
zero
.
|
20.
|
Elimination of the Predecessor non-controlling interest.
|
Unamortized long-term debt
|
|
$
|
3,546,847
|
|
Litigation claims
|
|
(20,478
|
)
|
|
Rejections and cures of executory contracts
|
|
(16,038
|
)
|
|
Ad valorem and franchise taxes
|
|
(3,494
|
)
|
|
Legal and professional fees and expenses
|
|
(44,920
|
)
|
|
Write off of director and officer insurance policy
|
|
(7,533
|
)
|
|
Gain on accounts payable settlements
|
|
84,228
|
|
|
Loss on mortgage
|
|
(8,153
|
)
|
|
Gain on preferred stock dividends
|
|
37,893
|
|
|
Fresh start valuation adjustments
|
|
(28,549
|
)
|
|
Fair value of equity issued
|
|
(827,424
|
)
|
|
Principal value of New Convertible Notes issued
|
|
(281,780
|
)
|
|
Gain on reorganization items, net
|
|
$
|
2,430,599
|
|
|
Sales
|
|
% of Revenue
|
|||
Period from October 2, 2016 through December 31, 2016 - Successor
|
|
|
|
|||
Targa Pipeline Mid-Continent West OK LLC
|
$
|
35,845
|
|
|
36.4
|
%
|
Plains Marketing, L.P.
|
$
|
32,022
|
|
|
32.5
|
%
|
|
|
|
|
|||
|
|
|
|
|||
Period from January 1, 2016 through October 1, 2016 - Predecessor
|
|
|
|
|||
Plains Marketing, L.P.
|
$
|
110,370
|
|
|
37.6
|
%
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
108,238
|
|
|
36.8
|
%
|
|
|
|
|
|||
December 31, 2015 - Predecessor
|
|
|
|
|||
Plains Marketing, L.P.
|
$
|
318,018
|
|
|
41.4
|
%
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
231,649
|
|
|
30.1
|
%
|
|
|
|
|
|||
December 31, 2014 - Predecessor
|
|
|
|
|||
Plains Marketing, L.P.
|
$
|
597,117
|
|
|
38.3
|
%
|
Targa Pipeline Mid-Continent West OK LLC
|
$
|
333,027
|
|
|
21.4
|
%
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
||||||||
Cash paid for reorganization items
|
$
|
—
|
|
|
|
$
|
(55,606
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Cash paid for interest, net of amounts capitalized
|
$
|
(1,183
|
)
|
|
|
$
|
(104,609
|
)
|
|
$
|
(296,386
|
)
|
|
$
|
(235,793
|
)
|
Cash (paid) received for income taxes
|
$
|
—
|
|
|
|
$
|
(28
|
)
|
|
$
|
(88
|
)
|
|
$
|
1,928
|
|
|
|
|
|
|
|
|
|
|
||||||||
Supplemental Disclosure of Noncash Investing and Financing Activities
|
|
|
|
|
|
|
|
|
||||||||
Cumulative effect of adoption of ASU 2015-02
|
$
|
—
|
|
|
|
$
|
(247,566
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Property, plant and equipment transferred in settlement of contract
|
$
|
—
|
|
|
|
$
|
215,635
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Change in accrued capital expenditures
|
$
|
10,630
|
|
|
|
$
|
25,045
|
|
|
$
|
177,586
|
|
|
$
|
(55,557
|
)
|
Equity issued for debt
|
$
|
(13,001
|
)
|
|
|
$
|
(4,409
|
)
|
|
$
|
(63,299
|
)
|
|
$
|
—
|
|
Preferred stock dividends paid in common stock
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(16,188
|
)
|
|
$
|
—
|
|
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(50,310
|
)
|
|
$
|
—
|
|
Level 1
|
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
|
|
|
|
Level 2
|
|
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
|
|
|
|
Level 3
|
|
Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (
i.e.,
supported by little or no market activity).
|
Unobservable Input
|
|
Range
|
|
Weighted Average
|
|
Fair Value
|
|||||||
|
|
|
|
(In thousands)
|
|||||||||
Debt conversion feature hazard rate
|
|
114.0
|
%
|
–
|
135.2
|
%
|
|
119.2
|
%
|
|
$
|
29,355
|
|
|
Fair Value Measurements
|
|
Netting(1)
|
|
Assets/Liabilities at Fair Value
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Investments
|
$
|
7,541
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,541
|
|
|
$
|
7,541
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,541
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
$
|
—
|
|
|
$
|
29,714
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
29,714
|
|
|
$
|
—
|
|
|
$
|
29,714
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
29,714
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
Netting(1)
|
|
Assets/Liabilities at Fair Value
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
$
|
—
|
|
|
$
|
85,524
|
|
|
$
|
—
|
|
|
$
|
(1,175
|
)
|
|
$
|
84,349
|
|
Investments
|
10,106
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,106
|
|
|||||
|
$
|
10,106
|
|
|
$
|
85,524
|
|
|
$
|
—
|
|
|
$
|
(1,175
|
)
|
|
$
|
94,455
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative contracts
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,748
|
|
|
$
|
(1,175
|
)
|
|
$
|
573
|
|
Debt holder conversion feature
|
—
|
|
|
—
|
|
|
29,355
|
|
|
—
|
|
|
29,355
|
|
|||||
Mandatory prepayment feature - PGC Senior Secured Notes
|
—
|
|
|
2,941
|
|
|
—
|
|
|
—
|
|
|
2,941
|
|
|||||
|
$
|
—
|
|
|
$
|
2,941
|
|
|
$
|
31,103
|
|
|
$
|
(1,175
|
)
|
|
$
|
32,869
|
|
|
|
Predecessor
|
||||||
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
||||
Beginning balance
|
|
$
|
29,355
|
|
|
$
|
—
|
|
Issuances
|
|
—
|
|
|
31,200
|
|
||
(Loss) gain on derivative holder conversion feature
|
|
(880
|
)
|
|
10,198
|
|
||
Conversions
|
|
(21,194
|
)
|
|
(12,043
|
)
|
||
Write off of derivative holder conversion feature to reorganization items
|
|
(7,281
|
)
|
|
—
|
|
||
Ending level 3 debt holder conversion feature balance
|
|
$
|
—
|
|
|
$
|
29,355
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
December 31, 2016
|
|
|
December 31, 2015
|
||||||||||||
|
Fair Value
|
|
Carrying Value
|
|
|
Fair Value
|
|
Carrying Value
|
||||||||
New Convertible Notes
|
$
|
334,800
|
|
|
$
|
268,780
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
New Building Note
|
$
|
40,608
|
|
|
$
|
36,528
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
8.75% Senior Secured Notes due 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
403,098
|
|
|
$
|
1,265,814
|
|
Senior Unsecured Notes
|
|
|
|
|
|
|
|
|
||||||||
8.75% Senior Notes due 2020
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
39,740
|
|
|
$
|
389,232
|
|
7.5% Senior Notes due 2021
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
79,812
|
|
|
$
|
751,087
|
|
8.125% Senior Notes due 2022
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
57,749
|
|
|
$
|
518,693
|
|
7.5% Senior Notes due 2023
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
58,799
|
|
|
534,869
|
|
|
Convertible Senior Unsecured Notes
|
|
|
|
|
|
|
|
|
||||||||
8.125% Convertible Senior Notes due 2022
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
44,199
|
|
|
$
|
78,290
|
|
7.5% Convertible Senior Notes due 2023
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
15,125
|
|
|
$
|
24,393
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
Oil, natural gas and NGL sales
|
$
|
42,631
|
|
|
|
$
|
61,140
|
|
Joint interest billing
|
17,338
|
|
|
|
60,403
|
|
||
Oil and natural gas services
|
736
|
|
|
|
2,417
|
|
||
Other
|
14,272
|
|
|
|
8,274
|
|
||
Total accounts receivable
|
74,977
|
|
|
|
132,234
|
|
||
Less: allowance for doubtful accounts
|
(880
|
)
|
|
|
(4,847
|
)
|
||
Total accounts receivable, net
|
$
|
74,097
|
|
|
|
$
|
127,387
|
|
|
Successor
|
|
|
|
|
Predecessor
|
||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Beginning balance
|
$
|
—
|
|
|
|
$
|
4,847
|
|
|
$
|
7,083
|
|
|
$
|
11,061
|
|
Additions charged to costs and expenses(1)
|
880
|
|
|
|
16,695
|
|
|
1,320
|
|
|
818
|
|
||||
Deductions(2)
|
—
|
|
|
|
(751
|
)
|
|
(3,556
|
)
|
|
(4,796
|
)
|
||||
Impact of fresh start accounting
|
—
|
|
|
|
(20,791
|
)
|
|
—
|
|
|
—
|
|
||||
Ending balance
|
$
|
880
|
|
|
|
$
|
—
|
|
|
$
|
4,847
|
|
|
$
|
7,083
|
|
(1)
|
The Predecessor 2016 Period includes an addition for a joint interest account receivable after a determination that future collection was doubtful.
|
(2)
|
Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in
2015
are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in
2014
are related to the sale of the Gulf Properties.
