Attached files
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| 8-K - WHITING PETROLEUM CORPORATION FORM 8-K, DATED FEBRUARY 27, 2013 - WHITING PETROLEUM CORP | form8-k.htm |
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Company contact:
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John B. Kelso, Director of Investor Relations
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303.837.1661 or john.kelso@whiting.com
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Whiting Petroleum Corporation Announces Fourth Quarter and
Full-Year 2012 Financial and Operating Results
Record Production of 30.21 MMBOE (82,540 BOE/d) in 2012 Up 22%
Over 24.78 MMBOE (67,890 BOE/d) in 2011
Proved Reserves Increase 10% to a Record 378.8 MMBOE;
Adding Back 10.6 MMBOE Conveyed to Trust - Proved Reserves Up 13%;
Company Achieves 246% Reserve Replacement
Q4 2012 Net Income Available to Common Shareholders of $81.4 Million
or $0.69 per Diluted Share and Adjusted Net Income of $97.9 Million or
$0.83 per Diluted Share
Q4 2012 Discretionary Cash Flow Totals a Record $381.7 Million
2013 Capital Budget of $2.2 Billion;
Year-Over-Year Production Growth Guidance of +12% to +16%
Tarpon Prospect Well in North Dakota Tests 6,879 BOE/d
DENVER – February 27, 2013 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2012 totaled 7.917 million barrels of oil equivalent (MMBOE), of which 86% were crude oil/natural gas liquids (NGLs). This fourth quarter 2012 production total equates to a daily average production rate of 86,055 barrels of oil equivalent (BOE), representing a 22% increase over the fourth quarter 2011 average daily rate of 70,685 BOE per day and a 4% increase over the third quarter 2012 average daily rate of 82,615 BOE per day.
Production in 2012 totaled a record 30.21 MMBOE or 82,540 BOE per day. This represents a 22% increase over total production of 24.78 MMBOE or 67,890 BOE per day in 2011. Adding back the 4,500 BOE per day of production that was conveyed to Whiting USA Trust II in March 2012, our production in 2012 was up 28% over 2011.
James J. Volker, Whiting’s Chairman and CEO, commented, “2012 was a record year for Whiting Petroleum, and we are off to a great start in 2013. The development of the fields we discovered in 2011 such as Pronghorn, Hidden Bench, Tarpon and Redtail generated excellent results in 2012. In the wake of this development, we posted records in production, proved reserves and discretionary cash flow. According to the December 2012 Oil and Gas Production Report published by the North Dakota State Industrial Commission, Department of Minerals, Oil and Gas Division, Whiting was the number one oil producer in North Dakota at 66,155.7 barrels per day.”
Mr. Volker continued, “For the foreseeable future, our objective is to generate double-digit production growth while spending close to our discretionary cash flow. Our 2013 capital budget of $2.2 billion is expected to yield year-over-year production growth in the 12% to 16% range.”
We believe the following factors will lead to a strong year in 2013 for Whiting and our shareholders:
● Optimization programs that should lead to efficient, low-cost drilling and completion operations;
● Higher density pilot projects at Sanish, Pronghorn and Hidden Bench;
● Solid cash flow and balance sheet;
● Strong Bakken oil prices as differentials improve;
● The emergence of our Redtail prospect as a major resource play.
