[X]
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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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Common Stock, $0.001 par value
Preferred Share Purchase Rights
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New York Stock Exchange
New York Stock Exchange
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(Title of Class)
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(Name of each exchange on which registered)
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Large accelerated filer
T
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Accelerated filer
£
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Non-accelerated filer
£
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Smaller reporting company
£
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a.
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The area identified by drilling and limited by fluid contacts, if any, and
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b.
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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.
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a.
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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
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b.
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The project has been approved for development by all necessary parties and entities, including governmental entities.
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Item 1.
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B
usi
ness
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Proved Reserves
(1)
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|||||||||||||||||||||||||||
Core Area
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Oil (MMBbl)
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NGLs (MMBbl)
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Natural Gas (Bcf)
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Total (MMBOE)
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%
Oil
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Pre-Tax PV10% Value
(2)
(in millions)
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4
th
Quarter 2013 Average Daily Production (MBOE/d)
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||||||||||||||||||||
Rocky Mountains
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236.6 | 25.7 | 208.8 | 297.0 | 80% | $ | 7,309.7 | 84.7 | |||||||||||||||||||
Permian Basin
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106.4 | 17.8 | 17.6 | 127.1 | 84% | 1,524.6 | 12.3 | ||||||||||||||||||||
Other
(3)
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4.4 | 1.4 | 51.1 | 14.4 | 31% | 159.7 | 4.0 | ||||||||||||||||||||
Total
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347.4 | 44.9 | 277.5 | 438.5 | 79% | $ | 8,994.0 | 101.0 | |||||||||||||||||||
Discounted Future Income Taxes
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(2,400.1 | ) | |||||||||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows
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$ | 6,593.9 |
(1)
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Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2013, pursuant to current SEC and FASB guidelines.
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(2)
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Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
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(3)
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Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
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•
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pursuing the development of projects that we believe will generate attractive rates of return;
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•
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allocating a portion of our exploration and development (“E&D”) budget to leasing and exploring prospect areas;
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•
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maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows; and
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•
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seeking property acquisitions that complement our core areas.
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Rocky Mountains:
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Oil
(MMBbl)
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NGLs (MMBbl)
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Natural Gas
(Bcf)
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Total
(MMBOE)
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% of Total
Proved
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Estimated Future Capital Expenditures
(in millions)
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||||||||||||||||||
PDP
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128.5 | 13.2 | 122.1 | 161.9 | 55 | % | ||||||||||||||||||
PDNP
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0.5 | 0.1 | 1.2 | 0.8 | - | % | ||||||||||||||||||
PUD
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107.6 | 12.4 | 85.5 | 134.3 | 45 | % | ||||||||||||||||||
Total proved
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236.6 | 25.7 | 208.8 | 297.0 | 100 | % | $ | 2,597.7 | ||||||||||||||||
Total probable
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90.8 | 17.4 | 215.3 | 144.1 | $ | 2,835.7 | ||||||||||||||||||
Total possible
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59.0 | 8.4 | 136.2 | 90.1 | $ | 1,866.2 | ||||||||||||||||||
Permian Basin:
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||||||||||||||||||||||||
PDP
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49.6 | 5.9 | 11.8 | 57.4 | 45 | % | ||||||||||||||||||
PDNP
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15.3 | 3.5 | 2.8 | 19.3 | 15 | % | ||||||||||||||||||
PUD
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41.5 | 8.4 | 3.0 | 50.4 | 40 | % | ||||||||||||||||||
Total proved
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106.4 | 17.8 | 17.6 | 127.1 | 100 | % | $ | 1,335.3 | ||||||||||||||||
Total probable
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15.9 | 4.3 | 34.6 | 26.0 | $ | 265.1 | ||||||||||||||||||
Total possible
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76.9 | 16.1 | 2.8 | 93.4 | $ | 739.8 | ||||||||||||||||||
Other
(1)
:
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||||||||||||||||||||||||
PDP
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3.6 | 0.8 | 38.7 | 11.0 | 76 | % | ||||||||||||||||||
PDNP
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0.7 | 0.3 | 6.6 | 2.1 | 15 | % | ||||||||||||||||||
PUD
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0.1 | 0.3 | 5.8 | 1.3 | 9 | % | ||||||||||||||||||
Total proved
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4.4 | 1.4 | 51.1 | 14.4 | 100 | % | $ | 21.4 | ||||||||||||||||
Total probable
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2.6 | 0.6 | 17.7 | 6.1 | $ | 57.1 | ||||||||||||||||||
Total possible
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1.3 | 0.1 | 24.8 | 5.6 | $ | 80.1 | ||||||||||||||||||
Total Company:
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||||||||||||||||||||||||
PDP
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181.7 | 19.9 | 172.6 | 230.3 | 53 | % | ||||||||||||||||||
PDNP
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16.5 | 3.9 | 10.6 | 22.2 | 5 | % | ||||||||||||||||||
PUD
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149.2 | 21.1 | 94.3 | 186.0 | 42 | % | ||||||||||||||||||
Total proved
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347.4 | 44.9 | 277.5 | 438.5 | 100 | % | $ | 3,954.4 | ||||||||||||||||
Total probable
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109.3 | 22.3 | 267.6 | 176.2 | $ | 3,157.9 | ||||||||||||||||||
Total possible
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137.2 | 24.6 | 163.8 | 189.1 | $ | 2,686.1 |
(1)
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Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
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2013
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2012
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2011
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|||
Plains Marketing LP
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21%
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20%
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27%
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Shell Trading US
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14%
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14%
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13%
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Eighty Eight Oil Company
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11%
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11%
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8%
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Bridger Trading LLC
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8%
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11%
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6%
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•
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to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or other third parties;
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•
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to clean up contaminated property, including contaminated groundwater;
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•
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to perform remedial operations to prevent future contamination, including the plugging and abandonment of wells drilled and left inactive by prior owners and operators; or
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•
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to pay some or all of the costs of any such action.
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Item 1A.
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Ri
sk
Factors
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•
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changes in regional, domestic and global supply and demand for oil and natural gas;
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•
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the actions of the Organization of Petroleum Exporting Countries;
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•
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the price and quantity of imports of foreign oil and natural gas;
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•
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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent conflicts in the Middle East;
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•
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the level of global oil and natural gas exploration and production activity;
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•
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the effects of global credit, financial and economic issues;
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•
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the level of global oil and natural gas inventories;
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•
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developments of United States energy infrastructure, such as the approval to proceed with the Keystone XL pipeline from Hardesty, Alberta to Cushing, Oklahoma and the development of liquefied natural gas exporting facilities and the perceived timing thereof;
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•
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weather conditions;
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•
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technological advances affecting energy consumption;
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•
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domestic and foreign governmental regulations;
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•
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proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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•
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the price and availability of competitors’ supplies of oil and natural gas in captive market areas;
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•
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the price and availability of alternative fuels; and
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•
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acts of force majeure.
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•
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delays imposed by or resulting from compliance with regulatory requirements;
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•
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delays or limits on the issuance of drilling permits on our federal leases, including as a result of government shutdowns;
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•
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pressure or irregularities in geological formations;
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•
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shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, completion services and CO
2
;
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•
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equipment failures or accidents;
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•
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adverse weather conditions, such as freezing temperatures, hurricanes and storms;
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•
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reductions in oil, NGL and natural gas prices;
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•
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pipeline takeaway and refining and processing capacity; and
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•
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title problems.
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•
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historical production from the area compared with production rates from other producing areas;
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•
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the assumed effect of governmental regulation; and
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•
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assumptions about future prices of oil, NGLs and natural gas including differentials, production and development costs, gathering and transportation costs, severance and excise taxes, capital expenditures and availability of funds.
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•
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requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
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•
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limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
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•
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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•
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placing us at a competitive disadvantage relative to other less leveraged competitors; and
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•
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making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas’ credit agreement is subject to certain rate variability.
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•
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pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our senior or subordinated debt;
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•
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make loans to others;
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•
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make investments;
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•
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incur additional indebtedness or issue preferred stock;
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•
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create certain liens;
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•
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sell assets;
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•
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enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
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•
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consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;
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•
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engage in transactions with affiliates;
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•
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enter into hedging contracts;
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•
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create unrestricted subsidiaries; and
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•
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enter into sale and leaseback transactions.
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•
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our proved reserves;
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•
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the level of oil and natural gas we are able to produce from existing wells;
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•
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the prices at which oil and natural gas are sold;
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•
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the costs of producing oil and natural gas; and
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•
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our ability to acquire, locate and produce new reserves.
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•
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some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;
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•
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we may assume liabilities that were not disclosed to us or that exceed our estimates;
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•
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we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
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•
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acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
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•
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we may issue additional equity or debt securities in order to fund future acquisitions.
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•
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the amount of recoverable reserves;
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•
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future oil and natural gas prices;
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•
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estimates of operating costs;
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•
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estimates of future development costs;
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•
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timing of future development costs;
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•
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estimates of the costs and timing of plugging and abandonment; and
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•
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the assumption of unknown potential environmental and other liabilities, losses or costs, including for example, historical spills or releases for which we are not indemnified or for which our indemnity is inadequate.
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•
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environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
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•
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abnormally pressured formations;
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•
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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•
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the loss of well control;
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•
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fires and explosions;
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•
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personal injuries and death; and
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•
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natural disasters.
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•
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discharge permits for drilling operations;
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•
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drilling bonds;
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•
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reports concerning operations;
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•
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the spacing of wells;
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•
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unitization and pooling of properties; and
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•
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taxation.
|
•
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the repeal of the percentage depletion allowance for oil and gas properties;
|
•
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the elimination of current deductions for intangible drilling and development costs;
|
•
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the elimination of the deduction for U.S. oil and gas production activities; and
|
•
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an extension of the amortization period for certain geological and geophysical expenditures.
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Item 1B.
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Un
res
olved Staff Comments
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Item 2.
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P
rop
erties
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Oil
(MBbl)
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NGLs
(MBbl)
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Natural Gas
(MMcf)
|
Total
(MBOE)
|
|||||||||||||
Proved reserves
|
||||||||||||||||
Developed
|
198,204 | 23,721 | 183,129 | 252,446 | ||||||||||||
Undeveloped
|
149,217 | 21,148 | 94,385 | 186,096 | ||||||||||||
Total proved—December 31, 2013
|
347,421 | 44,869 | 277,514 | 438,542 | ||||||||||||
Probable reserves
|
||||||||||||||||
Developed
|
748 | 139 | 6,832 | 2,026 | ||||||||||||
Undeveloped
|
108,520 | 22,191 | 260,723 | 174,165 | ||||||||||||
Total probable—December 31, 2013
|
109,268 | 22,330 | 267,555 | 176,191 | ||||||||||||
Possible reserves
|
||||||||||||||||
Developed
|
1,989 | 387 | 1,746 | 2,667 | ||||||||||||
Undeveloped
|
135,234 | 24,220 | 162,034 | 186,460 | ||||||||||||
Total possible—December 31, 2013
|
137,223 | 24,607 | 163,780 | 189,127 |
Total
(MBOE)
|
||||
PUD balance—December 31, 2012
|
136,896 | |||
Converted to proved developed through drilling
(1)(3)
|
(27,782 | ) | ||
Converted to proved developed at EOR projects
(2)(3)
|
(12,364 | ) | ||
Added from revisions, extensions and discoveries
|
90,519 | |||
Removed for five-year rule
|
(602 | ) | ||
Removed due to low commodity prices
|
(143 | ) | ||
Purchased
|
12,745 | |||
Sold
|
(13,173 | ) | ||
PUD balance—December 31, 2013
|
186,096 |
(1)
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We incurred $701.5 million in capital expenditures, or $25.25 per BOE, to drill and bring on-line these PUD quantities.
|
(2)
|
Amount relates to PUD volumes that became proved developed reserves during 2013 at our CO
2
EOR project in the North Ward Estes field, at a cost of $40.35 per BOE.
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(3)
|
Combining the PUD drilling conversions with the PUD EOR conversions, we converted PUDs to proved developed reserves at a cost of $29.90 per BOE during 2013.
|
Developed Acreage
|
Undeveloped Acreage
|
Total Acreage
|
||||||||||||||||||||||
Gross
|
Net
|
Gross
(2)
|
Net
(2)
|
Gross
|
Net
|
|||||||||||||||||||
California
|
25,548 | 3,606 | - | - | 25,548 | 3,606 | ||||||||||||||||||
Colorado
|
61,579 | 42,555 | 179,242 | 116,629 | 240,821 | 159,184 | ||||||||||||||||||
Louisiana
|
40,074 | 11,691 | 101,325 | 90,862 | 141,399 | 102,553 | ||||||||||||||||||
Michigan
|
139,351 | 61,064 | 291,960 | 247,996 | 431,311 | 309,060 | ||||||||||||||||||
Montana
|
91,973 | 55,425 | 136,964 | 81,730 | 228,937 | 137,155 | ||||||||||||||||||
New Mexico
|
16,665 | 5,427 | 78,190 | 56,668 | 94,855 | 62,095 | ||||||||||||||||||
North Dakota
|
553,050 | 316,872 | 365,538 | 261,008 | 918,588 | 577,880 | ||||||||||||||||||
Oklahoma
|
56,645 | 28,392 | 406 | 68 | 57,051 | 28,460 | ||||||||||||||||||
Texas
|
260,935 | 147,963 | 84,214 | 60,849 | 345,149 | 208,812 | ||||||||||||||||||
Utah
|
35,826 | 18,370 | 406,522 | 240,108 | 442,348 | 258,478 | ||||||||||||||||||
Wyoming
|
95,725 | 55,835 | 49,312 | 36,072 | 145,037 | 91,907 | ||||||||||||||||||
Other
(1)
|
9,810 | 4,503 | 912 | 434 | 10,722 | 4,937 | ||||||||||||||||||
Total
|
1,387,181 | 751,703 | 1,694,585 | 1,192,424 | 3,081,766 | 1,944,127 |
(1)
|
Other includes Alabama, Arkansas, Kansas, Mississippi and Nebraska.