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
Oil and natural gas properties
|
|
|
|
|
||||
Proved(1)
|
$
|
840,201
|
|
|
|
$
|
12,529,681
|
|
Unproved
|
74,937
|
|
|
|
363,149
|
|
||
Total oil and natural gas properties
|
915,138
|
|
|
|
12,892,830
|
|
||
Less accumulated depreciation, depletion and impairment
|
(353,030
|
)
|
|
|
(11,149,888
|
)
|
||
Net oil and natural gas properties capitalized costs
|
562,108
|
|
|
|
1,742,942
|
|
||
Land
|
5,100
|
|
|
|
14,260
|
|
||
Non-oil and natural gas equipment(2)
|
166,010
|
|
|
|
373,687
|
|
||
Buildings and structures(3)
|
88,603
|
|
|
|
227,673
|
|
||
Total
|
259,713
|
|
|
|
615,620
|
|
||
Less accumulated depreciation and amortization
|
(3,889
|
)
|
|
|
(123,860
|
)
|
||
Other property, plant and equipment, net
|
255,824
|
|
|
|
491,760
|
|
||
Total property, plant and equipment, net
|
$
|
817,932
|
|
|
|
$
|
2,234,702
|
|
(1)
|
No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately
$48.9 million
at December 31, 2015.
|
(2)
|
No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately
$4.3 million
at December 31, 2015.
|
(3)
|
No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately
$20.4 million
at December 31, 2015.
|
|
|
|
Year Cost Incurred
|
||||||||||||||||
|
Total
|
|
2016
|
|
2015
|
|
2014
|
|
2013 and Prior
|
||||||||||
Property acquisition
|
$
|
71,171
|
|
|
$
|
7,390
|
|
|
$
|
18,959
|
|
|
$
|
34,770
|
|
|
$
|
10,052
|
|
Exploration(1)
|
20,459
|
|
|
2,123
|
|
|
10,578
|
|
|
4,678
|
|
|
3,080
|
|
|||||
Total costs incurred
|
$
|
91,630
|
|
|
$
|
9,513
|
|
|
$
|
29,537
|
|
|
$
|
39,448
|
|
|
$
|
13,132
|
|
(1)
|
Includes
$16.7 million
of pipe inventory costs incurred (
$2.1 million
in
2016
,
$9.6 million
in
2015
and
$5.0 million
in
2014
and prior years).
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Full cost pool ceiling limitation(1)(2)(3)
|
|
$
|
319,087
|
|
|
|
$
|
657,392
|
|
|
$
|
4,473,787
|
|
|
$
|
164,779
|
|
Drilling assets(4)
|
|
—
|
|
|
|
3,511
|
|
|
37,646
|
|
|
27,428
|
|
||||
Electrical transmission assets(5)
|
|
—
|
|
|
|
55,600
|
|
|
—
|
|
|
—
|
|
||||
Midstream assets(6)
|
|
—
|
|
|
|
1,691
|
|
|
7,148
|
|
|
561
|
|
||||
Other(7)
|
|
—
|
|
|
|
—
|
|
|
16,108
|
|
|
—
|
|
||||
|
|
$
|
319,087
|
|
|
|
$
|
718,194
|
|
|
$
|
4,534,689
|
|
|
$
|
192,768
|
|
(1)
|
Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting. Upon the application of fresh start accounting, the value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment.
|
(2)
|
Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.
|
(3)
|
Impairment in 2014 resulted from the divestiture of the Gulf Properties.
|
(4)
|
Impairment recorded in the Predecessor 2016 Period and the year ended December 31, 2015, resulted from discontinued drilling operations in its Permian region which resulted in an impairment on certain drilling assets after determining their future use was limited. During 2014, the Company recorded a
$24.3 million
impairment on its drilling and oilfield services assets in the Permian region as a result of fulfilling its drilling obligation with the Permian Trust in 2014 and the downward trend in oil prices that began in the second half of 2014.
|
(5)
|
Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.
|
(6)
|
Impairment in the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO
2
”) compressor station after determining that their future use was limited.
|
(7)
|
Impairment recorded on other assets in 2015, includes a
$15.4 million
impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
Accounts payable and other accrued expenses
|
$
|
65,408
|
|
|
|
$
|
231,697
|
|
Accrued interest
|
648
|
|
|
|
73,320
|
|
||
Production payable
|
16,011
|
|
|
|
55,260
|
|
||
Payroll and benefits
|
33,606
|
|
|
|
42,728
|
|
||
Convertible perpetual preferred stock dividends
|
—
|
|
|
|
21,572
|
|
||
Drilling advances
|
844
|
|
|
|
2,295
|
|
||
Related party
|
—
|
|
|
|
1,545
|
|
||
Total accounts payable and accrued expenses
|
$
|
116,517
|
|
|
|
$
|
428,417
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31,
|
|
|
December 31,
|
||||
|
2016
|
|
|
2015
|
||||
New First Lien Exit Facility
|
$
|
—
|
|
|
|
$
|
—
|
|
New Convertible Notes
|
268,780
|
|
|
|
—
|
|
||
New Building Note
|
36,528
|
|
|
|
—
|
|
||
Senior credit facility
|
—
|
|
|
|
—
|
|
||
8.75% Senior Secured Notes due 2020
|
—
|
|
|
|
1,265,814
|
|
||
Senior Unsecured Notes
|
|
|
|
|
||||
8.75% Senior Notes due 2020
|
—
|
|
|
|
389,232
|
|
||
7.5% Senior Notes due 2021
|
—
|
|
|
|
751,087
|
|
||
8.125% Senior Notes due 2022
|
—
|
|
|
|
518,693
|
|
||
7.5% Senior Notes due 2023
|
—
|
|
|
|
534,869
|
|
||
Convertible Senior Unsecured Notes
|
|
|
|
|
||||
8.125% Convertible Senior Notes due 2022
|
—
|
|
|
|
78,290
|
|
||
7.5% Convertible Senior Notes due 2023
|
—
|
|
|
|
24,393
|
|
||
Total debt
|
305,308
|
|
|
|
3,562,378
|
|
||
Less: current maturities of long-term debt
|
—
|
|
|
|
—
|
|
||
Long-term debt
|
$
|
305,308
|
|
|
|
$
|
3,562,378
|
|
|
|
Gross Amounts
|
|
Gross Amounts Offset
|
|
Amounts Net of Offset
|
|
Financial Collateral
|
|
Net Amount
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Derivative contracts - current
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Derivative contracts - noncurrent
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Derivative contracts - current
|
|
$
|
27,538
|
|
|
$
|
—
|
|
|
$
|
27,538
|
|
|
$
|
(27,538
|
)
|
|
$
|
—
|
|
Derivative contracts - noncurrent
|
|
2,176
|
|
|
—
|
|
|
2,176
|
|
|
(2,176
|
)
|
|
—
|
|
|||||
Total
|
|
$
|
29,714
|
|
|
$
|
—
|
|
|
$
|
29,714
|
|
|
$
|
(29,714
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts
|
|
Gross Amounts Offset
|
|
Amounts Net of Offset
|
|
Financial Collateral
|
|
Net Amount
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Derivative contracts - current