2
Operating and Financial Results
The following tables summarize the fourth quarter operating and financial results for 2012 and 2011:
| Three Months Ended December 31, | ||||||||||
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2012
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2011
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Change
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||||||||
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Production (MBOE/d)
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86.06 | 70.69 | 22% | |||||||
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Discretionary Cash Flow-MM (1)
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$ | 381.7 | $ | 328.8 | 16% | |||||
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Realized Price ($/BOE)
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$ | 71.09 | $ | 75.07 | ( 5%) | |||||
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Total Revenues-MM
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$ | 577.1 | $ | 498.6 | 16% | |||||
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Net Income Available to Common Shareholders-MM
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$ | 81.4 | $ | 62.6 | 30% | |||||
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Per Basic Share
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$ | 0.69 | $ | 0.54 | 28% | |||||
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Per Diluted Share
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$ | 0.69 | $ | 0.53 | 30% | |||||
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Adjusted Net Income Available to Common Shareholders-MM (2)
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$ | 97.9 | $ | 124.5 | (21%) | |||||
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Per Basic Share
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$ | 0.83 | $ | 1.06 | (22%) | |||||
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Per Diluted Share
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$ | 0.83 | $ | 1.05 | (21%) | |||||
| Twelve Months Ended December 31, | ||||||||||
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2012
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2011
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Change
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Production (MBOE/d)
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82.54 | 67.89 | 22% | |||||||
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Discretionary Cash Flow-MM (1)
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$ | 1,387.5 | $ | 1,242.7 | 12% | |||||
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Realized Price ($/BOE)
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$ | 69.85 | $ | 73.88 | (5%) | |||||
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Total Revenues-MM
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$ | 2,173.5 | $ | 1,899.6 | 14% | |||||
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Net Income Available to Common Shareholders-MM
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$ | 413.1 | $ | 490.6 | (16%) | |||||
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Per Basic Share
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$ | 3.51 | $ | 4.18 | (16%) | |||||
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Per Diluted Share
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$ | 3.48 | $ | 4.14 | (16%) | |||||
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Adjusted Net Income Available to Common Shareholders-MM (2)
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$ | 393.5 | $ | 456.2 | (14%) | |||||
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Per Basic Share
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$ | 3.35 | $ | 3.89 | (14%) | |||||
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Per Diluted Share
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$ | 3.31 | $ | 3.85 | (14%) | |||||
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(1)
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A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.
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(2)
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A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.
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Proved Reserves at December 31, 2012
As of December 31, 2012, Whiting had estimated proved reserves of 378.8 MMBOE, of which 64% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $7,283.9 million, of which approximately 99% came from properties located in Whiting’s Rocky Mountain, Permian Basin and Mid-Continent core areas.
3
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2012:
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Oil
(MBbl)
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NGLs
(MBbl)
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Natural
Gas
(MMcf)
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Total
(MBOE)
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|||||||||||||
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Balance – December 31, 2011
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260,144 | 37,609 | 284,975 | 345,249 | ||||||||||||
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Extensions and discoveries
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68,134 | 6,526 | 40,915 | 81,479 | ||||||||||||
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Sales of minerals in place
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(7,960 | ) | (320 | ) | (13,987 | ) | (10,611 | ) | ||||||||
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Production
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(23,139 | ) | (2,766 | ) | (25,827 | ) | (30,209 | ) | ||||||||
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Revisions to previous estimates
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4,106 | (951 | ) | (61,812 | ) | (7,148 | ) | |||||||||
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Balance – December 31, 2012
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301,285 | 40,098 | 224,264 | 378,760 | ||||||||||||
Whiting’s proved reserves of 378.8 MMBOE represented a 10% increase over the 345.2 MMBOE of proved reserves at year-end 2011, which equates to 246% reserve replacement (81,479 MBOE extensions and discoveries less 7,148 MBOE revisions equals 74,331 MBOE in net reserves added; 74,331 MBOE divided by 30,209 MBOE production = 246% reserve replacement). Adding back the 10.6 MMBOE that was conveyed to Whiting USA Trust II, our proved reserves were up 13%. An estimated 81.5 MMBOE of proved reserves were added through exploration and development activities. This represents a 68% increase over the 48.6 MMBOE of proved reserves that were added from exploration and development in 2011.
Most of the proved reserve additions during 2012 came from the Company’s Bakken and Three Forks development in the Williston Basin of North Dakota and Montana. Whiting booked an estimated 66.4 MMBOE of new Bakken and Three Forks proved reserves, bringing its total proved reserves in the Northern Rockies to 165.1 MMBOE at year-end 2012. Of this 165.1 MMBOE, 67% were proved developed and 33% were proved undeveloped.
Probable and Possible Reserves at December 31, 2012
At year-end 2012, Whiting’s probable reserves were estimated to be 115.2 MMBOE and our possible reserves were estimated to be 171.2 MMBOE, for a total of 286.3 MMBOE. The year-end 2012 estimated pre-tax PV10% for our probable and possible reserves was $2,621.4 million.
As with our proved reserves, 100% of Whiting’s probable and possible reserve estimates were independently engineered by Cawley, Gillespie & Associates, Inc. Please refer to “Disclosure Regarding Reserves and Resources” later in this news release for information on probable and possible reserves.