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(2)
|
Out of a total of approximately 1,694,585 gross (1,192,424 net) undeveloped acres as of December 31, 2013, the portion of our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 13% in 2014, 27% in 2015 and 22% in 2016.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Oil production (MMBbl)
|
27.0 | 23.1 | 18.3 | |||||||||
NGL production (MMBbl)
|
2.8 | 2.8 | 2.1 | |||||||||
Natural gas production (Bcf)
|
26.9 | 25.8 | 26.4 | |||||||||
Total production (MMBOE)
|
34.3 | 30.2 | 24.8 | |||||||||
Daily production (MBOE/d)
|
94.1 | 82.5 | 67.9 | |||||||||
North Ward Estes field production
(1)
|
||||||||||||
Oil production (MMBbl)
|
2.9 | 2.8 | 2.6 | |||||||||
NGL production (MMBbl)
|
0.4 | 0.3 | 0.4 | |||||||||
Natural gas production (Bcf)
|
0.3 | 0.3 | 0.4 | |||||||||
Total production (MMBOE)
|
3.4 | 3.2 | 3.0 | |||||||||
Sanish field production
(1)
|
||||||||||||
Oil production (MMBbl)
|
9.8 | 9.0 | 6.5 | |||||||||
NGL production (MMBbl)
|
1.1 | 1.2 | 0.8 | |||||||||
Natural gas production (Bcf)
|
4.8 | 3.6 | 2.2 | |||||||||
Total production (MMBOE)
|
11.7 | 10.8 | 7.7 | |||||||||
Average sales prices (before the effects of hedging):
|
||||||||||||
Oil (per Bbl)
|
$ | 90.39 | $ | 83.86 | $ | 88.61 | ||||||
NGLs (per Bbl)
|
$ | 40.41 | $ | 39.36 | $ | 52.38 | ||||||
Natural gas (per Mcf)
|
$ | 4.04 | $ | 3.42 | $ | 4.92 | ||||||
Average production costs:
|
||||||||||||
Production costs (per BOE)
(2)
|
$ | 11.94 | $ | 11.92 | $ | 11.77 |
(1)
|
The North Ward Estes and Sanish fields were our only fields that contained 15% or more of our total proved reserve volumes as of December 31, 2013.
|
(2)
|
Production costs reported above exclude from lease operating expenses ad valorem taxes of $20.1 million ($0.59 per BOE), $16.3 million ($0.54 per BOE) and $13.9 million ($0.56 per BOE) for the years ended December 31, 2013, 2012 and 2011, respectively.
|
Oil Wells
|
Natural Gas Wells
|
Total Wells
(1)
|
||||||||||||||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
Rocky Mountains
|
3,441 | 1,082 | 413 | 221 | 3,854 | 1,303 | ||||||||||||||||||
Permian Basin
|
4,091 | 1,727 | 386 | 122 | 4,477 | 1,849 | ||||||||||||||||||
Other
(2)
|
479 | 217 | 1,666 | 553 | 2,145 | 770 | ||||||||||||||||||
Total
|
8,011 | 3,026 | 2,465 | 896 | 10,476 | 3,922 |
(1)
|
141 wells have multiple completions. These 141 wells contain a total of 349 completions. One or more completions in the same bore hole are counted as one well.
|
(2)
|
Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
|
Gross Wells
|
Net Wells
|
|||||||||||||||||||||||
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
|||||||||||||||||||
2013:
|
||||||||||||||||||||||||
Development
|
376 | 1 | 377 | 185.5 | 1 | 186.5 | ||||||||||||||||||
Exploratory
|
43 | 8 | 51 | 35.2 | 7.5 | 42.7 | ||||||||||||||||||
Total
|
419 | 9 | 428 | 220.7 | 8.5 | 229.2 | ||||||||||||||||||
2012:
|
||||||||||||||||||||||||
Development
|
324 | - | 324 | 140.4 | - | 140.4 | ||||||||||||||||||
Exploratory
|
68 | 5 | 73 | 47.8 | 4.7 | 52.5 | ||||||||||||||||||
Total
|
392 | 5 | 397 | 188.2 | 4.7 | 192.9 | ||||||||||||||||||
2011:
|
||||||||||||||||||||||||
Development
|
218 | 3 | 221 | 93.9 | 1.5 | 95.4 | ||||||||||||||||||
Exploratory
|
60 | 3 | 63 | 36.6 | 3.0 | 39.6 | ||||||||||||||||||
Total
|
278 | 6 | 284 | 130.5 | 4.5 | 135.0 |
Drilling Rigs
|
||||
Northern Rocky Mountains
|
18 | |||
Central Rocky Mountains
|
3 | |||
North Ward Estes
|
2 | |||
Total
|
23 |
•
|
we follow fracturing and flowback procedures that comply with or exceed NDIC or other state requirements;
|
•
|
we train all company and contract personnel, who are responsible for well preparation, fracture stimulation and flowback, on our procedures;
|
•
|
we have implemented the incremental procedures of running a well casing caliper; visually inspecting the surface joint of intermediate casing; and if a lighter wall joint of casing or drilling wear is detected, the minimum burst pressure is reduced accordingly;
|
•
|
for wells that are within one mile of major bodies of water or locations that lead to bodies of water, we construct sufficient berming around the well location prior to initiating fracturing operations;
|
•
|
we run fracturing strings in certain situations when extra precaution is warranted, such as where the anticipated maximum treating pressure for the well is greater than the pressure rating of the intermediate casing or in areas located within one mile of major bodies of water; and
|
•
|
we are constructing a facility in North Dakota to treat and dispose of flow fluids from well stimulations.
|
Item 3.
|
L
egal
Proceedings
|
Item 4.
|
M
ine
Safety Disclosures
|
Name
|
Age
|
Position
|
||
James J. Volker
|
67
|
Chairman and Chief Executive Officer
|
||
James T. Brown
|
61
|
President and Chief Operating Officer
|
||
Mark R. Williams
|
57
|
Senior Vice President, Exploration and Development
|
||
Bruce R. DeBoer
|
61
|
Vice President, General Counsel and Corporate Secretary
|
||
Heather M. Duncan
|
43
|
Vice President, Human Resources
|
||
Steven A. Kranker
|
52
|
Vice President, Reservoir Engineering and Acquisitions
|
||
Rick A. Ross
|
55
|
Vice President, Operations
|
||
David M. Seery
|
59
|
Vice President, Land
|
||
Michael J. Stevens
|
48
|
Vice President and Chief Financial Officer
|
||
Brent P. Jensen
|
44
|
Controller and Treasurer
|
Item 5.
|
Ma
rk
et for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
High
|
Low
|
|||||||
Fiscal Year Ended December 31, 2013
|
||||||||
Fourth quarter (ended December 31, 2013)
|
$ | 70.57 | $ | 56.40 | ||||
Third quarter (ended September 30, 2013)
|
$ | 60.65 | $ | 46.13 | ||||
Second quarter (ended June 30, 2013)
|
$ | 50.96 | $ | 42.44 | ||||
First quarter (ended March 31, 2013)
|
$ | 52.02 | $ | 43.60 | ||||
Fiscal Year Ended December 31, 2012
|
||||||||
Fourth quarter (ended December 31, 2012)
|
$ | 48.87 | $ | 40.19 | ||||
Third quarter (ended September 30, 2012)
|
$ | 54.86 | $ | 38.29 | ||||
Second quarter (ended June 30, 2012)
|
$ | 58.33 | $ | 35.68 | ||||
First quarter (ended March 31, 2012)
|
$ | 63.97 | $ | 46.55 |
12/31/08
|
12/31/09
|
12/31/10
|
12/31/11
|
12/31/12
|
12/31/13
|
|||||||||||||||||||
Whiting Petroleum Corporation
|
$ | 100 | $ | 214 | $ | 350 | $ | 279 | $ | 259 | $ | 370 | ||||||||||||
Standard & Poor’s Composite 500 Index
|
100 | 123 | 139 | 139 | 158 | 205 | ||||||||||||||||||
Dow Jones U.S. Oil Companies, Secondary Index
|
100 | 139 | 161 | 153 | 160 | 208 |
Item 6.
|
Se
lect
ed Financial Data
|
Year Ended December 31,
|
||||||||||||||||||||
2013
|
2012
|
2011
|
2010
|
2009
|
||||||||||||||||
(dollars in millions, except per share data)
|
||||||||||||||||||||
Consolidated Statements of Income Information:
|
||||||||||||||||||||
Revenues and other income:
|
||||||||||||||||||||
Oil, NGL and natural gas sales
|
$ | 2,666.5 | $ | 2,137.7 | $ | 1,860.1 | $ | 1,475.3 | $ | 917.5 | ||||||||||
Gain (loss) on hedging activities
|
(1.9 | ) | 2.3 | 8.8 | 23.2 | 38.8 | ||||||||||||||
Amortization of deferred gain on sale
|
31.7 | 29.5 | 13.9 | 15.6 | 16.6 | |||||||||||||||
Gain on sale of properties
|
128.6 | 3.4 | 16.3 | 1.4 | 5.9 | |||||||||||||||
Interest income and other
|
3.4 | 0.5 | 0.5 | 0.6 | 0.6 | |||||||||||||||
Total revenues and other income
|
2,828.3 | 2,173.4 | 1,899.6 | 1,516.1 | 979.4 | |||||||||||||||
Costs and expenses:
|
||||||||||||||||||||
Lease operating
|
430.2 | 376.4 | 305.5 | 268.3 | 237.3 | |||||||||||||||
Production taxes
|
225.4 | 171.6 | 139.2 | 103.9 | 64.7 | |||||||||||||||
Depreciation, depletion and amortization
|
891.5 | 684.7 | 468.2 | 393.9 | 394.8 | |||||||||||||||
Exploration and impairment
|
453.2 | 167.0 | 84.6 | 59.4 | 73.0 | |||||||||||||||
General and administrative
|
138.0 | 108.6 | 85.0 | 64.7 | 42.3 | |||||||||||||||
Interest expense
|
112.9 | 75.2 | 62.5 | 59.1 | 64.6 | |||||||||||||||
Loss on early extinguishment of debt
|
4.4 | — | — | 6.2 | — | |||||||||||||||
Change in Production Participation Plan liability
|
(7.0 | ) | 13.8 | (0.9 | ) | 12.1 | 3.3 | |||||||||||||
Commodity derivative (gain) loss, net
|
7.8 | (85.9 | ) | (24.8 | ) | 7.1 | 262.2 | |||||||||||||
Total costs and expenses
|
2,256.4 | 1,511.4 | 1,119.3 | 974.7 | 1,142.2 | |||||||||||||||
Income (loss) before income taxes
|
571.9 | 662.0 | 780.3 | 541.4 | (162.8 | ) | ||||||||||||||
Income tax expense (benefit)
|
205.9 | 247.9 | 288.7 | 204.8 | (55.9 | ) | ||||||||||||||
Net income (loss)
|
366.0 | 414.1 | 491.6 | 336.7 | (106.9 | ) | ||||||||||||||
Net loss attributable to noncontrolling interest
|
0.1 | 0.1 | 0.1 | — | — | |||||||||||||||
Net income (loss) available to shareholders
|
366.1 | 414.2 | 491.7 | 336.7 | (106.9 | ) | ||||||||||||||
Preferred stock dividends
(1)
|
(0.5 | ) | (1.1 | ) | (1.1 | ) | (64.0 | ) | (10.3 | ) | ||||||||||
Net income (loss) available to common shareholders
|
$ | 365.5 | $ | 413.1 | $ | 490.6 | $ | 272.7 | $ | (117.2 | ) | |||||||||
Earnings (loss) per common share, basic
(2)
|
$ | 3.09 | $ | 3.51 | $ | 4.18 | $ | 2.57 | $ | (1.18 | ) | |||||||||
Earnings (loss) per common share, diluted
(2)
|
$ | 3.06 | $ | 3.48 | $ | 4.14 | $ | 2.55 | $ | (1.18 | ) | |||||||||
Other Financial Information:
|
||||||||||||||||||||
Net cash provided by operating activities
|
$ | 1,744.7 | $ | 1,401.2 | $ | 1,192.1 | $ | 997.3 | $ | 453.8 | ||||||||||
Net cash used in investing activities
|
$ | (1,902.5 | ) | $ | (1,780.3 | ) | $ | (1,760.0 | ) | $ | (914.6 | ) | $ | (523.5 | ) | |||||
Net cash provided by (used in) financing activities
|
$ | 812.4 | $ | 408.1 | $ | 564.8 | $ | (75.7 | ) | $ | 72.1 | |||||||||
Capital expenditures
|
$ | 2,772.7 | $ | 2,171.5 | $ | 1,804.3 | $ | 923.8 | $ | 585.8 | ||||||||||
Consolidated Balance Sheet Information:
|
||||||||||||||||||||
Total assets
|
$ | 8,833.5 | $ | 7,272.4 | $ | 6,045.6 | $ | 4,648.8 | $ | 4,029.5 | ||||||||||
Long-term debt
|
$ | 2,653.8 | $ | 1,800.0 | $ | 1,380.0 | $ | 800.0 | $ | 779.6 | ||||||||||
Total equity
(3)
|
$ | 3,836.7 | $ | 3,453.2 | $ | 3,029.1 | $ | 2,531.3 | $ | 2,270.1 |
(1)
|
The year ended December 31, 2010 includes a cash premium of $47.5 million for the induced conversion of our 6.25% Perpetual Preferred Stock.
|
(2)
|
On January 26, 2011, our Board of Directors approved a two-for-one split of the Company's shares of common stock to be effected in the form of a stock dividend effective February 22, 2011. Earnings (loss) per common share, basic and diluted for periods prior to February 2011 have been retroactively adjusted to reflect the stock split.
|
(3)
|
No cash dividends were declared or paid on our common stock during the periods presented.
|
Item 7.
|
Ma
nag
ement’s Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
pursuing the development of projects that we believe will generate attractive rates of return;
|
•
|
allocating a portion of our exploration and development budget to leasing and exploring prospect areas;
|
•
|
maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows; and
|
•
|
seeking property acquisitions that complement our core areas.
|
2012
|
2013
|
|||||||||||||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | |||||||||||||||||||||||||
Crude oil
|
$ | 102.94 | $ | 93.51 | $ | 92.19 | $ | 88.20 | $ | 94.34 | $ | 94.23 | $ | 105.82 | $ | 97.50 | ||||||||||||||||
Natural gas
|
$ | 2.72 | $ | 2.21 | $ | 2.81 | $ | 3.41 | $ | 3.34 | $ | 4.10 | $ | 3.58 | $ | 3.60 |
Development Area
|
2014 Exploration and Development Budget
(in millions)
|
|||
Northern Rockies
|
$ | 1,101.0 | ||
Central Rockies
|
575.0 | |||
Non-operated
|
232.0 | |||
CO
2
EOR project
(1)
|
203.0 | |||
Facilities
|
151.0 | |||
Well work and other
|
150.0 | |||
Exploration
(2)
|
116.0 | |||
Undeveloped acreage
|
116.0 | |||
CO
2
development
(3)
|
56.0 | |||
Total
|
$ | 2,700.0 |
(1)
|
2014 planned capital expenditures at our CO
2
EOR projects include $104.8 million for North Ward Estes CO
2
purchases.
|
(2)
|
Comprised primarily of exploration salaries, seismic activities, lease delay rentals and exploratory drilling.