|
|
$
|
85,524
|
|
|
$
|
(1,175
|
)
|
|
$
|
84,349
|
|
|
$
|
—
|
|
|
$
|
84,349
|
|
Derivative contracts - noncurrent
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
85,524
|
|
|
$
|
(1,175
|
)
|
|
$
|
84,349
|
|
|
$
|
—
|
|
|
$
|
84,349
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Derivative contracts - current
|
|
$
|
1,748
|
|
|
$
|
(1,175
|
)
|
|
$
|
573
|
|
|
$
|
(573
|
)
|
|
$
|
—
|
|
Derivative contracts - noncurrent
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
1,748
|
|
|
$
|
(1,175
|
)
|
|
$
|
573
|
|
|
$
|
(573
|
)
|
|
$
|
—
|
|
|
Notional (MBbls)
|
|
Weighted Average
Fixed Price
|
|||
January 2017 - December 2017
|
3,285
|
|
|
$
|
52.24
|
|
January 2018 - December 2018
|
1,825
|
|
|
$
|
55.34
|
|
|
Notional (MMcf)
|
|
Weighted Average
Fixed Price
|
|||
January 2017 - December 2017
|
32,850
|
|
|
$
|
3.20
|
|
January 2018 - December 2018
|
3,650
|
|
|
$
|
3.12
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||
|
|
|
|
December 31,
|
|
|
December 31,
|
||||
Type of Contract
|
|
Balance Sheet Classification
|
|
2016
|
|
|
2015
|
||||
Derivative assets
|
|
|
|
|
|
|
|
||||
Oil price swaps
|
|
Derivative contracts - current
|
|
$
|
—
|
|
|
|
$
|
68,224
|
|
Oil collars—three way
|
|
Derivative contracts - current
|
|
—
|
|
|
|
17,300
|
|
||
Derivative liabilities
|
|
|
|
|
|
|
|
||||
Oil price swaps
|
|
Derivative contracts - current
|
|
(13,395
|
)
|
|
|
—
|
|
||
Natural gas price swaps
|
|
Derivative contracts - current
|
|
(14,143
|
)
|
|
|
—
|
|
||
Natural gas basis swaps
|
|
Derivative contracts - current
|
|
—
|
|
|
|
(1,748
|
)
|
||
Debt holder conversion feature
|
|
Current maturities of long-term debt
|
|
—
|
|
|
|
(29,355
|
)
|
||
Mandatory prepayment feature - PGC Senior Secured Notes
|
|
Current maturities of long-term debt
|
|
—
|
|
|
|
(2,941
|
)
|
||
Oil price swaps
|
|
Derivative contracts - noncurrent
|
|
(2,105
|
)
|
|
|
—
|
|
||
Natural gas price swaps
|
|
Derivative contracts - noncurrent
|
|
(71
|
)
|
|
|
—
|
|
||
Total net derivative contracts
|
|
$
|
(29,714
|
)
|
|
|
$
|
51,480
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Beginning balance
|
$
|
92,413
|
|
|
|
$
|
103,578
|
|
|
$
|
54,402
|
|
|
$
|
424,117
|
|
Liability incurred upon acquiring and drilling wells
|
121
|
|
|
|
505
|
|
|
1,662
|
|
|
4,968
|
|
||||
Revisions in estimated cash flows(1)
|
12,397
|
|
|
|
—
|
|
|
44,060
|
|
|
(5,848
|
)
|
||||
Liability settled or disposed in current period(2)
|
(540
|
)
|
|
|
(36,979
|
)
|
|
(1,023
|
)
|
|
(377,927
|
)
|
||||
Accretion
|
2,090
|
|
|
|
4,365
|
|
|
4,477
|
|
|
9,092
|
|
||||
Impact of fresh start accounting
|
—
|
|
|
|
20,944
|
|
|
—
|
|
|
—
|
|
||||
Ending balance
|
106,481
|
|
|
|
92,413
|
|
|
103,578
|
|
|
54,402
|
|
||||
Less: current portion
|
66,154
|
|
|
|
65,678
|
|
|
8,399
|
|
|
—
|
|
||||
Asset retirement obligations, net of current
|
$
|
40,327
|
|
|
|
$
|
26,735
|
|
|
$
|
95,179
|
|
|
$
|
54,402
|
|
(1)
|
Revisions for the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives.
|
(2)
|
Liability settled or disposed for the Predecessor 2016 Period includes
$34.1 million
associated with the WTO Properties sold in January 2016. Liability settled or disposed for the year ended December 31, 2014, includes
$366.0 million
associated with the Gulf Properties sold in February 2014. For further discussion of the sale of properties see Note
5
.
|
•
|
the securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;
|
•
|
the recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and
|
•
|
the securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.
|
|
|
Convertible Perpetual Preferred Stock
|
||||||
|
|
8.5%
|
|
7.0%
|
||||
Liquidation preference per share
|
|
$
|
100.00
|
|
|
$
|
100.00
|
|
Annual dividend per share
|
|
$
|
8.50
|
|
|
$
|
7.00
|
|
Conversion rate per share to common stock
|
|
12.4805
|
|
|
12.8791
|
|
|
|
Predecessor
|
||||||||||
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||
8.5% Convertible perpetual preferred stock
|
|
|
|
|
|
|
||||||
Dividends paid in cash
|
|
$
|
—
|
|
|
$
|
11,262
|
|
|
$
|
22,525
|
|
Dividends satisfied in shares of common stock(1)
|
|
$
|
—
|
|
|
$
|
11,262
|
|
|
$
|
—
|
|
Accrued dividends at period end
|
|
$
|
—
|
|
|
$
|
8,447
|
|
|
$
|
8,447
|
|
Dividends in arrears
|
|
$
|
11,262
|
|
|
$
|
—
|
|
|
$
|
—
|
|
7.0% Convertible perpetual preferred stock
|
|
|
|
|
|
|
||||||
Dividends paid in cash
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
21,000
|
|
Dividends satisfied in shares of common stock(2)
|
|
$
|
—
|
|
|
$
|
10,500
|
|
|
$
|
—
|
|
Accrued dividends at period end
|
|
$
|
—
|
|
|
$
|
13,125
|
|
|
$
|
2,625
|
|
Dividends in arrears
|
|
$
|
21,000
|
|
|
$
|
10,500
|
|
|
$
|
—
|
|
6.0% Convertible perpetual preferred stock
|
|
|
|
|
|
|
||||||
Dividends paid in cash
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12,000
|
|
Accrued dividends at period end
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
For the year ended
December 31, 2015
, the Company paid a semi-annual dividend by issuing approximately
18.6 million
shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as
95%
of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately
$9.5 million
, (
$3.58
per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately
$1.8 million
, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.
|
(2)
|
For the year ended
December 31, 2015
, the Company paid a semi-annual dividend by issuing approximately
5.7 million
shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as
95%
of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately
$6.7 million
, (
$2.23
per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately
$3.8 million
, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.