4
The following table summarizes our proved, probable and possible reserves:
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3P Reserves (1)
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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
(In MM)
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% of Total
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||||||||||||||||||||||
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Proved
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301.3 | 40.1 | 224.3 | 378.8 | 80% | $ | 7,284 | (2) | 73% | |||||||||||||||||||
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Probable
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85.0 | 11.9 | 109.6 | 115.2 | 74% | $ | 1,262 | (3) | 13% | |||||||||||||||||||
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Possible
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123.2 | 21.9 | 156.4 | 171.2 | 72% | $ | 1,359 | (3) | 14% | |||||||||||||||||||
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(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 NYMEX price for each month within the 12 months ended December 31, 2012, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $94.71/Bbl and $2.76/MMBtu.
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(2)
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Pre-tax PV10% of Proved reserves 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 US 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. As of December 31, 2012, our discounted future income taxes were $1,876.9 million and our standardized measure of after-tax discounted future net cash flows was $5,407.0 million. 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 and natural gas reserves.
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(3)
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Pre-tax PV10% of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves, calculated net of estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using 12-month average prices, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or future income taxes and discounted using an annual discount rate of 10%. With respect to pre-tax PV10% amounts for probable or possible reserves, there do not exist any directly comparable US GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves.
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Potential Future Drilling Locations
Based on independent engineering and internal estimates, Whiting projects it has a total of 9,661 gross (4,503.2 net) potential future drilling locations. These consist of 7,556 gross (3,623.3 net) primary locations identified in our reserve database and 2,105 gross (879.9 net) prospective locations supported by successful exploration drilling or extensive geoscience. Of these gross locations, 50% are located in our Williston Basin Bakken/Three Forks plays and 25% are located in our Redtail Niobrara play.
5
The following table summarizes our potential gross and net drilling locations by core area:
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Identified Primary Locations
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Northern Rockies
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Gross
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Net
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Wells per Spacing Unit
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Southern Williston (Lewis & Clark; Pronghorn)
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1,104 | 410.2 |
3 Pronghorn Sand / 1280
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Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks)
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1,174 | 380.5 |
4 Middle BKN; 3 Upper TFK / 1280
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Sanish (Sanish; Parshall) (2)
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260 | 118.1 |
3.5 Middle BKN; 3 Upper TFK / 1280
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Other (3)
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588 | 340.3 | |||||||
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Total
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3,126 | 1,249.1 | |||||||
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Central Rockies
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Redtail Niobrara
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2,420 | 1,215.7 |
8 Nio "B"; 4 Nio "A" / 640 - 960
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Other (4)
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958 | 654.1 | |||||||
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Total
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3,378 | 1,869.8 | |||||||
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Gulf Coast
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131 | 98.1 | |||||||
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Mid-Cont
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41 | 33.7 | |||||||
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Permian Basin (5)
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817 | 319.3 | |||||||
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Michigan
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63 | 53.3 | |||||||
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Total Primary Inventory
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7,556 | 3,623.3 | |||||||
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Identified Prospective Locations
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Williston Basin
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Williston Basin New Objectives
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Gross
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Net
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Wells per Spacing Unit
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Missouri Breaks Upper Three Forks
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321 | 102.8 |
3 Upper TFK / 1280
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Hidden Bench Lower Bakken Silt / Higher Density Pilot
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556 | 161.9 |
4 BKN Silt; 4 Middle BKN per 1280
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Cassandra Lower Three Forks
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120 | 40.0 |
4 Lower TFK per 1280
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Tarpon Lower Three Forks
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40 | 15.0 |
3 Lower TFK per 1280
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Total
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1,037 | 319.7 | |||||||
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Williston Basin Higher Density Locations
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Pronghorn Sand Higher Density
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453 | 167.3 |
3 Add'l Pronghorn Sand / 1280
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Sanish Higher Density and Infill
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191 | 175.9 |
3 Add'l Middle BKN / 1280
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Total
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644 | 343.2 | |||||||
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Williston Basin Total Prospective Locations
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1,681 | 662.9 | |||||||
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Permian Basin
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Big Tex Horizontal
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424 | 217.0 |
6 Upper Wolfcamp / 640
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Total Prospective Inventory
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2,105 | 879.9 | |||||||
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Total Potential Locations (6)
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9,661 | 4,503.2 | |||||||
| (1) |
Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks.
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| (2) |
Cross unit boundary wells at Sanish result in an average of 3.5 wells per spacing unit. Parshall was developed on 640-acre spacing units and there is no Three Forks.
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| (3) |
Various fields in North Dakota and Montana, including Big Island, Starbuck, Big Stick and others.