|
(3)
|
E&D expenditures for the development of organic CO
2
reserves at our Bravo Dome field in New Mexico.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Net production:
|
||||||||||||
Oil (MMBbl)
|
27.0 | 23.1 | 18.3 | |||||||||
NGLs (MMBbl)
|
2.8 | 2.8 | 2.1 | |||||||||
Natural gas (Bcf)
|
26.9 | 25.8 | 26.4 | |||||||||
Total production (MMBOE)
|
34.3 | 30.2 | 24.8 | |||||||||
Net sales (in millions):
|
||||||||||||
Oil
(1)
|
$ | 2,443.7 | $ | 1,940.5 | $ | 1,621.5 | ||||||
NGLs
|
114.0 | 108.9 | 108.6 | |||||||||
Natural gas
(1)
|
108.8 | 88.3 | 130.0 | |||||||||
Total oil, NGL and natural gas sales
|
$ | 2,666.5 | $ | 2,137.7 | $ | 1,860.1 | ||||||
Average sales prices:
|
||||||||||||
Oil (per Bbl)
|
$ | 90.39 | $ | 83.86 | $ | 88.61 | ||||||
Effect of oil hedges on average price (per Bbl)
|
(1.13 | ) | (1.25 | ) | (1.67 | ) | ||||||
Oil net of hedging (per Bbl)
|
$ | 89.26 | $ | 82.61 | $ | 86.94 | ||||||
Average NYMEX price (per Bbl)
|
$ | 98.00 | $ | 94.19 | $ | 95.14 | ||||||
NGLs (per Bbl)
|
$ | 40.41 | $ | 39.36 | $ | 52.38 | ||||||
Natural gas (per Mcf)
|
$ | 4.04 | $ | 3.42 | $ | 4.92 | ||||||
Effect of natural gas hedges on average price (per Mcf)
|
- | 0.06 | 0.04 | |||||||||
Natural gas net of hedging (per Mcf)
|
$ | 4.04 | $ | 3.48 | $ | 4.96 | ||||||
Average NYMEX price (per Mcf)
|
$ | 3.66 | $ | 2.79 | $ | 4.04 | ||||||
Cost and expenses (per BOE):
|
||||||||||||
Lease operating expenses
|
$ | 12.53 | $ | 12.46 | $ | 12.33 | ||||||
Production taxes
|
$ | 6.56 | $ | 5.68 | $ | 5.62 | ||||||
Depreciation, depletion and amortization expense
|
$ | 25.96 | $ | 22.67 | $ | 18.89 | ||||||
General and administrative expenses
|
$ | 4.02 | $ | 3.59 | $ | 3.43 |
(1)
|
Before consideration of hedging transactions.
|
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Depletion
|
$ | 876,208 | $ | 673,789 | ||||
Depreciation
|
4,700 | 3,672 | ||||||
Accretion of asset retirement obligations
|
10,608 | 7,263 | ||||||
Total
|
$ | 891,516 | $ | 684,724 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Exploration
|
$ | 94,755 | $ | 59,117 | ||||
Impairment
|
358,455 | 107,855 | ||||||
Total
|
$ | 453,210 | $ | 166,972 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
General and administrative expenses
|
$ | 251,593 | $ | 199,943 | ||||
Reimbursements and allocations
|
(113,599 | ) | (91,370 | ) | ||||
General and administrative expense, net
|
$ | 137,994 | $ | 108,573 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Senior Notes and Senior Subordinated Notes
|
$ | 73,983 | $ | 40,250 | ||||
Credit agreement
|
27,978 | 28,043 | ||||||
Amortization of debt issue costs and debt premium
|
12,405 | 9,518 | ||||||
Other
|
85 | 148 | ||||||
Capitalized interest
|
(1,515 | ) | (2,749 | ) | ||||
Total
|
$ | 112,936 | $ | 75,210 |
Year Ended December 31,
|
||||||||
2012
|
2011
|
|||||||
Gains (losses) reclassified from AOCI on de-designated hedges
|
$ | 2,338 | $ | 8,758 |
Year Ended December 31,
|
||||||||
2012
|
2011
|
|||||||
Depletion
|
$ | 673,789 | $ | 457,499 | ||||
Depreciation
|
3,672 | 2,688 | ||||||
Accretion of asset retirement obligations
|
7,263 | 8,016 | ||||||
Total
|
$ | 684,724 | $ | 468,203 |
Year Ended December 31,
|
||||||||
2012
|
2011
|
|||||||
Exploration
|
$ | 59,117 | $ | 45,861 | ||||
Impairment
|
107,855 | 38,783 | ||||||
Total
|
$ | 166,972 | $ | 84,644 |
Year Ended December 31,
|
||||||||
2012
|
2011
|
|||||||
General and administrative expenses
|
$ | 199,943 | $ | 153,341 | ||||
Reimbursements and allocations
|
(91,370 | ) | (68,356 | ) | ||||
General and administrative expense, net
|
$ | 108,573 | $ | 84,985 |
Year Ended December 31,
|
||||||||
2012
|
2011
|
|||||||
Senior Subordinated Notes
|
$ | 40,250 | $ | 40,250 | ||||
Credit agreement
|
28,043 | 17,049 | ||||||
Amortization of debt issue costs
|
9,518 | 8,682 | ||||||
Other
|
148 | 109 | ||||||
Capitalized interest
|
(2,749 | ) | (3,574 | ) | ||||
Total
|
$ | 75,210 | $ | 62,516 |
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Rocky Mountains
(1)
|
$ | 2,172,462 | $ | 1,581,934 | $ | 1,364,324 | ||||||
Permian Basin
(2)
|
346,812 | 410,154 | 366,637 | |||||||||
Other
(3)
|
155,918 | 119,431 | 109,193 | |||||||||
Total incurred
|
$ | 2,675,192 | $ | 2,111,519 | $ | 1,840,154 |
(1)
|
For the year ended December 31, 2012, proceeds from the sale of the Belfield gas plant of $66.2 million have been included as a reduction to expenditures in the Rocky Mountains region.
|
(2)
|
For the years ended December 31, 2013 and 2012, amount includes $21.3 million and $10.8 million, respectively, related to the development of CO
2
reserves for use in our North Ward Estes field EOR project. We did not incur any such costs during the year ended December 31, 2011.
|
(3)
|
Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
|
Ratio of Outstanding Borrowings to Borrowing Base
|
Applicable Margin for Base Rate Loans
|
Applicable Margin for Eurodollar Loans
|
Commitment Fee
|
|||
Less than 0.25 to 1.0
|
0.50%
|
1.50%
|
0.375%
|
|||
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
0.75%
|
1.75%
|
0.375%
|
|||
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
1.00%
|
2.00%
|
0.50%
|
|||
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
1.25%
|
2.25%
|
0.50%
|
|||
Greater than or equal to 0.90 to 1.0
|
1.50%
|
2.50%
|
0.50%
|
Payments due by period
|
||||||||||||||||||||
Contractual Obligations
|
Total
|
Less than 1 year
|
1-3 years
|
3-5 years
|
More than 5 years
|
|||||||||||||||
Long-term debt
(1)
|
$ | 2,650,000 | $ | - | $ | - | $ | 350,000 | $ | 2,300,000 | ||||||||||
Cash interest expense on debt
(2)
|
891,896 | 146,750 | 293,500 | 287,813 | 163,833 | |||||||||||||||
Derivative contract liability fair value
(3)
|
3,482 | 3,482 | - | - | - | |||||||||||||||
Asset retirement obligations
(4)
|
126,148 | 9,706 | 19,243 | 21,642 | 75,557 | |||||||||||||||
Tax sharing liability
(5)
|
23,856 | 23,856 | - | - | - | |||||||||||||||
Purchase obligations
(6)
|
632,627 | 82,633 | 227,531 | 111,854 | 210,609 | |||||||||||||||
Drilling rig contracts
(7)
|
137,896 | 87,610 | 50,286 | - | - | |||||||||||||||
Operating leases
(8)
|
28,791 | 6,279 | 11,259 | 9,879 | 1,374 | |||||||||||||||
Construction and drilling contract
(9)
|
44,966 | 31,066 | 2,900 | 11,000 | - | |||||||||||||||
Total
|
$ | 4,539,662 | $ | 391,382 | $ | 604,719 | $ | 792,188 | $ | 2,751,373 |
(1)
|
Long-term debt consists of the principal amounts of the 6.5% Senior Subordinated Notes due 2018, the 5% Senior Notes due 2019 and the 5.75% Senior Notes due 2021.
|
(2)
|
Cash interest expense on the 6.5% Senior Subordinated Notes due 2018, the 5% Senior Notes due 2019 and the 5.75% Senior Notes due 2021 is estimated assuming no principal repayment until the due dates of the instruments. No cash interest expense is assumed on the credit facility as there were no borrowings outstanding as of December 31, 2013.
|
(3)
|
The above derivative obligation at December 31, 2013 primarily consists of (i) a $3.1 million fair value liability for derivative contracts we have entered into on our own behalf, primarily in the form of costless collars, to hedge our exposure to crude oil price fluctuations and (ii) a $0.4 million payable to Trust II for derivative contracts that we have entered into but have in turn conveyed to Trust II (although these derivatives are in a fair value asset position at quarter end, 90% of such derivative assets are due to Trust II under the terms of the conveyance). With respect to only a portion of our open derivative contracts at December 31, 2013 with certain counterparties, the forward price curve for crude oil generally exceeded the price curve that was in effect when these contracts were entered into, resulting in a derivative fair value liability. If current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, we are required to pay the contract counterparties. The ultimate settlement amounts under our derivative contracts are unknown, however, as they are subject to continuing market risk and commodity price volatility.
|
(4)
|
Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants and facilities.
|
(5)
|
Amount shown represents the expected payment due to Alliant Energy based on projected future income tax benefits attributable to an increase in our tax bases. As a result of the Tax Separation and Indemnification Agreement signed with Alliant Energy, the increased tax bases are expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by us. Under this agreement, we have agreed to pay Alliant Energy 90% of the future tax benefits we realize annually as a result of this step up in tax basis. In 2014, we are obligated to pay Alliant Energy the present value of the remaining tax benefits, which assumes that all such tax benefits will be realized in future years.
|
(6)
|
We have three take-or-pay purchase agreements, one agreement expiring in December 2014, one agreement expiring in December 2017 and one agreement expiring in December 2029, whereby we have committed to buy certain volumes of CO
2
for use in our North Ward Estes EOR project in Texas. The purchase agreements are with two different suppliers. Under the terms of the agreements, we are obligated to purchase a minimum daily volume of CO
2
(as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. In addition, we have one ship-or-pay agreement expiring in December 2017, whereby we have committed to transport a minimum daily volume of CO
2
via a certain pipeline or else pay for any deficiencies at a price stipulated in the contract. The CO
2
volumes planned for use in the EOR project in the North Ward Estes field currently exceed the minimum daily volumes specified in all of these agreements. Therefore, we expect to avoid any payments for deficiencies. The purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these contracts. However, our actual expenditures under these contracts are expected to exceed the minimum commitments presented above.
|
(7)
|
We currently have 12 drilling rigs under long-term contract, of which six drilling rigs expire in 2014, four in 2015 and two in 2016. All of these rigs are operating in the Rocky Mountains region. As of December 31, 2013, early termination of the remaining contracts would require termination penalties of $101.1 million, which would be in lieu of paying the remaining drilling commitments of $137.9 million. No other drilling rigs working for us are currently under long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled. Due to the short-term and indeterminate nature of the time remaining on rigs drilling on a well-by-well basis, such obligations have not been included in this table.
|
(8)
|
We lease 172,400 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2018, 47,900 square feet of office space in Midland, Texas expiring in 2020 and 20,000 square feet of office space in Dickinson, North Dakota expiring in 2016. In addition, we entered into a lease for several residential apartments in Watford City and Dickinson, North Dakota under an operating lease agreement expiring in 2015.
|
(9)
|
We have a contractual obligation of up to $51.4 million to fund the construction of certain facilities and field infrastructure and the drilling of forty-six CO
2
wells in our Bravo Dome field. If we fail to spend the required amounts by the dates set forth in the agreement, we will be required to pay the remaining unspent capital expenditures as liquidated damages. However, we expect to fulfill our obligations under this contract and thereby avoid any payments for deficiencies. We do not have any volumetric CO
2
delivery or supply commitments associated with this contract.
|
•
|
the quality and quantity of available data;
|
•
|
the interpretation of that data;
|
•
|
the accuracy of various mandated economic assumptions; and
|
•
|
the judgments of the persons preparing the estimates.
|
Item 7A.
|
Q
uan
titative and Qualitative Disclosures about Market Risk
|
Derivative Instrument
|
Commodity
|
Period
|
Monthly Volume
(Bbl)
|
Weighted Average NYMEX Floor/Ceiling
|
||||
Three-way collars
(1)
|
Crude Oil
|
01/2014
|
1,200,000
|
$71.00/$85.00/$103.56
|
||||
Crude Oil
|
02/2014
|
1,280,000
|
$70.94/$85.00/$103.34
|
|||||
Crude Oil
|
03/2014
|
1,280,000
|
$70.94/$85.00/$103.34
|
|||||
Crude Oil
|
04/2014 to 06/2014
|
1,280,000
|
$70.94/$85.00/$103.34
|
|||||
Crude Oil
|
07/2014 to 09/2014
|
1,280,000
|
$70.94/$85.00/$103.34
|
|||||
Crude Oil
|
10/2014 to 12/2014
|
1,280,000
|
$70.94/$85.00/$103.34
|
(1)
|
A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
|
Commodity
|
Period
|
Average Monthly Volume
(MMBtu)
|
Weighted Average Price Per MMBtu
|
|||
Natural Gas
|
01/2014 to 03/2014
|
330,000
|
$5.49
|
|||
Natural Gas
|
04/2014 to 06/2014
|
333,667
|
$5.49
|
|||
Natural Gas
|
07/2014 to 09/2014
|
337,333
|
$5.49
|
|||
Natural Gas
|
10/2014 to 12/2014
|
337,333
|
$5.49
|
Commodity
|
Period
|
Average Monthly Volume
(Bbl)
|
||
Crude Oil
|
01/2015 to 12/2015
|
760,417
|
||
Crude Oil
|
01/2016 to 12/2016
|
915,000
|
||
Crude Oil
|
01/2017 to 12/2017
|
1,064,583
|
||
Crude Oil
|
01/2018 to 12/2018
|
1,216,667
|
||
Crude Oil
|
01/2019 to 12/2019
|
1,368,750
|
Derivative Instrument
|
Commodity
|
Period
|
Monthly Volume
(Bbl)
|
NYMEX Floor/Ceiling
|
||||
Collars
|
Crude Oil
|
01/2014 to 03/2014
|
42,500
|
$80.00/$122.50
|
||||
Crude Oil
|
04/2014 to 06/2014
|
41,500
|
$80.00/$122.50
|
|||||
Crude Oil
|
07/2014 to 09/2014
|
40,600
|
$80.00/$122.50
|
|||||
Crude Oil
|
10/2014 to 12/2014
|
39,700
|
$80.00/$122.50
|
Item 8.