|
|
|
Predecessor
|
||||||||||
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||
Number of shares withheld for taxes
|
|
1,122
|
|
|
1,872
|
|
|
1,034
|
|
|||
Value of shares withheld for taxes
|
|
$
|
44
|
|
|
$
|
2,428
|
|
|
$
|
6,373
|
|
|
Number of
Shares
|
|
Weighted-
Average Grant
Date Fair Value
|
|||
|
(In thousands)
|
|
|
|||
Unvested restricted shares outstanding at October 1, 2016
|
—
|
|
|
$
|
—
|
|
Granted
|
1,448
|
|
|
$
|
24.32
|
|
Vested
|
(14
|
)
|
|
$
|
24.32
|
|
Forfeited / Canceled
|
(27
|
)
|
|
$
|
24.32
|
|
Unvested restricted shares outstanding at December 31, 2016
|
1,407
|
|
|
$
|
24.32
|
|
|
Number of
Shares
|
|
Weighted-
Average Grant
Date Fair Value
|
|||
|
(In thousands)
|
|
|
|||
Unvested restricted shares outstanding at December 31, 2013
|
7,643
|
|
|
$
|
6.92
|
|
Granted
|
6,367
|
|
|
$
|
6.17
|
|
Vested
|
(3,432
|
)
|
|
$
|
7.04
|
|
Forfeited / Canceled
|
(2,022
|
)
|
|
$
|
6.60
|
|
Unvested restricted shares outstanding at December 31, 2014
|
8,556
|
|
|
$
|
6.39
|
|
Granted
|
2,928
|
|
|
$
|
0.88
|
|
Vested
|
(5,186
|
)
|
|
$
|
4.95
|
|
Forfeited / Canceled
|
(672
|
)
|
|
$
|
6.38
|
|
Unvested restricted shares outstanding at December 31, 2015
|
5,626
|
|
|
$
|
4.85
|
|
Granted
|
—
|
|
|
$
|
—
|
|
Vested
|
(3,034
|
)
|
|
$
|
5.34
|
|
Forfeited / Canceled
|
(2,592
|
)
|
|
$
|
4.31
|
|
Predecessor ending unvested restricted shares at October 1, 2016
|
—
|
|
|
$
|
—
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Current
|
|
|
|
|
|
|
|
|
||||||||
Federal
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,160
|
)
|
State
|
9
|
|
|
|
11
|
|
|
123
|
|
|
(1,133
|
)
|
||||
|
9
|
|
|
|
11
|
|
|
123
|
|
|
(2,293
|
)
|
||||
Deferred
|
|
|
|
|
|
|
|
|
||||||||
Federal
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
State
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total provision (benefit)
|
9
|
|
|
|
11
|
|
|
123
|
|
|
(2,293
|
)
|
||||
Less: income tax provision attributable to noncontrolling interest
|
—
|
|
|
|
—
|
|
|
90
|
|
|
283
|
|
||||
Total provision (benefit) attributable to SandRidge Energy, Inc.
|
$
|
9
|
|
|
|
$
|
11
|
|
|
$
|
33
|
|
|
$
|
(2,576
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Computed at federal statutory rate
|
$
|
(116,891
|
)
|
|
|
$
|
504,283
|
|
|
$
|
(1,512,325
|
)
|
|
$
|
122,362
|
|
State taxes, net of federal benefit
|
(3,696
|
)
|
|
|
10,512
|
|
|
(19,988
|
)
|
|
4,145
|
|
||||
Non-deductible expenses
|
144
|
|
|
|
462
|
|
|
816
|
|
|
1,895
|
|
||||
Non-deductible debt costs
|
—
|
|
|
|
22,694
|
|
|
10,228
|
|
|
—
|
|
||||
Stock-based compensation
|
306
|
|
|
|
5,884
|
|
|
6,700
|
|
|
1,467
|
|
||||
Net effects of consolidating the non-controlling interests’ tax provisions
|
—
|
|
|
|
—
|
|
|
218,196
|
|
|
(34,614
|
)
|
||||
Discharge of debt and other reorganization related items
|
—
|
|
|
|
359,278
|
|
|
—
|
|
|
—
|
|
||||
Change in valuation allowance
|
120,144
|
|
|
|
(903,102
|
)
|
|
1,296,405
|
|
|
(96,769
|
)
|
||||
Other
|
2
|
|
|
|
—
|
|
|
1
|
|
|
(1,062
|
)
|
||||
Total provision (benefit) attributable to SandRidge Energy, Inc.
|
$
|
9
|
|
|
|
$
|
11
|
|
|
$
|
33
|
|
|
$
|
(2,576
|
)
|
|
Successor
|
|
|
Predecessor
|
||||
|
December 31, 2016
|
|
|
December 31, 2015
|
||||
Deferred tax liabilities
|
|
|
|
|
||||
Investments(1)
|
$
|
275,128
|
|
|
|
$
|
138,310
|
|
Derivative contracts
|
—
|
|
|
|
30,989
|
|
||
Long-term debt
|
—
|
|
|
|
10,017
|
|
||
Total deferred tax liabilities
|
275,128
|
|
|
|
179,316
|
|
||
Deferred tax assets
|
|
|
|
|
||||
Property, plant and equipment
|
751,683
|
|
|
|
807,275
|
|
||
Derivative contracts
|
11,274
|
|
|
|
—
|
|
||
Allowance for doubtful accounts
|
1,487
|
|
|
|
18,702
|
|
||
Net operating loss carryforwards
|
527,079
|
|
|
|
1,190,799
|
|
||
Compensation and benefits
|
14,494
|
|
|
|
18,607
|
|
||
Alternative minimum tax credits and other carryforwards
|
43,770
|
|
|
|
44,302
|
|
||
Asset retirement obligations
|
40,399
|
|
|
|
38,314
|
|
||
CO
2
under-delivery shortfall penalty
|
—
|
|
|
|
40,654
|
|
||
Other
|
4,663
|
|
|
|
4,305
|
|
||
Total deferred tax assets
|
1,394,849
|
|
|
|
2,162,958
|
|
||
Valuation allowance
|
(1,119,721
|
)
|
|
|
(1,983,642
|
)
|
||
Net deferred tax liability
|
$
|
—
|
|
|
|
$
|
—
|
|
(1)
|
Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
||||||
Unrecognized tax benefit at January 1
|
$
|
81
|
|
|
|
$
|
81
|
|
|
$
|
77
|
|
Changes to unrecognized tax benefits related to a prior year
|
3
|
|
|
|
—
|
|
|
4
|
|
|||
Unrecognized tax benefit at December 31
|
$
|
84
|
|
|
|
$
|
81
|
|
|
$
|
81
|
|
|
Net (Loss) Income
|
|
Weighted Average Shares
|
|
(Loss) Earnings Per Share
|
|||||
|
(In thousands, except per share amounts)
|
|||||||||
Period from October 2, 2016 to December 31, 2016 (Successor)
|
|
|
|
|
|
|||||
Basic loss per share
|
$
|
(333,982
|
)
|
|
18,967
|
|
|
$
|
(17.61
|
)
|
Effect of dilutive securities
|
|
|
|
|
|
|||||
Restricted stock(1)
|
—
|
|
|
—
|
|
|
|
|||
Warrants(1)
|
—
|
|
|
—
|
|
|
|
|||
New Convertible Notes(2)
|
—
|
|
|
—
|
|
|
|
|||
Diluted loss per share
|
$
|
(333,982
|
)
|
|
18,967
|
|
|
$
|
(17.61
|
)
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|||||
Period from January 1, 2016 to October 1, 2016 (Predecessor)
|
|
|
|
|
|
|||||
Basic earnings per share
|
$
|
1,424,476
|
|
|
708,928
|
|
|
$
|
2.01
|
|
Effect of dilutive securities
|
|
|
|
|
|
|||||
Restricted stock and units(3)
|
—
|
|
|
—
|
|
|
|
|||
Diluted earnings per share
|
$
|
1,424,476
|
|
|
708,928
|
|
|
$
|
2.01
|
|
Year Ended December 31, 2015 (Predecessor)
|
|
|
|
|
|
|||||
Basic loss per share
|
$
|
(3,735,495
|
)
|
|
521,936
|
|
|
$
|
(7.16
|
)
|
Effect of dilutive securities
|
|
|
|
|
|
|||||
Restricted stock and units(3)
|
—
|
|
|
—
|
|
|
|
|||
Convertible preferred stock(4)
|
—
|
|
|
—
|
|
|
|
|||
Convertible senior unsecured notes(5)
|
—
|
|
|
—
|
|
|
|
|||
Diluted loss per share
|
$
|
(3,735,495
|
)
|
|
521,936
|
|
|
$
|
(7.16
|
)
|
Year Ended December 31, 2014 (Predecessor)
|
|
|
|
|
|
|||||
Basic earnings per share
|
$
|
203,260
|
|
|
479,644
|
|
|
$
|
0.42
|
|
Effect of dilutive securities
|
|
|
|
|
|
|||||
Restricted stock
|
—
|
|
|
2,181
|
|
|
|
|||
Convertible preferred stock(4)
|
6,500
|
|
|
17,918
|
|
|
|
|||
Diluted earnings per share
|
$
|
209,760
|
|
|
499,743
|
|
|
$
|
0.42
|
|
(1)
|
No
incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive.