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| (4) |
Various fields in Colorado, Wyoming and Utah including Sulphur Creek, Fontenelle, Nitchie Gulch, Flat Rock and others.
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| (5) |
Various fields in Texas and New Mexico including Jo-Mill, West Jo-Mill, Garza, Signal Peak and others.
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| (6) |
Locations include both 3P reserves and Resource Potential.
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6
2012 Capital Expenditures
Whiting’s capital expenditures totaled $2,112 million in 2012 or approximately $212 million above its $1,900 million capital budget. The increase was due to a higher level of both operated and non-operated drilling activity. In total, we completed 192.9 net wells versus a projected 160 net wells.
2013 Capital Budget
Our 2013 capital budget is $2,200 million, which we expect to fund substantially with net cash provided by our operating activities, borrowings under our credit facility and certain oil and gas property divestitures. Whiting expects to invest $1,914 million of the 2013 capital budget in exploration and development activity, $108 million for land, and $178 million for facilities. Based on this level of capital spending, we forecast production of 33.8 MMBOE – 35.0 MMBOE for 2013, an increase of 12% - 16% over our 2012 production of 30.2 MMBOE.
Our 2013 capital budget is currently allocated among our major development areas as indicated in the table below:
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2013 CAPEX (MM)
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Gross Wells
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Net Wells
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% of Total
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Northern Rockies
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$ | 1,142 | 219 | 148 | 52% | |||||||||||
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EOR
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240 |
NA
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(2) |
NA
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(2) | 11% | ||||||||||
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Central Rockies
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136 | 37 | 27 | 6% | ||||||||||||
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Non-Operated
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164 | 7% | ||||||||||||||
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Land
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108 | 5% | ||||||||||||||
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Exploration (1)
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82 | 4% | ||||||||||||||
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Facilities
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178 | 8% | ||||||||||||||
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Well Work, Misc. Costs
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150 | 7% | ||||||||||||||
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Total Budget
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$ | 2,200 | 256 | 175 | 100% | |||||||||||
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(1)
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Comprised primarily of exploration salaries, seismic activities, delay rentals and exploratory drilling.
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(2)
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These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis.
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7
Operations Update
Core Development Areas
Bakken and Three Forks Development
In 2012, we experienced significant productivity increases as we moved into development drilling mode in new fields in the Southern and Western Williston Basin. As the following table illustrates, our average well drilled in the Bakken / Pronghorn / Three Forks hydrocarbon system posted higher 30, 60 and 90-day average rates year-over-year:
| Average Rate All Whiting
Bakken, Pronghorn, Three Forks Wells
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30-Day Rate
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60-Day Rate
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90-Day Rate
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2012
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572
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470
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403
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2011
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432
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373
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338
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Southern Williston Basin
The Southern Williston Basin encompasses our Pronghorn and Lewis & Clark prospects, which encompass a total of 398,334 gross (262,974 net) acres. Fourth quarter 2012 production from this region averaged 13,430 BOE per day. This daily rate represents a 10% increase over the 12,190 BOE per day rate in the third quarter of 2012.
Pronghorn Prospect. We experienced exceptional drilling results in the fourth quarter at our Pronghorn prospect. As detailed in the following table, significant fourth quarter 2012 completions include eight wells with 24-hour initial production rates that exceeded 2,000 BOE per day:
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Well Name
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IP Date
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WI%
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BOE/d
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||
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3J TRUST 44-8PH
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11/24/2012
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89%
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2,696
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FROEHLICH 11-28PH
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11/27/2012
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89%
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2,644
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MARSH 34-18PH
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12/09/2012
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65%
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2,340
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FROEHLICH 21-28PH
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11/28/2012
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89%
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2,301
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OBRIGEWITCH 41-17PH
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11/24/2012
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96%
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2,292
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FROEHLICH 41-28PH
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11/27/2012
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89%
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2,288
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FRANK 14-7PH
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11/14/2012
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90%
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2,165
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OBRIGEWITCH 41-16PH
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11/27/2012
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89%
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2,110
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Average
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87%
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2,355
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We intend to conduct a higher density pilot program at Pronghorn. Our plan is to drill six Pronghorn Sand wells per 1,280-acre spacing unit, which is up from our initial plan of three wells per spacing unit.
8
Western Williston Basin
The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri Breaks and Cassandra prospects. These areas represent a total of 183,508 gross (114,732 net) acres. Production from the Western Williston Basin averaged 5,120 BOE per day in the fourth quarter of 2012, which represented a 47% increase over the 3,485 BOE per day average rate in the third quarter of 2012.