|
F
inan
cial Statements and Supplementary Data
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Report of Independent Registered Public Accounting Firm
|
75
|
Consolidated Balance Sheets as of December 31, 2013 and 2012
|
76
|
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011
|
77
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011
|
78
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
|
79
|
Consolidated Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011
|
81
|
Notes to Consolidated Financial Statements
|
82
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
ASSETS
|
||||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 699,460 | $ | 44,800 | ||||
Accounts receivable trade, net
|
341,177 | 318,265 | ||||||
Prepaid expenses and other
|
28,981 | 21,347 | ||||||
Total current assets
|
1,069,618 | 384,412 | ||||||
Property and equipment:
|
||||||||
Oil and gas properties, successful efforts method
|
10,065,150 | 9,211,998 | ||||||
Other property and equipment
|
206,385 | 141,738 | ||||||
Total property and equipment
|
10,271,535 | 9,353,736 | ||||||
Less accumulated depreciation, depletion and amortization
|
(2,676,490 | ) | (2,590,203 | ) | ||||
Total property and equipment, net
|
7,595,045 | 6,763,533 | ||||||
Debt issuance costs
|
48,530 | 28,748 | ||||||
Other long-term assets
|
120,277 | 95,726 | ||||||
TOTAL ASSETS
|
$ | 8,833,470 | $ | 7,272,419 | ||||
LIABILITIES AND EQUITY
|
||||||||
Current liabilities:
|
||||||||
Accounts payable trade
|
$ | 107,692 | $ | 131,370 | ||||
Accrued capital expenditures
|
158,739 | 110,663 | ||||||
Accrued liabilities and other
|
214,109 | 170,207 | ||||||
Revenues and royalties payable
|
198,558 | 149,692 | ||||||
Taxes payable
|
50,052 | 33,283 | ||||||
Accrued interest
|
44,405 | 10,415 | ||||||
Derivative liabilities
|
3,482 | 21,955 | ||||||
Deferred income taxes
|
648 | 9,394 | ||||||
Total current liabilities
|
777,685 | 636,979 | ||||||
Long-term debt
|
2,653,834 | 1,800,000 | ||||||
Deferred income taxes
|
1,278,030 | 1,063,681 | ||||||
Derivative liabilities
|
- | 1,678 | ||||||
Production Participation Plan liability
|
87,503 | 94,483 | ||||||
Asset retirement obligations
|
116,442 | 86,179 | ||||||
Deferred gain on sale
|
79,065 | 110,395 | ||||||
Other long-term liabilities
|
4,212 | 25,852 | ||||||
Total liabilities
|
4,996,771 | 3,819,247 | ||||||
Commitments and contingencies
|
||||||||
Equity:
|
||||||||
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, no shares authorized, issued or outstanding as of December 31, 2013 and 172,391 shares issued and outstanding as of December 31, 2012
|
- | - | ||||||
Common stock, $0.001 par value, 300,000,000 shares authorized; 120,101,555 issued and 118,657,245 outstanding as of December 31, 2013 and 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012
|
120 | 119 | ||||||
Additional paid-in capital
|
1,583,542 | 1,566,717 | ||||||
Accumulated other comprehensive loss
|
- | (1,236 | ) | |||||
Retained earnings
|
2,244,905 | 1,879,388 | ||||||
Total Whiting shareholders’ equity
|
3,828,567 | 3,444,988 | ||||||
Noncontrolling interest
|
8,132 | 8,184 | ||||||
Total equity
|
3,836,699 | 3,453,172 | ||||||
TOTAL LIABILITIES AND EQUITY
|
$ | 8,833,470 | $ | 7,272,419 | ||||
See notes to consolidated financial statements.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
REVENUES AND OTHER INCOME:
|
||||||||||||
Oil, NGL and natural gas sales
|
$ | 2,666,549 | $ | 2,137,714 | $ | 1,860,146 | ||||||
Gain (loss) on hedging activities
|
(1,958 | ) | 2,338 | 8,758 | ||||||||
Amortization of deferred gain on sale
|
31,737 | 29,458 | 13,937 | |||||||||
Gain on sale of properties
|
128,648 | 3,423 | 16,313 | |||||||||
Interest income and other
|
3,409 | 519 | 468 | |||||||||
Total revenues and other income
|
2,828,385 | 2,173,452 | 1,899,622 | |||||||||
COSTS AND EXPENSES:
|
||||||||||||
Lease operating
|
430,221 | 376,424 | 305,487 | |||||||||
Production taxes
|
225,403 | 171,625 | 139,190 | |||||||||
Depreciation, depletion and amortization
|
891,516 | 684,724 | 468,203 | |||||||||
Exploration and impairment
|
453,210 | 166,972 | 84,644 | |||||||||
General and administrative
|
137,994 | 108,573 | 84,985 | |||||||||
Interest expense
|
112,936 | 75,210 | 62,516 | |||||||||
Loss on early extinguishment of debt
|
4,412 | - | - | |||||||||
Change in Production Participation Plan liability
|
(6,980 | ) | 13,824 | (865 | ) | |||||||
Commodity derivative (gain) loss, net
|
7,802 | (85,911 | ) | (24,857 | ) | |||||||
Total costs and expenses
|
2,256,514 | 1,511,441 | 1,119,303 | |||||||||
INCOME BEFORE INCOME TAXES
|
571,871 | 662,011 | 780,319 | |||||||||
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||
Current
|
986 | (669 | ) | 3,853 | ||||||||
Deferred
|
204,882 | 248,581 | 284,838 | |||||||||
Total income tax expense
|
205,868 | 247,912 | 288,691 | |||||||||
NET INCOME
|
366,003 | 414,099 | 491,628 | |||||||||
Net loss attributable to noncontrolling interest
|
52 | 90 | 59 | |||||||||
NET INCOME AVAILABLE TO SHAREHOLDERS
|
366,055 | 414,189 | 491,687 | |||||||||
Preferred stock dividends
|
(538 | ) | (1,077 | ) | (1,077 | ) | ||||||
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 365,517 | $ | 413,112 | $ | 490,610 | ||||||
EARNINGS PER COMMON SHARE:
|
||||||||||||
Basic
|
$ | 3.09 | $ | 3.51 | $ | 4.18 | ||||||
Diluted
|
$ | 3.06 | $ | 3.48 | $ | 4.14 | ||||||
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||||||
Basic
|
118,260 | 117,601 | 117,345 | |||||||||
Diluted
|
119,588 | 119,028 | 118,668 | |||||||||
See notes to consolidated financial statements.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
NET INCOME
|
$ | 366,003 | $ | 414,099 | $ | 491,628 | ||||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
|
||||||||||||
OCI amortization on de-designated hedges
(1)(2)
|
1,236 | (1,476 | ) | (5,528 | ) | |||||||
Total other comprehensive income (loss), net of tax
|
1,236 | (1,476 | ) | (5,528 | ) | |||||||
COMPREHENSIVE INCOME
|
367,239 | 412,623 | 486,100 | |||||||||
Comprehensive loss attributable to noncontrolling interest
|
52 | 90 | 59 | |||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING
|
$ | 367,291 | $ | 412,713 | $ | 486,159 | ||||||
(1)
Presented net of income tax expense of $722 for the year ended December 31, 2013 and income tax benefits of $862 and $3,230 for the years ended December 31, 2012 and 2011, respectively.
|
||||||||||||
(2)
These gain (loss) amounts on de-designated hedges are reclassified from accumulated other comprehensive income (“AOCI”) to gain (loss) on hedging activities in the consolidated statements of income.
|
||||||||||||
See notes to consolidated financial statements.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
Net income
|
$ | 366,003 | $ | 414,099 | $ | 491,628 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
Depreciation, depletion and amortization
|
891,516 | 684,724 | 468,203 | |||||||||
Deferred income tax expense
|
204,882 | 248,581 | 284,838 | |||||||||
Amortization of debt issuance costs and debt premium
|
12,405 | 9,518 | 8,682 | |||||||||
Stock-based compensation
|
22,436 | 18,190 | 13,509 | |||||||||
Amortization of deferred gain on sale
|
(31,737 | ) | (29,458 | ) | (13,937 | ) | ||||||
Gain on sale of properties
|
(128,648 | ) | (3,423 | ) | (16,313 | ) | ||||||
Undeveloped leasehold and oil and gas property impairments
|
358,455 | 107,855 | 38,783 | |||||||||
Exploratory dry hole costs
|
28,725 | 18,428 | 4,924 | |||||||||
Loss on early extinguishment of debt
|
4,412 | - | - | |||||||||
Change in Production Participation Plan liability
|
(6,980 | ) | 13,824 | (865 | ) | |||||||
Non-cash portion of derivative (gains) and losses
|
(20,830 | ) | (115,733 | ) | (63,093 | ) | ||||||
Other, net
|
(16,118 | ) | (18,708 | ) | (13,512 | ) | ||||||
Changes in current assets and liabilities:
|
||||||||||||
Accounts receivable trade
|
(22,912 | ) | (55,750 | ) | (62,802 | ) | ||||||
Prepaid expenses and other
|
(15,981 | ) | 2,535 | (3,771 | ) | |||||||
Accounts payable trade and accrued liabilities
|
33,360 | 58,647 | 33,135 | |||||||||
Revenues and royalties payable
|
48,988 | 45,798 | 21,770 | |||||||||
Taxes payable
|
16,769 | 2,088 | 904 | |||||||||
Net cash provided by operating activities
|
1,744,745 | 1,401,215 | 1,192,083 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
Drilling and development capital expenditures
|
(2,349,819 | ) | (2,050,029 | ) | (1,554,271 | ) | ||||||
Acquisition of oil and gas properties
|
(422,923 | ) | (125,282 | ) | (193,809 | ) | ||||||
Other property and equipment
|
(45,304 | ) | 3,852 | (56,232 | ) | |||||||
Proceeds from sale of oil and gas properties
|
968,606 | 69,190 | 69,276 | |||||||||
Net proceeds from sale of 18,400,000 units in Whiting USA Trust II
|
- | 322,257 | - | |||||||||
Issuance of note receivable
|
(10,530 | ) | (306 | ) | (25,000 | ) | ||||||
Cash paid for investing derivatives
|
(44,900 | ) | - | - | ||||||||
Cash settlements received on investing derivatives
|
2,371 | - | - | |||||||||
Net cash used in investing activities
|
(1,902,499 | ) | (1,780,318 | ) | (1,760,036 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
Issuance of 5% Senior Notes due 2019
|
1,100,000 | - | - | |||||||||
Issuance of 5.75% Senior Notes due 2021
|
1,204,000 | - | - | |||||||||
Redemption of 7% Senior Subordinated Notes due 2014
|
(253,988 | ) | - | - | ||||||||
Long-term borrowings under credit agreement
|
1,860,000 | 2,340,000 | 1,760,000 | |||||||||
Repayments of long-term borrowings under credit agreement
|
(3,060,000 | ) | (1,920,000 | ) | (1,180,000 | ) | ||||||
Debt issuance costs
|
(29,690 | ) | (2,807 | ) | (5,691 | ) | ||||||
Restricted stock used for tax withholdings
|
(5,611 | ) | (5,695 | ) | (9,049 | ) | ||||||
Repayments to Alliant Energy Corporation
|
(1,759 | ) | (2,329 | ) | (1,871 | ) | ||||||
Preferred stock dividends paid
|
(538 | ) | (1,077 | ) | (1,077 | ) | ||||||
Contributions from noncontrolling interest
|
- | - | 2,500 | |||||||||
Net cash provided by financing activities
|
$ | 812,414 | $ | 408,092 | $ | 564,812 | ||||||
See notes to consolidated financial statements.
|
(Continued)
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
$ | 654,660 | $ | 28,989 | $ | (3,141 | ) | |||||
CASH AND CASH EQUIVALENTS:
|
||||||||||||
Beginning of period
|
44,800 | 15,811 | 18,952 | |||||||||
End of period
|
$ | 699,460 | $ | 44,800 | $ | 15,811 | ||||||
SUPPLEMENTAL CASH FLOW DISCLOSURES:
|
||||||||||||
Income taxes paid (refunded), net
|
$ | 3,681 | $ | (268 | ) | $ | 4,065 | |||||
Interest paid, net of amounts capitalized
|
$ | 66,541 | $ | 68,005 | $ | 53,761 | ||||||
NONCASH INVESTING ACTIVITIES:
|
||||||||||||
Accrued capital expenditures
|
$ | 158,739 | $ | 110,663 | $ | 142,827 | ||||||
NONCASH FINANCING ACTIVITIES:
|
||||||||||||
Contributions from noncontrolling interest
|
$ | - | $ | - | $ | 5,833 | ||||||
See notes to consolidated financial statements.
|
(Concluded)
|
Preferred Stock
|
Common Stock
|
Additional Paid-in
|
Accumulated Other Comprehensive
|
Retained
|
Total Whiting Shareholders’
|
Noncontrolling
|
||||||||||||||||||||||||||||||||||
Shares
|
Amount
|
Shares
|
Amount
|
Capital
|
Income (Loss)
|
Earnings
|
Equity
|
Interest
|
Total Equity
|
|||||||||||||||||||||||||||||||
BALANCES-January 1, 2011
|
173 | $ | - | 117,968 | $ | 59 | $ | 1,549,822 | $ | 5,768 | $ | 975,666 | $ | 2,531,315 | $ | - | $ | 2,531,315 | ||||||||||||||||||||||
Net income (loss)
|
- | - | - | - | - | 491,687 | 491,687 | (59 | ) | 491,628 | ||||||||||||||||||||||||||||||
Other comprehensive income
|
- | - | - | - | - | (5,528 | ) | - | (5,528 | ) | - | (5,528 | ) | |||||||||||||||||||||||||||
Conversion of preferred stock to common
|
(1 | ) | - | 1 | - | - | - | - | - | - |
-
|
|||||||||||||||||||||||||||||
Two-for-one stock split
|
- | - | - | 59 | (59 | ) | - | - | - | - | - | |||||||||||||||||||||||||||||
Contributions from noncontrolling interest
|
- | - | - | - | - | - | - | - | 8,333 | 8,333 | ||||||||||||||||||||||||||||||
Restricted stock issued
|
- | - | 304 | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Restricted stock forfeited
|
- | - | (20 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||
Restricted stock used for tax withholdings
|
- | - | (148 | ) | - | (9,049 | ) | - | - | (9,049 | ) | - | (9,049 | ) | ||||||||||||||||||||||||||
Stock-based compensation
|
- | - | - | - | 13,509 | - | - | 13,509 | - | 13,509 | ||||||||||||||||||||||||||||||
Preferred dividends paid
|
- | - | - | - | - | - | (1,077 | ) | (1,077 | ) | - | (1,077 | ) | |||||||||||||||||||||||||||
BALANCES-December 31, 2011
|
172 | - | 118,105 | 118 | 1,554,223 | 240 | 1,466,276 | 3,020,857 | 8,274 | 3,029,131 | ||||||||||||||||||||||||||||||
Net income (loss)
|
- | - | - | - | - | - | 414,189 | 414,189 | (90 | ) | 414,099 | |||||||||||||||||||||||||||||
Other comprehensive income
|
- | - | - | - | - | (1,476 | ) | - | (1,476 | ) | - | (1,476 | ) | |||||||||||||||||||||||||||
Restricted stock issued
|
- | - | 592 | 1 | (1 | ) | - | - | - | - | - | |||||||||||||||||||||||||||||
Restricted stock forfeited
|
- | - | (9 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||
Restricted stock used for tax withholdings
|
- | - | (106 | ) | - | (5,695 | ) | - | - | (5,695 | ) | - | (5,695 | ) | ||||||||||||||||||||||||||
Stock-based compensation
|
- | - | - | - | 18,190 | - | - | 18,190 | - | 18,190 | ||||||||||||||||||||||||||||||
Preferred dividends paid
|
- | - | - | - | - | - | (1,077 | ) | (1,077 | ) | - | (1,077 | ) | |||||||||||||||||||||||||||
BALANCES-December 31, 2012
|
172 | - | 118,582 | 119 | 1,566,717 | (1,236 | ) | 1,879,388 | 3,444,988 | 8,184 | 3,453,172 | |||||||||||||||||||||||||||||
Net income (loss)
|
- | - | - | - | - | - | 366,055 | 366,055 | (52 | ) | 366,003 | |||||||||||||||||||||||||||||
Other comprehensive loss
|
- | - | - | - | - | 1,236 | - | 1,236 | - | 1,236 | ||||||||||||||||||||||||||||||
Conversion of preferred stock to common
|
(172 | ) | - | 794 | 1 | - | - | - | 1 | - | 1 | |||||||||||||||||||||||||||||
Restricted stock issued
|
- | - | 941 | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Restricted stock forfeited
|
- | - | (100 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||
Restricted stock used for tax withholdings
|
- | - | (115 | ) | - | (5,611 | ) | - | - | (5,611 | ) | - | (5,611 | ) | ||||||||||||||||||||||||||
Stock-based compensation
|
- | - | - | - | 22,436 | - | - | 22,436 | - | 22,436 | ||||||||||||||||||||||||||||||
Preferred dividends paid
|
- | - | - | - | - | - | (538 | ) | (538 | ) | - | (538 | ) | |||||||||||||||||||||||||||
BALANCES-December 31, 2013
|
- | $ | - | 120,102 | $ | 120 | $ | 1,583,542 | $ | - | $ | 2,244,905 | $ | 3,828,567 | $ | 8,132 | $ | 3,836,699 | ||||||||||||||||||||||
See notes to consolidated financial statements.