|
(2)
|
Potential common shares related to the New Convertible Notes covering
14.6 million
shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.
|
(3)
|
No
incremental shares of potentially dilutive restricted stock awards or units were included for the Predecessor 2016 Period and the year ended
December 31, 2015
as their effect was antidilutive under the treasury stock method.
|
(4)
|
Potential common shares related to the Predecessor Company’s then-outstanding
8.5%
and
7.0%
convertible perpetual preferred stock covering
71.2 million
and
71.7 million
shares for the years ended
December 31, 2015
and
2014
, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.
|
(5)
|
Potential common shares related to the Predecessor Company’s then-outstanding
8.125%
and
7.5%
Convertible Senior Unsecured Notes covering
48.5 million
shares for the year ended
December 31, 2015
were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.
|
•
|
increased the principal amount of commitments to
$600.0 million
from
$425.0 million
;
|
•
|
extended the maturity date to March 31, 2020 from February 4, 2020;
|
•
|
borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;
|
•
|
reduced the interest rate from a flat base rate of LIBOR plus
4.75%
per annum to a pricing grid tied to borrowing base utilization of (A) LIBOR plus an applicable margin that varies from
3.00%
to
4.00%
per annum, or (B) the base rate plus an applicable margin that varies from
2.00%
to
3.00%
per annum;
|
•
|
reduced the LIBOR floor from
1%
to
0%
;
|
•
|
eliminated the minimum proved developing producing reserves asset coverage ratio;
|
•
|
removed the requirement to maintain
$50.0 million
in a cash collateral account controlled by the administrative agent;
|
•
|
eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and
|
•
|
eliminated certain negative covenants, such as the
$20.0 million
liquidity requirement and the limitation on capital expenditures.
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
December 31,
|
|
|
December 31,
|
||||||||
|
2016
|
|
|
2015
|
|
2014
|
||||||
Oil and natural gas properties
|
|
|
|
|
|
|
||||||
Proved
|
$
|
840,201
|
|
|
|
$
|
12,529,681
|
|
|
$
|
11,707,147
|
|
Unproved
|
74,937
|
|
|
|
363,149
|
|
|
290,596
|
|
|||
Total oil and natural gas properties
|
915,138
|
|
|
|
12,892,830
|
|
|
11,997,743
|
|
|||
Less accumulated depreciation, depletion and impairment
|
(353,030
|
)
|
|
|
(11,149,888
|
)
|
|
(6,359,149
|
)
|
|||
Net oil and natural gas properties capitalized costs
|
$
|
562,108
|
|
|
|
$
|
1,742,942
|
|
|
$
|
5,638,594
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Acquisitions of properties
|
|
|
|
|
|
|
|
|
||||||||
Proved
|
$
|
5,142
|
|
|
|
$
|
3,897
|
|
|
$
|
35,376
|
|
|
$
|
73,370
|
|
Unproved
|
5,491
|
|
|
|
1,899
|
|
|
210,065
|
|
|
123,649
|
|
||||
Exploration(1)
|
—
|
|
|
|
1,234
|
|
|
29,297
|
|
|
41,070
|
|
||||
Development
|
27,429
|
|
|
|
149,924
|
|
|
571,562
|
|
|
1,288,395
|
|
||||
Total cost incurred
|
$
|
38,062
|
|
|
|
$
|
156,954
|
|
|
$
|
846,300
|
|
|
$
|
1,526,484
|
|
(1)
|
Includes seismic costs of
$7.1 million
and
$10.8 million
for the years ended December 31,
2015
and
2014
, respectively.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Revenues
|
$
|
98,307
|
|
|
|
$
|
279,971
|
|
|
$
|
707,434
|
|
|
$
|
1,420,879
|
|
Expenses
|
|
|
|
|
|
|
|
|
||||||||
Production costs
|
27,640
|
|
|
|
135,715
|
|
|
324,141
|
|
|
377,819
|
|
||||
Depreciation and depletion
|
33,971
|
|
|
|
86,613
|
|
|
319,913
|
|
|
434,295
|
|
||||
Accretion of asset retirement obligations
|
2,090
|
|
|
|
4,365
|
|
|
4,477
|
|
|
9,092
|
|
||||
Impairment
|
319,087
|
|
|
|
657,392
|
|
|
4,473,787
|
|
|
164,779
|
|
||||
Total expenses
|
382,788
|
|
|
|
884,085
|
|
|
5,122,318
|
|
|
985,985
|
|
||||
(Loss) income before income taxes
|
(284,481
|
)
|
|
|
(604,114
|
)
|
|
(4,414,884
|
)
|
|
434,894
|
|
||||
Income tax expense (benefit)(1)
|
8
|
|
|
|
(5
|
)
|
|
126
|
|
|
(2,852
|
)
|
||||
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)
|
$
|
(284,489
|
)
|
|
|
$
|
(604,109
|
)
|
|
$
|
(4,415,010
|
)
|
|
$
|
437,746
|
|
(1)
|
Reflects the Company’s effective tax rate for each period.
|
•
|
the quality and quantity of available data and the engineering and geological interpretation of that data;
|
•
|
estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
|
•
|
the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and
|
•
|
the judgment of the personnel preparing the estimates.
|
|
Oil
|
|
NGL
|
|
Natural Gas
|
|||
|
(MBbls)
|
|
(MBbls)
|
|
(MMcf)(1)
|
|||
Proved developed and undeveloped reserves
|
|
|
|
|
|
|||
As of December 31, 2013 - Predecessor
|
142,641
|
|
|
59,052
|
|
|
1,390,429
|
|
Revisions of previous estimates
|
(18,687
|
)
|
|
11,103
|
|
|
167,589
|
|
Acquisitions of new reserves
|
1,009
|
|
|
441
|
|
|
12,527
|
|
Extensions and discoveries
|
37,603
|
|
|
27,500
|
|
|
467,185
|
|
Sales of reserves in place
|
(25,659
|
)
|
|
(2,516
|
)
|
|
(163,800
|
)
|
Production
|
(10,876
|
)
|
|
(3,794
|
)
|
|
(85,697
|
)
|
As of December 31, 2014(2) - Predecessor
|
126,031
|
|
|
91,786
|
|
|
1,788,233
|
|
Revisions of previous estimates
|
(70,708
|
)
|
|
(37,384
|
)
|
|
(759,106
|
)
|
Acquisitions of new reserves
|
22,447
|
|
|
2,460
|
|
|
15,952
|
|
Extensions and discoveries
|
9,741
|
|
|
9,257
|
|
|
160,865
|
|
Production
|
(9,600
|
)
|
|
(5,044
|
)
|
|
(92,104
|
)
|
As of December 31, 2015(2) - Predecessor
|
77,911
|
|
|
61,075
|
|
|
1,113,840
|
|
Adoption of ASU 2015-02
|
(6,971
|
)
|
|
(3,695
|
)
|
|
(50,508
|
)
|
Revisions of previous estimates
|
(39,973
|
)
|
|
(21,475
|
)
|
|
(415,568
|
)
|
Extensions and discoveries
|
987
|
|
|
472
|
|
|
7,955
|
|
Sales of reserves in place
|
(387
|
)
|
|
—
|
|
|
(145,267
|
)
|
Production
|
(4,315
|
)
|
|
(3,358
|
)
|
|
(44,124
|
)
|
As of October 1, 2016 - Predecessor
|
27,252
|
|
|
33,019
|
|
|
466,328
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|||
Revisions of previous estimates
|
23,978
|
|
|
1,139
|
|
|
915
|
|
Extensions and discoveries
|
2,868
|
|
|
448
|
|
|
10,309
|
|
Production
|
(1,214
|
)
|
|
(999
|
)
|
|
(12,770
|
)
|
As of December 31, 2016 - Successor
|
52,884
|
|
|
33,607
|
|
|
464,782
|
|
Proved developed reserves
|
|
|
|
|
|
|||
As of December 31, 2013 - Predecessor
|
83,893
|
|
|
35,807
|
|
|
951,609
|
|
As of December 31, 2014 - Predecessor
|
79,022
|
|
|
56,823
|
|
|
1,203,447
|
|
As of December 31, 2015 - Predecessor
|
48,639
|
|
|
51,089
|
|
|
964,617
|
|
As of October 1, 2016 - Predecessor
|
24,541
|
|
|
30,238
|
|
|
428,050
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|||
As of December 31, 2016 - Successor
|
25,911
|
|
|
29,290
|
|
|
393,028
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|||
As of December 31, 2013 - Predecessor
|
58,748
|
|
|
23,245
|
|
|
438,820
|
|
As of December 31, 2014 - Predecessor
|
47,009
|
|
|
34,963
|
|
|
584,786
|
|
As of December 31, 2015 - Predecessor
|
29,272
|
|
|
9,986
|
|
|
149,223
|
|
As of October 1, 2016 - Predecessor
|
2,711
|
|
|
2,781
|
|
|
38,278
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|||
As of December 31, 2016 - Successor
|
26,973
|
|
|
4,317
|
|
|
71,754
|
|
(1)
|
Natural gas reserves are computed at
14.65
pounds per square inch absolute and
60
degrees Fahrenheit.