Tarpon Prospect. We drilled another prolific well at our Tarpon prospect in McKenzie County, North Dakota. The Tarpon Federal 21-4-3H was tested on December 28, 2012 flowing 4,971 barrels of oil and 11,450 Mcf of gas (6,879 BOE) per day from the Middle Bakken formation. This is the third best well drilled to date in the Williston Basin, the first being Whiting’s Tarpon Federal 21-4H with an initial production rate of 7,009 BOE per day. We hold a 56% working interest and a 45% net revenue interest in the Tarpon Federal 21-4-3H. We have implemented pad drilling at Tarpon with plans to drill three wells off of each pad.
Hidden Bench Prospect. Based on core analysis, we have identified an additional reservoir positioned between the Middle Bakken and Three Forks that has demonstrated high oil in place and may significantly increase reserves in this area. We plan to test this zone which we refer to as the "Middle Bakken Silt" by drilling 160 acre spaced wells above and below this target zone and stimulating these wells with large frac volumes. We believe that this higher density drilling could also improve our recovery efficiency in the Middle Bakken reservoir.
Missouri Breaks Prospect. We hold 95,928 gross (66,095 net) acres in the Missouri Breaks prospect, located in Richland County, Montana and McKenzie County, North Dakota. We continue to de-risk our acreage in the Missouri Breaks area. We have now drilled successful wells on the western, eastern and southern portions of our acreage. On October 27, 2012, we completed the Amber Elizabeth 9-4H in the Middle Bakken formation flowing 1,315 BOE per day. This was our first well drilled in the eastern portion of Missouri Breaks.
Sanish Field
Whiting’s net production from the Sanish field averaged 32,590 BOE per day in the fourth quarter of 2012, an increase of 4% over the third quarter 2012 average of 31,400 BOE per day. Net production from Sanish in 2012 totaled 11.4 MMBOE (an average of 31,081 BOE per day), representing a 40% increase over 2011. Whiting continues to generate strong results from the field. Highlighting recent results was the completion of the Fladeland 14-33H, which was completed in the Middle Bakken formation flowing 3,220 BOE per day. This wing well’s 7,279-foot lateral was fraced in a total of 22 stages.
9
Also of note was the completion of the Lioneld Fladeland 12-12H, which was completed in the Middle Bakken formation flowing 2,747 BOE per day on December 15, 2012. This well was drilled on the western edge of the Sanish field and was fraced in 30 stages.
We plan to initiate a higher density pilot program in the Sanish field in the first half of 2013. If successful, this could add an additional three Middle Bakken locations per 1,280-acre spacing unit. We also plan to refrac several wells at Sanish in 2013.
Red River Plays
Big Island. We currently hold 172,464 gross (122,389 net) acres in the Big Island prospect, which is located in Golden Valley County, North Dakota and Wibaux County, Montana. We have identified more than 50 vertical Red River prospects at our Big Island play using 3-D seismic interpretation. We are currently shooting 3-D seismic on the northwest portion of Big Island with the intention of identifying additional prospect locations. Estimated ultimate recoveries for these wells range from 200,000 BOE to 300,000 BOE. The wells have an estimated completed well cost of $3.0 to $3.5 million.
Our most recent completion at Big Island, the Katherine 33-23, flowed 593 BOE per day from the Upper Red River “D” zone on December 17, 2012. Whiting holds a 99% working interest and a 79% net revenue interest in this vertical well. We currently plan to test the Lower Red River “D” zone with a horizontal well in mid-2013.
Starbuck Prospect. We are currently conducting a 283-square-mile 3-D seismic shoot at our Starbuck prospect in order to identify seismic anomalies in the Upper Red River “D” zone. This shoot was approximately 60% complete at the end of January 2013. We hold 104,508 gross (92,227 net) acres in the Starbuck prospect, which is located in Roosevelt County, Montana.
Midstream Assets
Robinson Lake Gas Plant. As of December 31, 2012, our gas plant at Robinson Lake was processing 67 MMcf of gas per day (gross). We added compression in September 2012 that brought the plant’s inlet capacity to 72 MMcf per day, and we have the ability to increase to 90 MMcf per day in the future. Whiting owns a 50% interest in the plant.