|
1.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
2013
|
2012
|
2011
|
|||
Plains Marketing LP
|
21%
|
20%
|
27%
|
||
Shell Trading US
|
14%
|
14%
|
13%
|
||
Eighty Eight Oil Company
|
11%
|
11%
|
8%
|
||
Bridger Trading LLC
|
8%
|
11%
|
6%
|
2.
|
OIL AND GAS PROPERTIES
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
Proved leasehold costs
|
$ | 1,633,495 | $ | 2,119,541 | ||||
Unproved leasehold costs
|
372,298 | 362,483 | ||||||
Costs of completed wells and facilities
|
7,563,350 | 6,369,170 | ||||||
Wells and facilities in progress
|
496,007 | 360,804 | ||||||
Total oil and gas properties, successful efforts method
|
10,065,150 | 9,211,998 | ||||||
Accumulated depletion
|
(2,645,841 | ) | (2,564,081 | ) | ||||
Oil and gas properties, net
|
$ | 7,419,309 | $ | 6,647,917 |
3.
|
ACQUISITIONS AND DIVESTITURES
|
Purchase price
|
$ | 258,892 | ||
Allocation of purchase price:
|
||||
Proved properties
|
$ | 232,187 | ||
Unproved properties
|
27,335 | |||
Oil in tank inventory
|
692 | |||
Accounts receivable
|
578 | |||
Asset retirement obligations
|
(1,900 | ) | ||
Total
|
$ | 258,892 |
Period
|
Contracted Crude Oil Volumes (Bbl)
|
NYMEX Price for Crude Oil
(per Bbl)
|
||
Apr – Dec 2013
|
1,677,500
|
$98.50
|
||
Jan – Dec 2014
|
2,007,500
|
$94.75
|
||
Jan – Dec 2015
|
1,825,000
|
$94.75
|
||
Jan – Mar 2016
|
400,400
|
$93.50
|
||
Total
|
5,910,400
|
4.
|
LONG-TERM DEBT
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
Credit agreement
|
$ | - | $ | 1,200,000 | ||||
7% Senior Subordinated Notes due 2014
|
- | 250,000 | ||||||
6.5% Senior Subordinated Notes due 2018
|
350,000 | 350,000 | ||||||
5% Senior Notes due 2019
|
1,100,000 | - | ||||||
5.75% Senior Notes due 2021, including unamortized debt premium of $3,834
|
1,203,834 | - | ||||||
Total debt
|
$ | 2,653,834 | $ | 1,800,000 |
2014
|
2015
|
2016
|
2017
|
2018
|
||||||||||||||||
Long-term debt
|
$ | - | $ | - | $ | - | $ | - | $ | 350,000 |
Ratio of Outstanding Borrowings to Borrowing Base
|
Applicable Margin for Base Rate Loans
|
Applicable Margin for Eurodollar Loans
|
Commitment Fee
|
|||
Less than 0.25 to 1.0
|
0.50%
|
1.50%
|
0.375%
|
|||
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
0.75%
|
1.75%
|
0.375%
|
|||
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
1.00%
|
2.00%
|
0.50%
|
|||
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
1.25%
|
2.25%
|
0.50%
|
|||
Greater than or equal to 0.90 to 1.0
|
1.50%
|
2.50%
|
0.50%
|
5.
|
ASSET RETIREMENT OBLIGATIONS
|
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Asset retirement obligation at January 1
|
$ | 97,818 | $ | 69,721 | ||||
Additional liability incurred
|
17,535 | 9,292 | ||||||
Revisions in estimated cash flows
|
12,225 | 23,162 | ||||||
Accretion expense
|
10,608 | 7,263 | ||||||
Obligations on sold properties
|
(3,630 | ) | (4 | ) | ||||
Liabilities settled
|
(8,408 | ) | (11,616 | ) | ||||
Asset retirement obligation at December 31
|
$ | 126,148 | $ | 97,818 |
6.
|
DERIVATIVE FINANCIAL INSTRUMENTS
|
Whiting Petroleum Corporation
|
||||||
Derivative Instrument
|
Period
|
Contracted Crude Oil Volumes
(Bbl)
|
Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
|
|||
Collars
|
Jan – Dec 2014
|
49,290
|
$ 80.00 - $122.50
|
|||
Three-way collars
(1)
|
Jan – Dec 2014
|
15,280,000
|
$70.94 - $85.00 - $103.35
|
|||
Total
|
15,329,290
|
(1)
|
A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
|
Whiting Petroleum Corporation
|
||||||
Derivative Instrument
|
Period
|
Contracted Crude Oil Volumes
(Bbl)
|
NYMEX Price Collar Ranges for Crude Oil
(per Bbl)
|
|||
Collars
|
Jan – Dec 2014
|
49,290
|
$80.00 - $122.50
|
Third-party Public Holders of Trust II Units
|
||||||
Derivative Instrument
|
Period
|
Contracted Crude Oil Volumes
(Bbl)
|
NYMEX Price Collar Ranges for Crude Oil
(per Bbl)
|
|||
Collars
|
Jan – Dec 2014
|
443,610
|
$80.00 - $122.50
|
Gain (Loss) Reclassified from AOCI
into Income
(Effective Portion)
(1)
|
||||||||||
ASC 815 Cash Flow
|
Year Ended December 31,
|
|||||||||
Hedging Relationships
(1)
|
Income Statement Classification
|
2013
|
2012
|
|||||||
Commodity contracts
|
Gain (loss) on hedging activities
|
$ | (1,958 | ) | $ | 2,338 |
(1)
|
Effective April 1, 2009, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were being reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts had been reclassified into earnings.
|
(Gain) Loss Recognized in Income
|
||||||||||
Not Designated as
|
Year Ended December 31,
|
|||||||||
ASC 815 Hedges
|
Income Statement Classification
|
2013
|
2012
|
|||||||
Commodity contracts
|
Commodity derivative (gain) loss, net
|
$ | 20,503 | $ | (75,782 | ) | ||||
Embedded commodity contracts
|
Commodity derivative (gain) loss, net
|
(12,701 | ) | (10,129 | ) | |||||
Total
|
$ | 7,802 | $ | (85,911 | ) |
December 31, 2013
(1)
|
||||||||||||||
Not Designated as
ASC 815 Hedges
|
Balance Sheet Classification
|
Gross Recognized Assets/
Liabilities
|
Gross Amounts Offset
|
Net Recognized Fair Value Assets/
Liabilities
|
||||||||||
Derivative assets:
|
||||||||||||||
Commodity contracts
|
Prepaid expenses and other
|
$ | 23,752 | $ | (22,478 | ) | $ | 1,274 | ||||||
Embedded commodity contracts
|
Other long-term assets
|
36,416 | - | 36,416 | ||||||||||
Total derivative assets
|
$ | 60,168 | $ | (22,478 | ) | $ | 37,690 | |||||||
Derivative liabilities:
|
||||||||||||||
Commodity contracts
|
Current derivative liabilities
|
$ | 25,960 | $ | (22,478 | ) | $ | 3,482 | ||||||
Total derivative liabilities
|
$ | 25,960 | $ | (22,478 | ) | $ | 3,482 |
December 31, 2012
(1)
|
||||||||||||||
Not Designated as
ASC 815 Hedges
|
Balance Sheet Classification
|
Gross Recognized Assets/
Liabilities
|
Gross Amounts Offset
|
Net Recognized Fair Value Assets/
Liabilities
|
||||||||||
Derivative assets:
|
||||||||||||||
Commodity contracts
|
Prepaid expenses and other
|
$ | 40,909 | $ | (31,437 | ) | $ | 9,472 | ||||||
Commodity contracts
|
Other long-term assets
|
4,053 | (2,189 | ) | 1,864 | |||||||||
Embedded commodity contracts
|
Other long-term assets
|
24,038 | (323 | ) | 23,715 | |||||||||
Total derivative assets
|
$ | 69,000 | $ | (33,949 | ) | $ | 35,051 | |||||||
Derivative liabilities:
|
||||||||||||||
Commodity contracts
|
Current derivative liabilities
|
$ | 53,392 | $ | (31,437 | ) | $ | 21,955 | ||||||
Commodity contracts
|
Non-current derivative liabilities
|
3,867 | (2,189 | ) | 1,678 | |||||||||
Embedded commodity contracts
|
Non-current derivative liabilities
|
323 | (323 | ) | - | |||||||||
Total derivative liabilities
|
$ | 57,582 | $ | (33,949 | ) | $ | 23,633 |
(1)
|
Because counterparties to the Company’s derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
|
7.
|
FAIR VALUE MEASUREMENTS
|
·
|
Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
·
|
Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
|
·
|
Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
|
Level 1
|
Level 2
|
Level 3
|
Total Fair Value
December 31, 2013
|
|||||||||||||
Financial Assets
|
||||||||||||||||
Commodity derivatives – current
|
$ | - | $ | 1,274 | $ | - | $ | 1,274 | ||||||||
Embedded commodity derivatives – non-current
|
- | - | 36,416 | 36,416 | ||||||||||||
Total financial assets
|
$ | - | $ | 1,274 | $ | 36,416 | $ | 37,690 | ||||||||
Financial Liabilities
|
||||||||||||||||
Commodity derivatives – current
|
$ | - | $ | 3,482 | $ | - | $ | 3,482 | ||||||||
Total financial liabilities
|
$ | - | $ | 3,482 | $ | - | $ | 3,482 |
Level 1
|
Level 2
|
Level 3
|
Total Fair Value
December 31, 2012
|
|||||||||||||
Financial Assets
|
||||||||||||||||
Commodity derivatives – current
|
$ | - | $ | 9,472 | $ | - | $ | 9,472 | ||||||||
Commodity derivatives – non-current
|
- | 1,864 | - | 1,864 | ||||||||||||
Embedded commodity derivatives – non-current
|
- | - | 23,715 | 23,715 | ||||||||||||
Total financial assets
|
$ | - | $ | 11,336 | $ | 23,715 | $ | 35,051 | ||||||||
Financial Liabilities
|
||||||||||||||||
Commodity derivatives – current
|
$ | - | $ | 21,955 | $ | - | $ | 21,955 | ||||||||
Commodity derivatives – non-current
|
- | 1,678 | - | 1,678 | ||||||||||||
Total financial liabilities
|
$ | - | $ | 23,633 | $ | - | $ | 23,633 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Fair value asset, beginning of period
|
$ | 23,715 | $ | 12,980 | ||||
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings
(1)
|
12,701 | 10,735 | ||||||
Transfers into (out of) Level 3
|
- | - | ||||||
Fair value asset, end of period
|
$ | 36,416 | $ | 23,715 |
(1)
|
Included in commodity derivative (gain) loss, net in the consolidated statements of income.
|
Fair Value at
December 31, 2013
(in thousands)
|
Valuation Technique
|
Unobservable
Input
|
Range
(per Bbl)
|
|||||
Embedded commodity derivative
|
$ 36,416
|
Option model
|
Future prices of NYMEX crude oil after March 31, 2022
|
$79.87 - $95.75
|
(1)
|
During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373.2 million were written down to their fair value of $106.1 million, resulting in a non-cash impairment charge of $267.1 million. The impairment consisted of (i) a $220.8 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46.3 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.
|
(1)
|
During the year ended December 31, 2012, proved oil and gas properties with a carrying amount of $70.4 million were written down to their fair value of $23.5 million, resulting in a non-cash impairment charge of $46.9 million. The impairment consisted primarily of a $46.3 million write-down in the Rocky Mountains region related to changes in estimated reserves at December 31, 2012.
|
8.
|
DEFERRED COMPENSATION
|
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Long-term Production Participation Plan liability at January 1
|
$ | 94,483 | $ | 80,659 | ||||
Change in liability for accretion, vesting, changes in estimates and new Plan year activity
|
66,284 | 63,135 | ||||||
Accrued compensation expense reflected as a current liability
|
(73,264 | ) | (49,311 | ) | ||||
Long-term Production Participation Plan liability at December 31
|
$ | 87,503 | $ | 94,483 |
9.
|
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
|
2013
|
2012
|
2011
|
||||
Number of simulations
|
65,000
|
65,000
|
65,000
|
|||
Expected volatility
|
43.1%
|
51.9%
|
75.8%
|
|||
Risk-free rate
|
0.41%
|
0.35%
|
1.00%
|
|||
Dividend yield
|
-
|
-
|
-
|
Number
of Shares
|
Weighted Average
Grant Date
Fair Value
|
|||||||
Restricted stock awards nonvested, January 1, 2011
|
869,370 | $ | 16.27 | |||||
Granted
|
304,355 | 48.48 | ||||||
Vested
|
(429,136 | ) | 15.32 | |||||
Forfeited
|
(20,194 | ) | 33.53 | |||||
Restricted stock awards nonvested, December 31, 2011
|
724,395 | 29.88 | ||||||
Granted
|
592,400 | 34.45 | ||||||
Vested
|
(357,170 | ) | 17.91 | |||||
Forfeited
|
(8,599 | ) | 51.72 | |||||
Restricted stock awards nonvested, December 31, 2012
|
951,026 | 37.02 | ||||||
Granted
|
940,792 | 27.59 | ||||||
Vested
|
(347,824 | ) | 35.32 | |||||
Forfeited
|
(99,684 | ) | 30.95 | |||||
Restricted stock awards nonvested, December 31, 2013
|
1,444,310 | $ | 31.71 |
2012
|
2011
|
||
Risk-free interest rate
|
1.19%
|
2.47%
|
|
Expected volatility
|
61.4%
|
59.3%
|
|
Expected term
|
6.0 yrs.
|
6.0 yrs.