|
(2)
|
Includes proved reserves attributable to noncontrolling interests as shown in the table below:
|
•
|
the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
|
•
|
pricing is applied based upon 12-month average market prices at
December 31, 2016
,
2015
and
2014
adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
December 31,
|
|
|
December 31,
|
||||||||
|
2016
|
|
|
2015
|
|
2014
|
||||||
Oil (per barrel)
|
$
|
38.59
|
|
|
|
$
|
45.29
|
|
|
$
|
91.65
|
|
NGL (per barrel)
|
$
|
10.99
|
|
|
|
$
|
12.68
|
|
|
$
|
32.79
|
|
Natural gas (per Mcf)
|
$
|
1.56
|
|
|
|
$
|
1.87
|
|
|
$
|
3.61
|
|
•
|
future development and production costs are determined based upon actual cost at year-end;
|
•
|
the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
|
•
|
a discount factor of 10% per year is applied annually to the future net cash flows.
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
December 31,
|
|
|
December 31,
|
||||||||
|
2016
|
|
|
2015
|
|
2014
|
||||||
Future cash inflows from production
|
$
|
3,136,762
|
|
|
|
$
|
6,387,944
|
|
|
$
|
21,022,320
|
|
Future production costs
|
(1,454,798
|
)
|
|
|
(2,731,542
|
)
|
|
(6,499,366
|
)
|
|||
Future development costs(1)
|
(665,516
|
)
|
|
|
(838,945
|
)
|
|
(1,810,201
|
)
|
|||
Future income tax expenses
|
(142
|
)
|
|
|
(901
|
)
|
|
(3,223,740
|
)
|
|||
Undiscounted future net cash flows
|
1,016,306
|
|
|
|
2,816,556
|
|
|
9,489,013
|
|
|||
10% annual discount
|
(577,942
|
)
|
|
|
(1,501,994
|
)
|
|
(5,401,261
|
)
|
|||
Standardized measure of discounted future net cash flows(2)
|
$
|
438,364
|
|
|
|
$
|
1,314,562
|
|
|
$
|
4,087,752
|
|
(1)
|
Includes abandonment costs.
|
(2)
|
Includes approximately
$224.6 million
and
$643.3 million
attributable to noncontrolling interests at December 31,
2015
and
2014
respectively.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Period from October 2, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 1, 2016
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
||||||||
Beginning present value
|
$
|
392,604
|
|
|
|
$
|
1,314,562
|
|
|
$
|
4,087,752
|
|
|
$
|
4,017,611
|
|
Changes during the year
|
|
|
|
|
|
|
|
|
||||||||
Adoption of ASU 2015-02
|
—
|
|
|
|
(224,965
|
)
|
|
—
|
|
|
—
|
|
||||
Revenues less production and other costs
|
(70,668
|
)
|
|
|
(144,256
|
)
|
|
(383,293
|
)
|
|
(1,043,060
|
)
|
||||
Net changes in prices, production and other costs
|
35,684
|
|
|
|
(394,173
|
)
|
|
(3,813,465
|
)
|
|
331,694
|
|
||||
Development costs incurred
|
7,941
|
|
|
|
69,080
|
|
|
217,596
|
|
|
364,262
|
|
||||
Net changes in future development costs
|
(291,232
|
)
|
|
|
436,041
|
|
|
273,437
|
|
|
(341,183
|
)
|
||||
Extensions and discoveries
|
14,986
|
|
|
|
12,449
|
|
|
230,055
|
|
|
1,785,963
|
|
||||
Revisions of previous quantity estimates
|
308,374
|
|
|
|
(728,254
|
)
|
|
(1,354,778
|
)
|
|
(77,688
|
)
|
||||
Accretion of discount
|
9,375
|
|
|
|
91,337
|
|
|
512,483
|
|
|
477,458
|
|
||||
Net change in income taxes
|
—
|
|
|
|
402
|
|
|
1,426,333
|
|
|
(256,371
|
)
|
||||
Purchases of reserves in-place
|
—
|
|
|
|
—
|
|
|
18,429
|
|
|
50,958
|
|
||||
Sales of reserves in-place
|
—
|
|
|
|
(13,314
|
)
|
|
—
|
|
|
(1,058,330
|
)
|
||||
Timing differences and other(1)
|
31,300
|
|
|
|
(26,305
|
)
|
|
100,013
|
|
|
(163,562
|
)
|
||||
Net change for the year
|
45,760
|
|
|
|
(921,958
|
)
|
|
(2,773,190
|
)
|
|
70,141
|
|
||||
Ending present value(2)
|
$
|
438,364
|
|
|
|
$
|
392,604
|
|
|
$
|
1,314,562
|
|
|
$
|
4,087,752
|
|
(1)
|
The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
|
(2)
|
Includes approximately
$224.6 million
and
$643.3 million
attributable to noncontrolling interests at December 31,
2015
, and 2014 respectively.
|
|
Predecessor
|
|
|
Successor
|
||||||||||||||||
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth Quarter
|
|
|
Fourth Quarter
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
90,332
|
|
|
$
|
99,421
|
|
|
$
|
104,056
|
|
|
$
|
—
|
|
|
|
$
|
98,456
|
|
Loss from operations(1)(2)
|
$
|
(273,555
|
)
|
|
$
|
(275,310
|
)
|
|
$
|
(357,338
|
)
|
|
$
|
—
|
|
|
|
$
|
(336,345
|
)
|
Net (loss) income(1)(2)(3)
|
$
|
(313,226
|
)
|
|
$
|
(515,911
|
)
|
|
$
|
(404,337
|
)
|
|
$
|
2,674,271
|
|
|
|
(333,982
|
)
|
|
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)
|
$
|
(324,107
|
)
|
|
$
|
(521,351
|
)
|
|
$
|
(404,337
|
)
|
|
$
|
2,674,271
|
|
|
|
$
|
(333,982
|
)
|
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
(0.47
|
)
|
|
$
|
(0.73
|
)
|
|
$
|
(0.56
|
)
|
|
$
|
3.72
|
|
|
|
$
|
(17.61
|
)
|
Diluted
|
$
|
(0.47
|
)
|
|
$
|
(0.73
|
)
|
|
$
|
(0.56
|
)
|
|
$
|
3.72
|
|
|
|
$
|
(17.61
|
)
|
|
Predecessor
|
||||||||||||||
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
Total revenues
|
$
|
215,308
|
|
|
$
|
229,607
|
|
|
$
|
180,152
|
|
|
$
|
143,642
|
|
Loss from operations(4)(5)
|
$
|
(1,088,456
|
)
|
|
$
|
(1,535,083
|
)
|
|
$
|
(1,059,733
|
)
|
|
$
|
(959,406
|
)
|
Net loss(4)(5)
|
$
|
(1,151,874
|
)
|
|
$
|
(1,588,731
|
)
|
|
$
|
(796,485
|
)
|
|
$
|
(783,961
|
)
|
Loss applicable to SandRidge Energy, Inc. common stockholders(4)(5)
|
$
|
(1,045,834
|
)
|
|
$
|
(1,375,556
|
)
|
|
$
|
(649,526
|
)
|
|
$
|
(664,579
|
)
|
Loss applicable per share to SandRidge Energy, Inc. common stockholders(6)
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(2.19
|
)
|
|
$
|
(2.78
|
)
|
|
$
|
(1.23
|
)
|
|
$
|
(1.13
|
)
|
Diluted
|
$
|
(2.19
|
)
|
|
$
|
(2.78
|
)
|
|
$
|
(1.23
|
)
|
|
$
|
(1.13
|
)
|
(1)
|
Includes impairment of
$110.1 million
,
$253.6 million
,
$354.5 million
and
$319.1 million
for the first, second, and third quarters and Successor 2016 Period, respectively. See Note
9
for further discussion of impairment.