Belfield Gas Processing Plant. The Belfield plant was processing 18 MMcf of gas per day (gross) as of December 31, 2012. Currently, there is inlet compression in place to process 24 MMcf per day. Whiting owns 50% of the Belfield plant. We began connecting other operators’ wells to the plant in November 2012.
10
Other Development Areas
Denver Basin: Redtail Niobrara Prospect. We hold a total of 109,856 gross (79,467 net) acres in our Redtail prospect, located in the Denver Julesberg Basin in Weld County, Colorado. Highlighting recent results from the Niobrara “B” zone was the completion of the Wildhorse 02-0214H. This well flowed 534 barrels of oil and 757 Mcf of gas (660 BOE) per day on October 20, 2012. Whiting holds a 100% working interest and an 80% net revenue interest in the Wildhorse well, which was drilled on a 640-acre spacing unit.
We plan to construct a new gas processing plant at our Redtail prospect. Construction is expected to be completed in early 2014. The plant’s planned inlet capacity is 15 MMcf of gas per day. We currently have one drilling rig running at Redtail. We plan to add a second rig around mid-year and a third rig once the plant is completed.
Delaware Basin: Big Tex Prospect. Whiting’s lease position at Big Tex consists of 116,694 gross (86,882 net) acres, located primarily in Pecos County, Texas. On January 23, 2013, we completed the May 2502H flowing 674 barrels of oil per day from the Wolfcamp formation. The well’s peak 30-day average was 397 barrels of oil per day. Whiting owns a 100% working interest and an 80% net revenue interest in the May 2502H.
The May 2502H well offsets the May 2501, a vertical Wolfcamp well that was completed in May 2012 flowing 353 BOE per day from the Upper Wolfcamp formation. Both May wells are located on the southwest side of the Big Tex prospect.
EOR Projects
North Ward Estes Field. Net production from our North Ward Estes field averaged 8,540 BOE per day in the fourth quarter of 2012. One of the largest phases at North Ward Estes (Phase 3B) is pressuring up with CO2, and we are beginning to see a production response. Current production from the field is approximately 9,000 BOE per day. Whiting is currently injecting approximately 350 MMcf of CO2 per day into the field, of which about 63% is recycled gas.
Optimization Programs
Over the past three and a half years, our use of the “Drill Well on Paper” (“DWOP”) optimization process to perform step-by-step analysis of the drilling programs in the Bakken and Three Forks formations in North Dakota has allowed us to reduce average drill times from 38 days to 18.5 days per well in the Sanish field and from 35 days to 17.0 days per well in other fields throughout North Dakota.
11
As post-DWOP drill times in North Dakota have stabilized at these reduced rates, drilling procedures are being modified to utilize pad drilling technologies to further reduce drilling time and costs per well. Pad drilling in a batch drilling methodology is utilized to reduce surface disturbance, rig mobilization, and service costs by drilling two or three wells from a single drilling location. Drilling costs for pad wells have been over $175,000 lower in the Sanish field and $502,000 lower in the Pronghorn field than single well locations in the same fields. Whiting currently has nine pad capable rigs drilling in North Dakota with one additional pad capable rig to start late in the first quarter of 2013.
In September of 2012, we initiated a program to reduce our overall cycle time, or the time from spud to first production. This program initially covered operations in our Pronghorn, Lewis & Clark, Hidden Bench, Tarpon and East Missouri Breaks fields. The focus of the program is on: the construction of pads and tank batteries; drilling rig mobilization times; pre-job preparation and timing for fracture stimulations; and, post-frac flow back and timing of production to facilities.
To date, we have reduced this cycle time by 23.7 days, to 67.1 days from 90.8 days. The cycle time reduction is resulting in accelerated production and drilling and completion cost savings.