|
|
Dividend yield
|
-
|
-
|
Number of Options
|
Weighted Average Exercise Price per Share
|
Aggregate Intrinsic Value
(in thousands)
|
Weighted Average Remaining Contractual Term
(in years)
|
||||||||||
Options outstanding at January 1, 2011
|
296,516 | $ | 16.78 | ||||||||||
Granted
|
80,820 | 60.28 | |||||||||||
Exercised
|
- | - | $ | - | |||||||||
Forfeited or expired
|
- | - | |||||||||||
Options outstanding at December 31, 2011
|
377,336 | 26.09 | |||||||||||
Granted
|
45,359 | 51.22 | |||||||||||
Exercised
|
- | - | $ | - | |||||||||
Forfeited or expired
|
- | - | |||||||||||
Options outstanding at December 31, 2012
|
422,695 | 28.79 | |||||||||||
Granted
|
- | - | |||||||||||
Exercised
|
- | - | $ | - | |||||||||
Forfeited or expired
|
(1,855 | ) | 60.28 | ||||||||||
Options outstanding at December 31, 2013
|
420,840 | $ | 28.65 | $ | 13,979.6 |
5.9
|
|||||||
Options vested and expected to vest at December 31, 2013
|
420,840 | $ | 28.65 | $ | 13,979.6 |
5.9
|
|||||||
Options exercisable at December 31, 2013
|
365,511 | $ | 24.61 | $ | 13,617.8 |
5.7
|
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Balance at January 1
|
$ | 8,184 | $ | 8,274 | ||||
Net income (loss)
|
(52 | ) | (90 | ) | ||||
Balance at December 31
|
$ | 8,132 | $ | 8,184 |
10.
|
INCOME TAXES
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Current income tax expense (refund):
|
||||||||||||
Federal
|
$ | 7,060 | $ | - | $ | 107 | ||||||
State
|
(6,074 | ) | (669 | ) | 3,746 | |||||||
Total current income tax expense
|
986 | (669 | ) | 3,853 | ||||||||
Deferred income tax expense:
|
||||||||||||
Federal
|
196,787 | 233,468 | 272,653 | |||||||||
State
|
8,095 | 15,113 | 12,185 | |||||||||
Total deferred income tax expense
|
204,882 | 248,581 | 284,838 | |||||||||
Total
|
$ | 205,868 | $ | 247,912 | $ | 288,691 |
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
U.S. statutory income tax expense
|
$ | 200,155 | $ | 231,704 | $ | 273,112 | ||||||
State income taxes, net of federal benefit
|
13,962 | 14,444 | 16,602 | |||||||||
State income tax credits
|
(10,525 | ) | - | - | ||||||||
Statutory depletion
|
(796 | ) | (620 | ) | (697 | ) | ||||||
Enacted changes in state tax laws
|
(1,416 | ) | - | (1,842 | ) | |||||||
Permanent items
|
2,122 | 1,524 | 1,420 | |||||||||
Other
|
2,366 | 860 | 96 | |||||||||
Total
|
$ | 205,868 | $ | 247,912 | $ | 288,691 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Deferred income tax assets:
|
||||||||
Net operating loss carryforward
|
$ | 438,922 | $ | 520,980 | ||||
Derivative instruments
|
- | 19,957 | ||||||
Production Participation Plan liability
|
32,245 | 34,865 | ||||||
Tax sharing liability
|
9,439 | 8,312 | ||||||
Asset retirement obligations
|
23,642 | 19,759 | ||||||
Underwriter fees
|
10,974 | 12,677 | ||||||
Restricted stock compensation
|
13,384 | 9,852 | ||||||
Enhanced oil recovery credit carryforwards
|
7,946 | 7,946 | ||||||
Alternative minimum tax credit carryforwards
|
18,452 | 11,391 | ||||||
Foreign tax credit carryforwards
|
1,230 | 1,230 | ||||||
Other
|
2,004 | 1,508 | ||||||
Total deferred income tax assets
|
558,238 | 648,477 | ||||||
Less valuation allowances
|
(1,230 | ) | (1,230 | ) | ||||
Net deferred income tax assets
|
557,008 | 647,247 | ||||||
Deferred income tax liabilities:
|
||||||||
Oil and gas properties
|
1,675,916 | 1,555,142 | ||||||
Trust distributions
|
149,332 | 165,180 | ||||||
Derivative instruments
|
10,438 | - | ||||||
Total deferred income tax liabilities
|
1,835,686 | 1,720,322 | ||||||
Total net deferred income tax liabilities
|
$ | 1,278,678 | $ | 1,073,075 |
Year Ended December 31,
|
||||||||
2013
|
2012
|
|||||||
Assets:
|
||||||||
Current deferred income taxes
|
$ | - | $ | - | ||||
Liabilities:
|
||||||||
Current deferred income taxes
|
648 | 9,394 | ||||||
Non-current deferred income taxes
|
1,278,030 | 1,063,681 | ||||||
Net deferred income tax liabilities
|
$ | 1,278,678 | $ | 1,073,075 |
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Beginning balance at January 1
|
$ | 170 | $ | 299 | $ | 299 | ||||||
Decrease related to tax position taken in a prior period
|
- | (129 | ) | - | ||||||||
Ending balance at December 31
|
$ | 170 | $ | 170 | $ | 299 |
11.
|
EARNINGS PER SHARE
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Basic Earnings Per Share
|
||||||||||||
Numerator:
|
||||||||||||
Net income available to shareholders
|
$ | 366,055 | $ | 414,189 | $ | 491,687 | ||||||
Preferred stock dividends
(1)
|
(494 | ) | (1,077 | ) | (1,077 | ) | ||||||
Net income available to common shareholders, basic
|
$ | 365,561 | $ | 413,112 | $ | 490,610 | ||||||
Denominator:
|
||||||||||||
Weighted average shares outstanding, basic
|
118,260 | 117,601 | 117,345 | |||||||||
Diluted Earnings Per Share
|
||||||||||||
Numerator:
|
||||||||||||
Net income available to common shareholders, basic
|
$ | 365,561 | $ | 413,112 | $ | 490,610 | ||||||
Preferred stock dividends
|
538 | 1,077 | 1,077 | |||||||||
Adjusted net income available to common shareholders, diluted
|
$ | 366,099 | $ | 414,189 | $ | 491,687 | ||||||
Denominator:
|
||||||||||||
Weighted average shares outstanding, basic
|
118,260 | 117,601 | 117,345 | |||||||||
Restricted stock and stock options
|
957 | 633 | 529 | |||||||||
Convertible perpetual preferred stock
|
371 | 794 | 794 | |||||||||
Weighted average shares outstanding, diluted
|
119,588 | 119,028 | 118,668 | |||||||||
Earnings per common share, basic
|
$ | 3.09 | $ | 3.51 | $ | 4.18 | ||||||
Earnings per common share, diluted
|
$ | 3.06 | $ | 3.48 | $ | 4.14 |
(1)
|
For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2012 and 2011.
|
12.
|
RELATED PARTY TRANSACTIONS
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
Assets
|
||||||||
Unit distributions due from Trust I
(1)
|
$ | 1,093 | $ | 929 | ||||
Liabilities
|
||||||||
Unit distributions payable to Trust I
(2)
|
$ | 6,932 | $ | 5,731 |
(1)
|
This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets.
|
(2)
|
This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2013 and 2012, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2013 and 2012, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31, 2013 and 2012, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. These amounts are included within accounts payable trade in the Company’s consolidated balance sheet.
|
13.
|
COMMITMENTS AND CONTINGENCIES
|
Payments due by period
|
||||||||||||||||||||||||||||
2014
|
2015
|
2016
|
2017
|
2018
|
Thereafter
|
Total
|
||||||||||||||||||||||
Non-cancelable leases
|
$ | 6,279 | $ | 5,872 | $ | 5,387 | $ | 5,250 | $ | 4,629 | $ | 1,374 | $ | 28,791 | ||||||||||||||
Drilling rig contracts
|
87,610 | 48,531 | 1,755 | - | - | - | 137,896 | |||||||||||||||||||||
Construction and drilling contract
|
31,066 | - | 2,900 | 6,900 | 4,100 | - | 44,966 | |||||||||||||||||||||
Total
|
$ | 124,955 | $ | 54,403 | $ | 10,042 | $ | 12,150 | $ | 8,729 | $ | 1,374 | $ | 211,653 |
14.
|
OIL AND GAS ACTIVITIES
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Development
(1)
|
$ | 2,132,824 | $ | 1,667,182 | $ | 1,245,150 | ||||||
Proved property acquisition
|
232,572 | 19,785 | 4,324 | |||||||||
Unproved property acquisition
|
174,103 | 119,175 | 191,482 | |||||||||
Exploration
|
363,234 | 436,084 | 400,823 | |||||||||
Total
|
$ | 2,902,733 | $ | 2,242,226 | $ | 1,841,779 |
(1)
|
During 2013, 2012 and 2011, non-cash additions to oil and gas properties of $29.8 million, $36.3 million and $4.9 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Beginning balance at January 1
|
$ | 108,861 | $ | 90,519 | $ | 4,434 | ||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
281,951 | 384,223 | 354,962 | |||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
(291,962 | ) | (358,625 | ) | (267,847 | ) | ||||||
Capitalized exploratory well costs charged to expense
|
(13,472 | ) | (7,256 | ) | (1,030 | ) | ||||||
Ending balance at December 31
|
$ | 85,378 | $ | 108,861 | $ | 90,519 |
15.
|
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
|
Oil
(MBbl)
|
NGLs
(MBbl)
|
Natural Gas
(MMcf)
|
Total
(MBOE)
|
|||||||||||||
Balance—January 1, 2011
|
224,196 | 30,082 | 303,544 | 304,869 | ||||||||||||
Extensions and discoveries
|
39,660 | 5,024 | 23,211 | 48,552 | ||||||||||||
Sales of minerals in place
|
(579 | ) | (632 | ) | (9,759 | ) | (2,837 | ) | ||||||||
Purchases of minerals in place
|
114 | 58 | 1,639 | 445 | ||||||||||||
Production
|
(18,299 | ) | (2,074 | ) | (26,443 | ) | (24,780 | ) | ||||||||
Revisions to previous estimates
|
15,052 | 5,151 | (7,217 | ) | 19,000 | |||||||||||
Balance—December 31, 2011
|
260,144 | 37,609 | 284,975 | 345,249 | ||||||||||||
Extensions and discoveries
|
68,134 | 6,526 | 40,915 | 81,479 | ||||||||||||
Sales of minerals in place
|
(7,960 | ) | (320 | ) | (13,987 | ) | (10,611 | ) | ||||||||
Production
|
(23,139 | ) | (2,766 | ) | (25,827 | ) | (30,209 | ) | ||||||||
Revisions to previous estimates
|
4,106 | (951 | ) | (61,812 | ) | (7,148 | ) | |||||||||
Balance—December 31, 2012
|
301,285 | 40,098 | 224,264 | 378,760 | ||||||||||||
Extensions and discoveries
|
88,293 | 9,830 | 63,893 | 108,772 | ||||||||||||
Sales of minerals in place
|
(36,992 | ) | (4,777 | ) | (12,411 | ) | (43,838 | ) | ||||||||
Purchases of minerals in place
|
14,543 | 1,311 | 7,751 | 17,146 | ||||||||||||
Production
|
(27,035 | ) | (2,821 | ) | (26,917 | ) | (34,342 | ) | ||||||||
Revisions to previous estimates
|
7,327 | 1,228 | 20,934 | 12,044 | ||||||||||||
Balance—December 31, 2013
|
347,421 | 44,869 | 277,514 | 438,542 | ||||||||||||
Proved developed reserves:
|
||||||||||||||||
December 31, 2010
|
160,088 | 18,321 | 220,530 | 215,164 | ||||||||||||
December 31, 2011
|
180,975 | 22,109 | 211,297 | 238,300 | ||||||||||||
December 31, 2012
|
190,845 | 24,204 | 160,893 | 241,864 | ||||||||||||
December 31, 2013
|
198,204 | 23,721 | 183,129 | 252,446 | ||||||||||||
Proved undeveloped reserves:
|
||||||||||||||||
December 31, 2010
|
64,108 | 11,761 | 83,014 | 89,705 | ||||||||||||
December 31, 2011
|
79,169 | 15,500 | 73,678 | 106,949 | ||||||||||||
December 31, 2012
|
110,440 | 15,894 | 63,371 | 136,896 | ||||||||||||
December 31, 2013
|
149,217 | 21,148 | 94,385 | 186,096 |
·
|
Extensions and discoveries.
In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in the Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields. The new producing wells in these areas and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
|
·
|
Sales of minerals in place.
In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the disposition of the Postle Properties, further described in the Acquisitions and Divestitures footnote, which decreased the Company’s proved reserves.
|
·
|
Purchases of minerals in place.
In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves.
|
·
|
Revisions to previous estimates.
In 2013, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 12.0 MMBOE. Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012 and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
|
|
Notable changes in proved reserves for the year ended December 31, 2012 included:
|
·
|
Extensions and discoveries.
In 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful drilling in the Sanish, Redtail, Missouri Breaks and Pronghorn fields. The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
|
·
|
Revisions to previous estimates.
In 2012, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 7.1 MMBOE. Included in these revisions were (i) 11.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011, and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
|
|
Notable changes in proved reserves for the year ended December 31, 2011 included:
|
·
|
Extensions and discoveries.
In 2011, total extensions and discoveries of 48.6 MMBOE were primarily attributable to successful drilling in the Sanish and Pronghorn fields. The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves in these areas.
|
·
|
Revisions to previous estimates.