|
(2)
|
Includes loss on settlement of contract of
$89.1 million
and gain on extinguishment of
$41.3 million
for the first quarter.
|
(3)
|
Includes (loss) gain on reorganization items related to the Company’s restructuring under Chapter 11 filings of
$(200.9) million
,
$(42.8) million
, and
$2.7 billion
for the second and third quarters and Predecessor fourth quarter, respectively. See Note
2
for further discussion of reorganization items.
|
(4)
|
Includes impairment of
$1.1 billion
,
$1.5 billion
,
$1.1 billion
and
$886.8 million
for the first, second, third and fourth quarters, respectively. See Note
9
for further discussion of impairment.
|
(5)
|
Includes (gain) loss on derivative contracts of
$(49.8) million
,
$33.0 million
,
$(42.2) million
and
$(14.0) million
for the first, second, third and fourth quarters, respectively.
|
(6)
|
Loss applicable per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of loss applicable per share to common stockholders for each of the four quarters may not equal the fiscal year amount.
|
|
SANDRIDGE ENERGY, INC.
|
|
|
|
|
|
By
|
/s/ J
AMES
D. B
ENNETT
|
|
|
James D. Bennett,
|
|
|
President and Chief Executive Officer
|
March 3, 2017
|
|
|
Signature
|
|
Title
|
Date
|
|
|
|
|
/s/ JAMES D. BENNETT
|
|
President, Chief Executive Officer and Director
(Principal Executive Officer)
|
March 3, 2017
|
James D. Bennett
|
|
|
|
|
|
|
|
/s/ JULIAN BOTT
|
|
Chief Financial Officer and Executive Vice President (Principal Financial Officer)
|
March 3, 2017
|
Julian Bott
|
|
|
|
|
|
|
|
/s/ LISA E. KLEIN
|
|
Vice President—Accounting
(Principal Accounting Officer)
|
March 3, 2017
|
Lisa E. Klein
|
|
|
|
|
|
|
|
/s/ MICHAEL L. BENNETT
|
|
Director
|
March 3, 2017
|
Michael L. Bennett
|
|
|
|
|
|
|
|
/s/ JOHN V. GENOVA
|
|
Chairman
|
March 3, 2017
|
John V. Genova
|
|
|
|
|
|
|
|
/s/ WILLIAM (BILL) M. GRIFFIN
|
|
Director
|
March 3, 2017
|
William (Bill) M. Griffin
|
|
|
|
|
|
|
|
/s/ DAVID J. KORNDER
|
|
Director
|
March 3, 2017
|
David J. Kornder
|
|
|
|
|
|
Incorporated by Reference
|
|
|||
Exhibit
No.
|
Exhibit Description
|
Form
|
SEC
File No.
|
Exhibit
|
Filing Date
|
Filed
Herewith
|
2.1
|
Equity Purchase Agreement dated as of January 6, 2014, between SandRidge Energy, Inc., SandRidge Holdings, Inc. and Fieldwood Energy LLC
|
8-K
|
001-33784
|
2.1
|
1/9/2014
|
|
2.2
|
Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016
|
8-A
|
001-33784
|
2.1
|
10/4/2016
|
|
3.1
|
Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.
|
8-A
|
001-33784
|
3.1
|
10/4/2016
|
|
3.2
|
Amended and Restated Bylaws of SandRidge Energy, Inc.
|
8-A
|
001-33784
|
3.2
|
10/4/2016
|
|
4.1
|
Form of specimen Common Stock certificate of SandRidge Energy, Inc.
|
8-K
|
001-33784
|
4.1
|
10/7/2016
|
|
4.2
|
Warrant Agreement, dated as of October 4, 2016, between SandRidge Energy, Inc. and American Stock Transfer & Trust Company, LLC, as warrant agent
|
8-K
|
001-33784
|
10.6
|
10/7/2016
|
|
4.3
|
Convertible Notes Indenture, dated as of October 4, 2016, among SandRidge Energy, Inc., the guarantors party thereto and Wilmington Trust, National Association, as trustee
|
8-K
|
001-33784
|
10.3
|
10/7/2016
|
|
4.4
|
Registration Rights Agreement dated as of October 4, 2016, among SandRidge Energy, Inc. and the holders party thereto
|
8-A
|
001-33784
|
10.1
|
10/4/2017
|
|
10.1†
|
SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
8-K
|
001-33784
|
10.8
|
10/7/2016
|
|
10.1.1†
|
Form of Non-employee Director Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
|
|
|
|
*
|
10.1.2†
|
Form of Executive Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
|
|
|
|
*
|
10.1.3†
|
Form of Emergence Performance Unit Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
|
|
|
|
*
|
10.1.4†
|
Form of Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
|
|
|
|
*
|
10.1.5†
|
Form of Performance Share Unit Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan
|
|
|
|
|
*
|
10.2.1†
|
Employment Agreement, effective as of August 12, 2014, between SandRidge Energy, Inc. and James D. Bennett
|
10-K
|
001-33784
|
10.3.1
|
2/27/2015
|
|
10.2.2†
|
Employment Agreement, effective as of August 17, 2015, between SandRidge Energy, Inc. and Julian Bott.
|
8-K
|
001-33784
|
10.1
|
8/5/2015
|
|
10.2.3†
|
Employment Agreement, effective as of December 30, 2013, between SandRidge Energy, Inc. and Duane Grubert
|
10-K
|
001-33784
|
10.3.2
|
2/27/2015
|
|
10.2.4†
|
2015 Form of Employment Agreement for Executive Vice Presidents and Senior Vice Presidents of SandRidge Energy, Inc.
|
10-Q
|
001-33784
|
10.3.4
|
11/5/2015
|
|
10.3†
|
Form of Indemnification Agreement for directors and officers
|
8-K
|
001-33784
|
10.9
|
10/7/2016
|
|
Section 1.
|
Terms Generally 2
|
Section 2.
|
Grant of Security 3
|
Section 3.
|
Security for Obligations 4
|
Section 4.
|
Grantors Remain Liable 4
|
Section 5.
|
Delivery and Control of Security Collateral 5
|
Section 6.
|
Maintaining Deposit and Securities Accounts 7
|
Section 7.
|
Representations and Warranties 8
|
Section 8.
|
Further Assurances 9
|
Section 9.
|
Collections on Receivables and Related Contracts 10
|
Section 10.
|
As to Intellectual Property 10
|
Section 11.
|
Voting Rights; Dividends; Etc 11
|
Section 12.
|
Additional Shares 12
|
Section 13.
|
Administrative Agent Appointed Attorney-in-Fact 12
|
Section 14.
|
Administrative Agent May Perform 12
|
Section 15.
|
The Administrative Agent’s Duties 12
|
Section 16.
|
Remedies 13
|
Section 17.
|
Subordination of Liens 15
|
Section 18.
|
Amendments; Waivers; Additional Grantors; Etc 15
|
Section 19.
|
Notices, Etc 15
|
Section 20.
|
Continuing Security Interest; Assignments under the Credit Agreement 15
|
Section 21.
|
Release; Termination 16
|
Section 22.
|
Terms Generally; References and Titles 17
|
Section 23.
|
Execution in Counterparts 17
|
Section 24.
|
Governing Law; Jurisdiction; Waiver of Jury Trial, Etc. 17
|
Schedule I
|
Location, Type of Organization, Jurisdiction of Organization and Organizational Identification Number
|
Schedule II
|
Pledged Equity
|
Exhibit A
|
Form of Security Agreement Supplement
|
Grantor
|
Location
|
Type of
Organization
|
Jurisdiction of
Organization
|
Organizational I.D.