Operated Drilling Rig Count
As of February 1, 2013, 24 operated drilling rigs were active on our properties. The breakdown of our operated rigs as of February 1, 2013 was as follows:
|
Region
|
Drilling Rigs | |
|
Northern Rockies
|
20
|
|
|
Permian Basin
|
-
|
|
|
Central Rockies
|
2
|
|
|
EOR Projects:
|
||
|
Postle
|
1
|
|
|
North Ward Estes
|
1
|
|
|
Total
|
24
|
12
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2012 and 2011:
|
Three Months Ended December 31,
|
|||||||||||
|
Production
|
2012
|
2011
|
Change
|
||||||||
|
Oil (MMBbl)
|
6.12 | 4.91 | 25% | ||||||||
|
NGLs (MMBbl)
|
0.71 | 0.54 | 32% | ||||||||
|
Natural gas (Bcf)
|
6.52 | 6.35 | 3% | ||||||||
|
Total equivalent (MMBOE)
|
7.92 | 6.50 | 22% | ||||||||
|
Average Sales Price
|
|||||||||||
|
Oil (per Bbl):
|
|||||||||||
|
Price received
|
$ | 83.50 | $ | 88.87 | (6%) | ||||||
|
Effect of crude oil hedging (1)
|
(0.41 | ) | (0.85 | ) | |||||||
|
Realized price
|
$ | 83.09 | $ | 88.02 | (6%) | ||||||
|
NYMEX oil (per Bbl)
|
$ | 88.20 | $ | 94.02 | (6%) | ||||||
|
NGLs (per Bbl):
|
|||||||||||
|
Realized price
|
$ | 43.10 | $ | 48.46 | (11%) | ||||||
|
Natural gas (per Mcf):
|
|||||||||||
|
Price received
|
$ | 3.60 | $ | 4.72 | (24%) | ||||||
|
Effect of natural gas hedging (1)
|
0.05 | 0.05 | |||||||||
|
Realized price
|
$ | 3.65 | $ | 4.77 | (23%) | ||||||
|
NYMEX natural gas (per Mcf)
|
$ | 3.41 | $ | 3.54 | (4%) | ||||||
|
(1)
|
Whiting realized pre-tax cash settlement losses of $2.5 million on its crude oil hedges and gains of $0.3 million on its natural gas hedges during the fourth quarter of 2012. A summary of Whiting’s outstanding hedges is included later in this news release.
|
13
Fourth Quarter and Full-Year 2012 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
|
Per BOE, Except Production
|
||||||||||||||||
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Production (MMBOE)
|
7.92 | 6.50 | 30.21 | 24.78 | ||||||||||||
|
Sales price, net of hedging
|
$ | 71.09 | $ | 75.07 | $ | 69.85 | $ | 73.88 | ||||||||
|
Lease operating expense
|
12.41 | 12.69 | 12.46 | 12.33 | ||||||||||||
|
Production tax
|
5.40 | 5.96 | 5.68 | 5.62 | ||||||||||||
|
General & administrative
|
3.03 | 3.46 | 3.59 | 3.43 | ||||||||||||
|
Exploration
|
3.22 | 1.45 | 1.96 | 1.85 | ||||||||||||
|
Cash interest expense
|
2.23 | 2.20 | 2.17 | 2.17 | ||||||||||||
|
Cash income tax expense (benefit)
|
(0.17 | ) | (0.11 | ) | (0.02 | ) | 0.16 | |||||||||
| $ | 44.97 | $ | 49.42 | $ | 44.01 | $ | 48.32 | |||||||||
Fourth Quarter and Full-Year 2012 Drilling and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three and twelve months ended December 31, 2012:
|
Gross/Net Wells Completed
|
||||||||||||||||
|
Total New
|
% Success
|
CAPEX
|
||||||||||||||
|
Producing
|
Non-Producing
|
Drilling
|
Rate
|
(in MM)
|
||||||||||||
| Q4 12 | 124 / 63.0 | 4 / 3.9 | 128 / 66.9 | 96.9% / 94.2% | $ 574.1 | |||||||||||
| 12M 12 | 392 / 188.2 | 5 / 4.7 | 397 / 192.9 | 98.7% / 97.6% | $ 2,111.5 | |||||||||||
Outlook for First Quarter and Full-Year 2013
The following table provides guidance for the first quarter and full-year 2013 based on current forecasts, including Whiting’s full-year 2013 capital budget of $2,200.0 million:
| Guidance | ||||||||||||||||||||
| First Quarter | Full-Year | |||||||||||||||||||
| 2013 | 2013 | |||||||||||||||||||
|
Production (MMBOE)
|
7.80
|
- | 8.20 | 33.80 | - | 35.00 |
|
|||||||||||||
|
Lease operating expense per BOE
|
$ |
12.50
|
- | $ | 12.90 | $ | 12.40 | - | $ | 12.70 |
|
|||||||||
|
General and admin. expense per BOE
|
$ |
3.40
|
- | $ | 3.60 | $ | 3.30 | - | $ | 3.50 |
|
|||||||||
|
Interest expense per BOE
|
$ |
2.40
|
- | $ | 2.60 | $ | 2.30 | - | $ | 2.50 |
|
|||||||||
|
Depr., depletion and amort. per BOE
|
$ |
24.00
|
- | $ | 24.75 | $ | 24.50 | - | $ | 25.50 |
|
|||||||||
|
Prod. taxes (% of production revenue)
|
8.4%
|
- | 8.6% | 8.6% | - | 8.8% |
|
|||||||||||||
|
Oil price differentials to NYMEX per Bbl(1)
|
( | $ |
6.50
|
) | - | ( | $ | 7.50 | ) | ( | $ | 6.50 | ) | - | ( | $ | 7.50 |
)
|
||
|
Gas price premium to NYMEX per Mcf(2)
|
$ |
0.20
|
- | $ | 0.50 | $ | 0.20 | - | $ | 0.50 |
|
|||||||||
|
(1)
|
Does not include the effect of NGLs.