In 2011, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 19.0 MMBOE. Included in these revisions were (i) 4.7 MMBOE of upward adjustments caused by higher crude oil prices incorporated into the Company’s reserve estimates at December 31, 2011 as compared to December 31, 2010, and (ii) 14.3 MMBOE of net upward adjustments attributable to reservoir analysis and well performance. The oil component of the net 14.3 MMBOE revision consisted of a 10.9 MMBOE increase that was primarily related to the Postle and North Ward Estes fields, where the performance of the CO
2
injection EOR projects supported an increase in the proved reserve assignments. The NGL component of the net 14.3 MMBOE revision consisted of a 4.8 MMBOE increase due to the performance of the Postle and North Ward Estes fields and various properties in the Northern Rockies area, primarily in the Sanish field. The gas component of the net 14.3 MMBOE revision consisted of a 1.4 MMBOE decrease that was primarily related to the Flat Rock field where proved reserve assignments were reduced due to the production performance of two recently completed wells.
|
December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Future cash flows
|
$ | 35,178,399 | $ | 29,308,752 | $ | 26,815,086 | ||||||
Future production costs
|
(12,973,292 | ) | (11,397,332 | ) | (8,908,131 | ) | ||||||
Future development costs
|
(5,355,383 | ) | (3,181,618 | ) | (1,982,813 | ) | ||||||
Future income tax expense
|
(3,954,401 | ) | (4,278,529 | ) | (4,875,973 | ) | ||||||
Future net cash flows
|
12,895,323 | 10,451,273 | 11,048,169 | |||||||||
10% annual discount for estimated timing of cash flows
|
(6,301,462 | ) | (5,044,240 | ) | (5,775,677 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 6,593,861 | $ | 5,407,033 | $ | 5,272,492 |
December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Beginning of year
|
$ | 5,407,033 | $ | 5,272,492 | $ | 3,667,606 | ||||||
Sale of oil and gas produced, net of production costs
|
(2,010,925 | ) | (1,589,665 | ) | (1,415,469 | ) | ||||||
Sales of minerals in place
|
(1,064,195 | ) | (438,614 | ) | (67,600 | ) | ||||||
Net changes in prices and production costs
|
902,916 | (1,061,495 | ) | 2,246,014 | ||||||||
Extensions, discoveries and improved recoveries
|
2,827,321 | 3,708,780 | 1,156,740 | |||||||||
Previously estimated development costs incurred during the period
|
832,096 | 526,982 | 408,079 | |||||||||
Changes in estimated future development costs
|
(1,264,189 | ) | (1,498,592 | ) | (797,542 | ) | ||||||
Purchases of minerals in place
|
445,669 | - | 10,604 | |||||||||
Revisions of previous quantity estimates
|
313,069 | (295,432 | ) | 452,668 | ||||||||
Net change in income taxes
|
(335,637 | ) | 255,328 | (755,369 | ) | |||||||
Accretion of discount
|
540,703 | 527,249 | 366,761 | |||||||||
End of year
|
$ | 6,593,861 | $ | 5,407,033 | $ | 5,272,492 |
2013
|
2012
|
2011
|
||||||||||
Oil (per Bbl)
|
$ | 90.80 | $ | 87.15 | $ | 89.18 | ||||||
NGLs (per Bbl)
|
$ | 54.38 | $ | 58.15 | $ | 62.93 | ||||||
Natural Gas (per Mcf)
|
$ | 4.30 | $ | 3.21 | $ | 4.39 |
16.
|
QUARTERLY FINANCIAL DATA (UNAUDITED)
|
Three Months Ended
|
||||||||||||||||
Year ended December 31, 2013
:
|
March 31,
2013
|
June 30,
2013
|
September 30,
2013
|
December 31,
2013
|
||||||||||||
Oil, NGL and natural gas sales
|
$ | 605,114 | $ | 651,868 | $ | 706,543 | $ | 703,024 | ||||||||
Operating profit
(1)
|
$ | 252,806 | $ | 269,528 | $ | 316,764 | $ | 280,311 | ||||||||
Net income (loss)
|
$ | 86,244 | $ | 134,944 | $ | 204,091 | $ | (59,276 | ) | |||||||
Basic earnings (loss) per share
|
$ | 0.73 | $ | 1.14 | $ | 1.72 | $ | (0.50 | ) | |||||||
Diluted earnings (loss) per share
|
$ | 0.72 | $ | 1.14 | $ | 1.71 | $ | (0.50 | ) |
Three Months Ended
|
||||||||||||||||
Year ended December 31, 2012
:
|
March 31,
2012
|
June 30,
2012
|
September 30,
2012
|
December 31,
2012
|
||||||||||||
Oil, NGL and natural gas sales
|
$ | 558,697 | $ | 492,756 | $ | 521,195 | $ | 565,066 | ||||||||
Operating profit
(1)
|
$ | 263,176 | $ | 201,900 | $ | 204,230 | $ | 235,635 | ||||||||
Net income
|
$ | 98,446 | $ | 150,851 | $ | 83,113 | $ | 81,689 | ||||||||
Basic earnings per share
|
$ | 0.84 | $ | 1.28 | $ | 0.70 | $ | 0.69 | ||||||||
Diluted earnings per share
|
$ | 0.83 | $ | 1.27 | $ | 0.70 | $ | 0.69 |
(1)
|
Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.
|
Item 9.
|
Chan
ge
s in and Disagreements with Accountants on Accounting and Financial Disclosure
|
Item 9A.
|
Con
tro
ls and Procedures
|
Item 9B.
|
O
th
er Information
|
Item 10.
|
Di
rect
ors, Executive Officers and Corporate Governance
|
Item 11.
|
E
xec
utive Compensation
|
Item 12.
|
Se
cur
ity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
Plan Category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
Weighted-average exercise price of outstanding options, warrants and rights
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)
|
|||||||||
Equity compensation plans approved by security holders
(1)
|
420,840 | $ | 28.65 | 5,380,594 | (2) | |||||||
Equity compensation plans not approved by security holders
|
- | N/A | - | |||||||||
Total
|
420,840 | $ | 28.65 | 5,380,594 | (2) |
(1)
|
Includes the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Plan”) and Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Plan”). Upon shareholder approval of the 2013 Plan in May 2013, the 2003 Plan was terminated, but continues to govern awards that were outstanding on its termination. Any shares netted or forfeited under the 2003 Plan will be available for future issuance under the 2013 Plan.
|
(2)
|
Number of securities reduced by 420,840 stock options outstanding and 1,444,310 shares of restricted common stock previously issued for which the restrictions have not lapsed.
|
Item 13.
|
Ce
rt
ain Relationships, Related Transactions and Director Independence
|
Item 14.
|
Pr
inci
pal Accounting Fees and Services
|
Item 15.
|
E
xhib
its, Financial Statement Schedules
|
(a)
|
1.
|
Financial statements – Refer to the Index to Consolidated Financial Statements included in Item 8 of this Form 10-K for a list of all financial statements filed as part of this report.
|
|
2.
|
Financial statement schedules – The following financial statement schedule is filed as part of this Annual Report on Form 10-K:
|
|
3.
|
Exhibits – The exhibits listed in the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K.
|
(b)
|
Exhibits
|
(c)
|
Financial Statement Schedules
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
ASSETS
|
||||||||
Current assets
|
$ | 5,120 | $ | 2,390 | ||||
Investment in subsidiaries
|
2,707,184 | 2,330,987 | ||||||
Intercompany receivable
|
3,796,321 | 1,748,463 | ||||||
Total assets
|
$ | 6,508,625 | $ | 4,081,840 | ||||
LIABILITIES AND EQUITY
|
||||||||
Current liabilities
|
$ | 26,054 | $ | 14,372 | ||||
Long-term debt
|
2,653,834 | 600,000 | ||||||
Other long-term liabilities
|
170 | 21,244 | ||||||
Shareholders’ equity
|
3,828,567 | 3,446,224 | ||||||
Total liabilities and equity
|
$ | 6,508,625 | $ | 4,081,840 |
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Operating expenses:
|
||||||||||||
General and administrative
|
$ | (1,131 | ) | $ | (16,506 | ) | $ | (12,024 | ) | |||
Interest expense
|
(2,922 | ) | (2,168 | ) | (2,066 | ) | ||||||
Equity in earnings of subsidiaries
|
361,732 | 425,870 | 500,564 | |||||||||
Income before income taxes
|
357,679 | 407,196 | 486,474 | |||||||||
Income tax benefit
|
8,376 | 6,993 | 5,213 | |||||||||
Net income
|
$ | 366,055 | $ | 414,189 | $ | 491,687 | ||||||
Comprehensive income
|
$ | 366,055 | $ | 414,189 | $ | 491,687 | ||||||
See notes to condensed financial statements.
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
Cash flows provided by operating activities
|
$ | - | $ | 16,423 | $ | 4,962 | ||||||
Cash flows from investing activities:
|
||||||||||||
Investment in subsidiaries
|
- | - | - | |||||||||
Cash flows from financing activities:
|
||||||||||||
Intercompany receivable
|
(2,048,253 | ) | (14,094 | ) | (3,091 | ) | ||||||
Issuance of 5% Senior Notes due 2019
|
1,100,000 | - | - | |||||||||
Issuance of 5.75% Senior Notes due 2021
|
1,204,000 | - | - | |||||||||
Redemption of 7% Senior Subordinated Notes due 2014
|
(253,988 | ) | - | - | ||||||||
Other financing activities
|
(1,759 | ) | (2,329 | ) | (1,871 | ) | ||||||
Net cash used in financing activities
|
- | (16,423 | ) | (4,962 | ) | |||||||
Net change in cash and cash equivalents
|
- | - | - | |||||||||
Cash and cash equivalents:
|
||||||||||||
Beginning of period
|
- | - | - | |||||||||
End of period
|
$ | - | $ | - | $ | - | ||||||
NONCASH INVESTING ACTIVITIES:
|
||||||||||||
Distributions from Whiting USA Trust I decreasing investment in subsidiaries
|
$ | (4,749 | ) | $ | (5,827 | ) | $ | (6,500 | ) | |||
See notes to condensed financial statements.
|
(Continued)
|
Year Ended December 31,
|
||||||||||||
2013
|
2012
|
2011
|
||||||||||
NONCASH FINANCING ACTIVITIES:
|
||||||||||||
Preferred stock dividends paid decreasing shareholders’ equity
|
$ | (538 | ) | $ | (1,077 | ) | $ | (1,077 | ) | |||
Preferred stock dividends paid decreasing intercompany receivable
|
$ | (538 | ) | $ | (1,077 | ) | $ | (1,077 | ) | |||
Distributions from Whiting USA Trust I increasing intercompany receivable
|
$ | 4,749 | $ | 5,827 | $ | 6,500 | ||||||
See notes to condensed financial statements.
|
(Concluded)
|
December 31,
|
||||||||
2013
|
2012
|
|||||||
Long-term debt:
|
||||||||
7% Senior Subordinated Notes due 2014
|
$ | - | $ | 250,000 | ||||
6.5% Senior Subordinated Notes due 2018
|
350,000 | 350,000 | ||||||
5% Senior Notes due 2019
|
1,100,000 | - | ||||||
5.75% Senior Notes due 2021, including unamortized debt premium of $3,834
|
1,203,834 | - | ||||||
Other long-term liabilities:
|
||||||||
Tax sharing liability
(1)
|
- | 21,074 | ||||||
Other
|
170 | 170 | ||||||
Total long-term debt and other long-term liabilities
|
$ | 2,654,004 | $ | 621,244 |
(1)
|
As of December 31, 2013, the entire $23.9 million balance due to Alliant Energy under the tax sharing agreement was reflected as a current liability in these condensed financial statements and is included in the schedule of maturities below.
|
2014
|
2015
|
2016
|
2017
|
2018
|
Thereafter
|
Total
|
||||||||||||||||||||||
Amounts due
|
$ | 23,856 | $ | - | $ | - | $ | - | $ | 350,000 | $ | 2,300,000 | $ | 2,673,856 |
WHITING PETROLEUM CORPORATION
|
||
By
|
/s/ James J. Volker
|
|
James J. Volker
|
||
Chairman and Chief Executive Officer
|
Signature
|
Title
|
Date
|
||
/s/ James J. Volker
James J. Volker
|
Chairman and Chief
Executive Officer and Director
(Principal Executive Officer)
|
February 27, 2014
|
||
/s/ Michael J. Stevens
Michael J. Stevens
|
Vice President and
Chief Financial Officer
(Principal Financial Officer)
|
February 27, 2014
|
||
/s/ Brent P. Jensen
Brent P. Jensen
|
Controller and Treasurer
(Principal Accounting Officer)
|
February 27, 2014
|
||
/s/ Thomas L. Aller
Thomas L. Aller
|
Director
|
February 27, 2014
|
||
/s/ D. Sherwin Artus
D. Sherwin Artus
|
Director
|
February 27, 2014
|
||
/s/ Philip E. Doty
Philip E. Doty
|
Director
|
February 27, 2014
|
||
/s/ William N. Hahne
William N. Hahne
|
Director
|
February 27, 2014
|
||
/s/ Allan R. Larson
Allan R. Larson
|
Director
|
February 27, 2014
|
||
/s/ Michael B. Walen
Michael B. Walen
|
Director
|
February 27, 2014
|
Exhibit
Number
|
Exhibit Description
|
(3.1)
|
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated June 28, 2013 (File No. 001-31899)].
|
(3.2)
|
Amended and Restated By-laws of Whiting Petroleum Corporation, effective February 20, 2014 [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 20, 2014 (File No. 001-31899)].
|
(4.1)
|
Fifth Amended and Restated Credit Agreement, dated as of October 15, 2010, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the various other agents party thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 15, 2010 (File No. 001-31899)].
|
(4.2)
|
First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 15, 2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, the various other agents party thereto and the lenders party thereto [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-31899)].
|
(4.3)
|
Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 12, 2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, the various other agents party thereto and the lenders party thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 12, 2011 (File No. 001-31899)].
|
(4.4)
|
Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 19, 2012, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 19, 2012 (File No. 001-31899)].
|
(4.5)
|
Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated as of June 27, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 (File No. 001-31899)].
|
(4.6)
|
Fifth Amendment to Fifth Amended and Restated Credit Agreement, dated as of September 6, 2013, among Whiting Petroleum Corporation, its subsidiary Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents and lenders party thereto [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 6, 2013 (File No. 001-31899)].
|
(4.7)
|
Subordinated Indenture, dated as of April 19, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and The Bank of New York Trust Company, N.A., as successor trustee [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
|
(4.8)
|
Second Supplemental Indenture, dated September 24, 2010, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 6.5% Senior Subordinated Notes due 2018 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
|
Exhibit
Number
|
Exhibit Description
|
(4.9)
|
Rights Agreement, dated as of February 23, 2006, between Whiting Petroleum Corporation and Computershare Trust Company, Inc. [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No. 001-31899)].
|
(4.10)
|
Notice to JPMorgan Chase Bank, N.A., as Administrative Agent, dated September 9, 2013, to reduce the aggregate commitments under the Fifth Amended and Restated Credit Agreement, as amended [Incorporated by reference to Exhibit 4.4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 9, 2013 (File No. 001-31899)].
|
(4.11)
|
Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 9, 2013 (File No. 001-31899)].
|
(4.12)
|
First Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.000% Senior Notes due 2019 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 9, 2013 (File No. 001-31899)].
|
(4.13)
|
Second Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.750% Senior Notes due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 9, 2013 (File No. 001-31899)].
|
(4.14)
|
Third Supplemental Indenture, dated September 26, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.750% Senior Notes due 2021 issued on September 26, 2013 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 23, 2013 (File No. 001-31899)].
|
(10.1)*
|
Whiting Petroleum Corporation 2003 Equity Incentive Plan, as amended through October 23, 2007 [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 23, 2007 (File No. 001-31899)].
|
(10.2)*
|
Whiting Petroleum Corporation 2013 Equity Incentive Plan [Incorporated by reference to Annex A to Whiting Petroleum Corporation’s definitive proxy statement filed with the Securities and Exchange Commission on Schedule 14A on March 25, 2013 (File No. 001-31899)].
|
(10.3)*
|
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan for time-based vesting awards on and after October 23, 2007 [Incorporated by reference to Exhibit 10.4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 23, 2007 (File No. 001-31899)].
|
(10.4)*
|
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan for performance vesting awards on and after February 23, 2008 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 001-31899)].
|
(10.5)*
|
Whiting Petroleum Corporation Production Participation Plan, as amended and restated February 4, 2008 [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-31899)].
|
(10.6)
|
Tax Separation and Indemnification Agreement between Alliant Energy Corporation, Whiting Petroleum Corporation and Whiting Oil and Gas Corporation [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].
|
Exhibit
Number
|
Exhibit Description
|
(10.7)*
|
Summary of Non-Employee Director Compensation for Whiting Petroleum Corporation.
|
(10.8)*
|
Production Participation Plan Credit Service Agreement, dated February 23, 2007, between Whiting Petroleum Corporation and James J. Volker [Incorporated by reference to Exhibit 10.7 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-31899)].
|
(10.9)*
|
Form of Indemnification Agreement for directors and executive officers of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.10 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-31899)].
|
(10.10)*
|
Form of Executive Excise Tax Gross-Up Agreement for executive officers of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated January 13, 2009 (File No. 001-31899)].