No.
|
SandRidge Energy, Inc.
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Corporation
|
Delaware
|
20-8084793
|
SandRidge Operating Company
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Corporation
|
Texas
|
75-2541245
|
Integra Energy, L.L.C.
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Limited Liability
Company
|
Texas
|
75-2887527
|
SandRidge Holdings, Inc.
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Corporation
|
Delaware
|
20-5878401
|
SandRidge Exploration and
Production, LLC
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Limited Liability
Company
|
Delaware
|
87-0776535
|
SandRidge Midstream, Inc.
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Corporation
|
Texas
|
75-2541148
|
Lariat Services, Inc.
|
123 Robert S. Kerr
Avenue, Oklahoma
City, OK 73102
|
Corporation
|
Texas
|
75-2887527
|
Grantor
|
Changes
|
SandRidge Energy, Inc.
|
None
|
SandRidge Operating Company
|
None
|
Integra Energy, L.L.C.
|
None
|
SandRidge Holdings, Inc.
|
None
|
SandRidge Exploration and
Production, LLC
|
None
|
SandRidge Midstream, Inc.
|
None
|
Lariat Services, Inc.
|
None
|
Grantor
|
Issuer
|
Class of Equity
|
Certificate
No(s)
|
Number of
Shares
|
Percentage of
Outstanding
Shares
|
SandRidge Energy, Inc.
|
Lariat Services,
Inc.
|
Common Stock
|
1
|
100,000
|
100%
|
SandRidge Energy, Inc.
|
SandRidge
CO2, LLC
|
Membership
Interests
|
n/a
|
n/a
|
100%
|
SandRidge Energy, Inc.
|
SandRidge
Holdings, Inc.
|
Common Stock
|
1
|
100
|
100%
|
SandRidge Energy, Inc.
|
SandRidge
Midstream, Inc.
|
Common Stock
|
1
|
100,000
|
100%
|
SandRidge Energy, Inc.
|
SandRidge
Operating Company
|
Common Stock
|
1
|
100,000
|
100%
|
SandRidge Energy, Inc.
|
SandRidge
Realty, LLC
|
Membership
Interests
|
n/a
|
n/a
|
100%
|
Integra Energy, L.L.C.
|
Cholla Pipeline,
L.P.
|
Limited
Partnership
|
n/a
|
n/a
|
36.1427%
|
SandRidge Holdings, Inc.
|
SandRidge
Exploration and
Production, LLC
|
Membership
Interests
|
n/a
|
n/a
|
100%
|
SandRidge Exploration and
Production, LLC
|
Integra Energy,
L.L.C.
|
Membership
Interests
|
n/a
|
n/a
|
100%
|
SandRidge Midstream, Inc.
|
Cholla Pipeline,
L.P.
|
Limited
Partnership
Interests
|
n/a
|
n/a
|
62.5716%
|
SandRidge Midstream, Inc.
|
Sagebrush Pipeline, LLC
|
Membership Interests
|
n/a
|
n/a
|
73.80881%
|
By:
|
|
Name:
|
|
Title:
|
|
|
|
SandRidge Energy, Inc.
|
|
123 Robert S. Kerr Avenue
|
|
|
Oklahoma City, Oklahoma
73102
|
|
|
|
|
|
|
|
|
|
Name:
|
[●]
|
Award Number:
|
[●]
|
Address:
|
[●]
|
Plan:
|
2016 Omnibus Incentive Plan
|
|
|
Employee ID:
|
[●]
|
VEST DATE
|
SHARES
|
[●]
|
[●]
|
[●]
|
[●]
|
[●]
|
[●]
|
|
|
|
|
|
SandRidge Energy, Inc.
|
|
123 Robert S. Kerr Avenue
|
|
|
Oklahoma City, Oklahoma
73102
|
|
|
|
|
|
|
|
|
|
Name:
|
[●]
|
Award Number:
|
[●]
|
Address:
|
[●]
|
Plan:
|
2016 Omnibus Incentive Plan
|
|
|
Employee ID:
|
[●]
|
an Oklahoma limited liability company
By: |
/s/ Julian Bott
Name: Julian Bott Title: Executive Vice President and Chief |
Entity Name
|
|
State of Organization
|
Integra Energy, L.L.C.
|
|
Texas
|
Lariat Services, Inc.
|
|
Texas
|
SandRidge Exploration and Production, LLC
|
|
Delaware
|
SandRidge Holdings, Inc.
|
|
Delaware
|
SandRidge Midstream, Inc.
|
|
Texas
|
SandRidge Operating Company
|
|
Texas
|
SandRidge Realty, LLC
|
|
Oklahoma
|
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.
|
|
|
|
|
|
|
|
|
|
|
||
|
621 SEVENTEENTH STREET, SUITE 1550
|
DENVER, COLORADO 80293
|
(303) 623-9147
|
1.
|
I have reviewed this annual report on Form 10-K of SandRidge 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 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 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/ James D. Bennett
|
James D. Bennett
|
President and Chief Executive Officer
|
1.
|
I have reviewed this annual report on Form 10-K of SandRidge 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 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 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/ Julian Bott
|
Julian Bott
|
Executive Vice President and Chief Financial Officer
|
/s/ James D. Bennett
|
James D. Bennett
|
President and Chief Executive Officer
|
/s/ Julian Bott
|
Julian Bott
|
Executive Vice President and Chief Financial Officer
|
Re:
|
Evaluation Summary
|
|
SandRidge Energy, Inc. Interests
|
|
Proved Reserves
|
|
As of January 1, 2017
|
|
|
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
4,812.4
|
|
698.2
|
|
2,392.7
|
|
-59,961.7
|
|
-23,026.1
|
Note:
|
The estimates herein are based on economic limits when combining the SandRidge direct interest and the Trust royalty interest. The negative future net revenues are the result of showing only the SandRidge proportional consolidation interest.
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|
/s/ Scott Wilson /seal/
|
|
|
|
As of December 31, 2016
|
|
|
Proved
|
||||||||||
|
|
Developed Producing
|
|
Undeveloped
|
|
Total
Proved
|
||||||
Net Remaining Reserves
|
|
|
|
|
|
|
||||||
Oil/Condensate – MBarrels
|
|
3,238
|
|
|
22,986
|
|
|
26,224
|
|
|||
Gas - MMCF
|
|
2,600
|
|
|
21,532
|
|
|
24,132
|
|
|||
|
|
|
|
|
|
|
||||||
Income Data (M$)
|
|
|
|
|
|
|
||||||
Future Gross Revenue
|
|
|
$118,346
|
|
|
|
$837,726
|
|
|
|
$956,072
|
|
Deductions
|
|
31,391
|
|
|
563,324
|
|
|
594,715
|
|
|||
Future Net Income (FNI)
|
|
$
|
86,955
|
|
|
|
$274,402
|
|
|
|
$361,357
|
|
|
|
|
|
|
|
|
||||||
Discounted FNI @ 10%
|
|
$
|
46,119
|
|
|
$
|
8,415
|
|
|
$
|
54,534
|
|
|
|
Discounted Future Net Income (M$)
|
||
|
|
As of December 31, 2016
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
9
|
|
$67,223
|
|
|
15
|
|
$11,874
|
|
|
20
|
|
$(10,761)
|
|
|
25
|
|
$(23,368)
|
|
|
30
|
|
$(30,458)
|
|