|
(10.11)*
|
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan [Incorporated by reference to Exhibit 10.14 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-31899)].
|
(10.12)*
|
Noncompetition Agreement, between J. Douglas Lang and Whiting Petroleum Corporation, effective as of June 17, 2013 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated June 17, 2013 (File No. 001-31899)].
|
(10.13)
|
Purchase and Sale Agreement, by and between Whiting Oil and Gas Corporation and BreitBurn Operating L.P., effective as of April 1, 2013 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated June 22, 2013 (File No. 001-31899)].
|
(10.14)*
|
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for performance vesting awards.
|
(10.15)*
|
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for time-based vesting awards.
|
(10.16)*
|
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan.
|
(21)
|
Subsidiaries of Whiting Petroleum Corporation.
|
(23.1)
|
Consent of Deloitte & Touche LLP.
|
(23.2)
|
Consent of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
|
(31.1)
|
Certification by the Chairman and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
|
(31.2)
|
Certification by the Vice President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
|
(32.1)
|
Written Statement of the Chairman and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
|
(32.2)
|
Written Statement of the Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
|
(99.1)
|
Proxy Statement for the 2014 Annual Meeting of Stockholders, to be filed within 120 days of December 31, 2013 [To be filed with the Securities and Exchange Commission under Regulation 14A within 120 days after December 31, 2013; except to the extent specifically incorporated by reference, the Proxy Statement for the 2014 Annual Meeting of Stockholders shall not be deemed to be filed with the Securities and Exchange Commission as part of this Annual Report on Form 10-K].
|
(99.2)
|
Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers relating to Total Proved Reserves and Report of Cawley, Gillespie & Associates, Inc. relating to Probable and Possible Reserves, each dated January 3, 2014.
|
Exhibit
Number
|
Exhibit Description
|
(101)
|
The following materials from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013 are filed herewith, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets as of December 31, 2013 and 2012, (ii) the Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011, (iii) the Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011, (iv) the Consolidated Statements of Cash Flow for the Years Ended December 31, 2013, 2012 and 2011, (v) the Consolidated Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011 and (vi) Notes to Consolidated Financial Statements.
|
|
*
|
A management contract or compensatory plan or arrangement.
|
Committee Service
|
||||||||||||||||
Board Service
|
Audit
|
Compensation
|
Nominating and Governance
|
|||||||||||||
Annual retainer
|
$ | 58,500 | ||||||||||||||
Restricted stock (value), one year vesting
|
$ | 157,500 | ||||||||||||||
Committee chair annual retainer
|
$ | 25,000 | $ | 15,000 | $ | 15,000 | ||||||||||
Committee chair restricted stock (value)
|
$ | 25,000 | $ | 15,000 | $ | 15,000 | ||||||||||
Committee member annual retainer
|
$ | 10,000 | $ | 5,000 | $ | 5,000 | ||||||||||
Meeting fee
|
$ | 1,500 | $ | 1,500 | $ | 1,500 | $ | 1,500 |
WHITING PETROLEUM CORPORATION
|
|||
By:
|
|||
James J. Volker
|
«Name»
|
||
Chief Executive Officer
|
No. of Shares of Restricted Stock:
«Shares»
|
||
Grant Date:
|
COMPANY
|
PARTICIPANT
|
||
WHITING PETROLEUM CORPORATION
|
|||
By:
|
|||
James J. Volker
|
No. of Shares of Restricted Stock:
|
||
Chief Executive Officer
|
Grant Date:
|
WHITING PETROLEUM CORPORATION
|
PARTICIPANT
|
||
By:
|
|||
James J. Volker
|
|||
Chief Executive Officer
|
No. of Optioned Shares:
|
||
Option Price per Share: $
|
|||
Grant Date:
|
Name
|
Jurisdiction of Incorporation or Organization
|
Percent Ownership
|
||
Whiting Oil and Gas Corporation
|
Delaware
|
100%
|
/s/ DELOITTE & TOUCHE LLP
|
|
Denver, Colorado
|
|
February 27, 2014
|
13640 BRIARWICK DRIVE, SUITE 100
|
306 WEST SEVENTH STREET, SUITE 302
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1707
|
FORT WORTH, TEXAS 76102-4987
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
817-336-2461
|
713-651-9944
|
www.cgaus.com
|
Sincerely,
|
|
/s/ Cawley, Gillespie & Associates, Inc.
|
|
Cawley, Gillespie & Associates, Inc.
|
|
Texas Registered Engineering Firm F-693
|
|
February 27, 2014
|
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 fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of 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.
|
Date: February 27, 2014
|
|
/s/ James J. Volker
|
|
James J. Volker
|
|
Chairman and Chief Executive Officer
|
|
Exhibit 31.2
|
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 fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of 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.
|
Date: February 27, 2014
|
|
/s/ Michael J. Stevens
|
|
Michael J. Stevens
|
|
Vice President and Chief Financial Officer
|
|
Exhibit 32.1
|
/s/ James J. Volker
|
|
James J. Volker
|
|
Chairman and Chief Executive Officer
|
|
Date: February 27, 2014
|
|
Exhibit 32.2
|
/s/ Michael J. Stevens
|
|
Michael J. Stevens
|
|
Vice President and Chief Financial Officer
|
|
Date: February 27, 2014
|
|
Exhibit 99.2
|
13640 BRIARWICK DRIVE, SUITE 100
|
306 WEST SEVENTH STREET, SUITE 302
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1707
|
FORT WORTH, TEXAS 76102-4987
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
817-336-2461
|
713-651-9944
|
www.cgaus.com
|
Proved Developed Producing
|
Proved Developed Behind Pipe
|
Proved Developed Non-Producing
|
Proved Developed
Shut-in
|
Proved Undeveloped
|
Total Proved
|
||
Net Reserves
|
|||||||
Oil
|
- Mbbl
|
181,673.9
|
1,528.0
|
15,002.0
|
0.0
|
149,217.3
|
347,421.2
|
Gas
|
- MMcf
|
172,527.2
|
9,141.5
|
1,460.6
|
0.0
|
94,385.0
|
277,514.3
|
NGL
|
- Mbbl
|
19,831.5
|
468.2
|
3,420.9
|
0.0
|
21,148.2
|
44,868.8
|
Revenue
|
|||||||
Oil
|
- M$
|
16,374,094.0
|
139,710.0
|
1,397,231.4
|
0.0
|
13,635,381.0
|
31,546,420.0
|
Gas
|
- M$
|
695,266.1
|
37,586.0
|
5,132.9
|
0.0
|
454,046.4
|
1,192,031.4
|
NGL
|
- M$
|
997,729.9
|
21,603.9
|
194,753.2
|
0.0
|
1,225,861.9
|
2,439,948.0
|
Severance Taxes
|
- M$
|
1,592,264.6
|
13,982.0
|
73,816.4
|
0.0
|
1,049,492.3
|
2,729,555.3
|
Ad Valorem Taxes
|
- M$
|
183,014.0
|
1,840.8
|
37,213.5
|
0.0
|
379,090.3
|
601,158.8
|
Operating Expenses
|
- M$
|
6,287,949.5
|
42,789.2
|
268,143.2
|
0.0
|
3,043,696.3
|
9,642,578.0
|
Investments
|
- M$
|
324,007.7
|
9,278.7
|
273,292.2
|
0.0
|
3,347,822.8
|
3,954,401.8
|
Net Operating Income
|
- M$
|
9,679,857.0
|
131,009.1
|
944,652.1
|
0.0
|
7,495,188.5
|
18,250,706.0
|
Discounted @ 10%
|
- M$
|
5,741,946.0
|
29,386.7
|
261,341.9
|
0.0
|
2,961,371.5
|
8,994,048.0
|
(Columns)
|
|
(1) (11) (21)
|
Calendar
or
Fiscal
years/months commencing on effective date.
|
(2) (3) (4)
|
Gross Production
(8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
|
(5) (6) (7)
|
Net Production
accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
|
(8)
|
Average (volume weighted)
gross liquid price
per barrel before deducting production-severance taxes.
|
(9)
|
Average (volume weighted)
gross gas price
per Mcf before deducting production-severance taxes.
|
(10)
|
Average (volume weighted)
gross NGL price
per barrel before deducting production-severance taxes.
|
(12)
|
Revenue
derived from oil sales -- column (5) times column (8).
|
(13)
|
Revenue
derived from gas sales -- column (6) times column (9).
|
(14)
|
Revenue
derived from NGL sales -- column (7) times column (10).
|
(15)
|
Revenue
derived from other sources.
|
(16)
|
Revenue
derived from hedge positions.
|
(17)
|
Total Revenue
– sum of column (12) through column (16).
|
(18)
|
Production-Severance taxes
deducted from gross oil and NGL revenue.
|
(19)
|
Production-Severance taxes
deducted from gross gas revenue.
|
(20)
|
Revenue after taxes
– column (17) less column (18) and column (19).
|
(22)
|
Operating Expenses
are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
|
(23)
|
Ad Valorem taxes
.
|
(24)
|
Work-over Expenses
are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
|
(25)
|
3rd Party COPAS
are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
|
(26)
|
Other Deductions
may include compression-gathering expenses, transportation costs and water disposal costs.
|
(27)
|
Investments
, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
|
(28) (29)
|
Future Net Cash Flow
is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
|
(30)
|
Cumulative Discounted Cash Flow
is calculated by discounting monthly cash flows at the specified annual rates.
|
|
Input Data
|
•
|
Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
|
Interests
|
•
|
Initial and final expense and revenue interests are shown below columns (27-28).
|
DCF Profile
|
•
|
The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.
|
Life
|
•
|
The economic life of the appraised property is noted in the lower right-hand corner of the table.
|
Footnotes
|
•
|
Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
|
13640 BRIARWICK DRIVE, SUITE 100
|
306 WEST SEVENTH STREET, SUITE 302
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1707
|
FORT WORTH, TEXAS 76102-4987
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
817-336-2461
|
713-651-9944
|
www.cgaus.com
|
Probable Developed Behind Pipe
|
Probable
Undeveloped
|
Total
Probable
|
||
Net Reserves
|
||||
Oil
|
- Mbbl
|
748.1
|
108,519.5
|
109,267.5
|
Gas
|
- MMcf
|
6,831.9
|
260,723.1
|
267,554.9
|
NGL
|
- Mbbl
|
139.5
|
22,190.9
|
22,330.4
|
Revenue
|
||||
Oil
|
- M$
|
69,047.0
|
9,922,280.0
|
9,991,329.0
|
Gas
|
- M$
|
27,639.0
|
1,301,342.6
|
1,328,981.6
|
NGL
|
- M$
|
5,771.6
|
1,139,478.9
|
1,145,250.8
|
Severance Taxes
|
- M$
|
6,522.2
|
762,354.2
|
768,876.3
|
Ad Valorem Taxes
|
- M$
|
1,365.5
|
428,324.1
|
429,689.6
|
Operating Expenses
|
- M$
|
31,047.1
|
2,640,484.5
|
2,671,532.0
|
Investments
|
- M$
|
5,304.1
|
3,152,649.8
|
3,157,954.0
|
Net Operating Income
|
- M$
|
58,218.8
|
5,379,293.5
|
5,437,512.5
|
Discounted @ 10%
|
- M$
|
32,007.9
|
1,830,880.4
|
1,862,888.3
|
Possible
Developed
|
Possible Developed Non-Producing
|
Possible Undeveloped
|
Total
Possible
|
||
Net Reserves
|
|||||
Oil
|
- Mbbl
|
754.8
|
1,234.5
|
135,234.4
|
137,223.6
|
Gas
|
- MMcf
|
1,693.7
|
52.5
|
162,034.3
|
163,780.4
|
NGL
|
- Mbbl
|
98.5
|
288.1
|
24,220.0
|
24,606.6
|
Revenue
|
|||||
Oil
|
- M$
|
67,579.8
|
115,758.2
|
12,450,120.0
|
12,633,459.0
|
Gas
|
- M$
|
6,843.9
|
189.6
|
684,815.3
|
691,848.7
|
NGL
|
- M$
|
4,249.8
|
16,578.0
|
1,401,039.1
|
1,421,866.8
|
Severance Taxes
|
- M$
|
4,339.6
|
6,101.7
|
844,115.8
|
854,557.1
|
Ad Valorem Taxes
|
- M$
|
1,965.8
|
3,072.1
|
341,939.4
|
346,977.3
|
Operating Expenses
|
- M$
|
14,797.5
|
16,365.5
|
2,240,180.8
|
2,271,343.8
|
Investments
|
- M$
|
6,735.6
|
26,814.2
|
2,652,584.0
|
2,686,134.0
|
Net Operating Income
|
- M$
|
50,834.9
|
80,172.3
|
8,457,154.0
|
8,588,163.0
|
Discounted @ 10%
|
- M$
|
27,036.3
|
28,906.9
|
1,700,430.1
|
1,756,373.6
|
(Columns)
|
|
(1) (11) (21)
|
Calendar
or
Fiscal
years/months commencing on effective date.
|
(2) (3) (4)
|
Gross Production
(8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
|
(5) (6) (7)
|
Net Production
accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
|
(8)
|
Average (volume weighted)
gross liquid price
per barrel before deducting production-severance taxes.
|
(9)
|
Average (volume weighted)
gross gas price
per Mcf before deducting production-severance taxes.
|
(10)
|
Average (volume weighted)
gross NGL price
per barrel before deducting production-severance taxes.
|
(12)
|
Revenue
derived from oil sales -- column (5) times column (8).
|
(13)
|
Revenue
derived from gas sales -- column (6) times column (9).
|
(14)
|
Revenue
derived from NGL sales -- column (7) times column (10).
|
(15)
|
Revenue
derived from other sources.
|
(16)
|
Revenue
derived from hedge positions.
|
(17)
|
Total Revenue
– sum of column (12) through column (16).
|
(18)
|
Production-Severance taxes
deducted from gross oil and NGL revenue.
|
(19)
|
Production-Severance taxes
deducted from gross gas revenue.
|
(20)
|
Revenue after taxes
– column (17) less column (18) and column (19).
|
(22)
|
Operating Expenses
are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
|
(23)
|
Ad Valorem taxes
.
|
(24)
|
Work-over Expenses
are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
|
(25)
|
3rd Party COPAS
are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
|
(26)
|
Other Deductions
may include compression-gathering expenses, transportation costs and water disposal costs.
|
(27)
|
Investments
, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
|
(28) (29)
|
Future Net Cash Flow
is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
|
(30)
|
Cumulative Discounted Cash Flow
is calculated by discounting monthly cash flows at the specified annual rates.
|
Input Data
|
•
|
Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
|
Interests
|
•
|
Initial and final expense and revenue interests are shown below columns (27-28).
|
DCF Profile
|
•
|
The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.
|
Life
|
•
|
The economic life of the appraised property is noted in the lower right-hand corner of the table.
|
Footnotes
|
•
|
Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
|
|
APPENDIX
|
13640 BRIARWICK DRIVE, SUITE 100
|
306 WEST SEVENTH STREET, SUITE 302
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1707
|
FORT WORTH, TEXAS 76102-4987
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
817-336-2461
|
713-651-9944
|
www.cgaus.com
|