|
|
(2)
|
Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
|
14
Oil Hedges
The following summarizes Whiting’s crude oil hedges as of February 6, 2013:
|
Weighted Average
|
As a Percentage of
|
|||||||
|
Derivative
|
Hedge
|
Contracted Volume
|
NYMEX Price Collar Range
|
December 2012
|
||||
|
Instrument
|
Period
|
(Bbls per Month)
|
(per Bbl)
|
Oil Production
|
||||
|
Three-way Collars(1)
|
2013
|
|||||||
|
Q1
|
910,000
|
$ 70.00 - $ 85.00 - $ 114.80
|
42.1%
|
|||||
|
Q2
|
1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
48.1%
|
|||||
|
Q3
|
1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
48.1%
|
|||||
|
Q4
|
1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
48.1%
|
|||||
|
Collars
|
2013
|
|||||||
|
Q1
|
294,560
|
$ 48.17 - $ 90.71
|
13.6%
|
|||||
|
Q2
|
294,550
|
$ 48.17 - $ 90.71
|
13.6%
|
|||||
|
Q3
|
294,450
|
$ 48.16 - $ 90.70
|
13.6%
|
|||||
|
Oct
|
294,340
|
$ 48.15 - $ 90.69
|
13.6%
|
|||||
|
Nov
|
194,340
|
$ 47.96 - $ 85.90
|
9.0%
|
|||||
|
Dec
|
4,340
|
$ 80.00 - $ 122.50
|
0.2%
|
|||||
|
2014
|
||||||||
|
Q1
|
4,250
|
$ 80.00 - $ 122.50
|
0.2%
|
|||||
|
Q2
|
4,150
|
$ 80.00 - $ 122.50
|
0.2%
|
|||||
|
Q3
|
4,060
|
$ 80.00 - $ 122.50
|
0.2%
|
|||||
|
Q4
|
3,970
|
$ 80.00 - $ 122.50
|
0.2%
|
|
(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.
|
15
Whiting also has the following fixed-price natural gas contracts in place as of February 6, 2013:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
December 2012
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2013
|
||||||
|
Q1
|
360,000
|
$5.47
|
15.8%
|
|||
|
Q2
|
364,000
|
$5.47
|
15.9%
|
|||
|
Q3
|
368,000
|
$5.47
|
16.1%
|
|||
|
Q4
|
368,000
|
$5.47
|
16.1%
|
|||
|
2014
|
||||||
|
Q1
|
330,000
|
$5.49
|
14.4%
|
|||
|
Q2
|
333,667
|
$5.49
|
14.6%
|
|||
|
Q3
|
337,333
|
$5.49
|
14.8%
|
|||
|
Q4
|
337,333
|
$5.49
|
14.8%
|
16
Selected Operating and Financial Statistics
|
Three Months Ended December 31,
|
Twelve Months Ended December 31,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Selected operating statistics
|
||||||||||||||||
|
Production
|
||||||||||||||||
|
Oil, MBbl
|
6,119 | 4,905 | 23,139 | 18,299 | ||||||||||||
|
NGLs, MBbl
|
711 | 540 | 2,766 | 2,074 | ||||||||||||
|
Natural gas, MMcf
|
6,522 | 6,347 | 25,827 | 26,443 | ||||||||||||
|
Oil equivalents, MBOE
|
7,917 | 6,503 | 30,209 | 24,780 | ||||||||||||
|
Average Prices
|
||||||||||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 83.50 | $ | 88.87 | $ | 83.86 | $ | 88.61 | ||||||||
|
NGLs per Bbl
|
$ | 43.10 | $ | 48.46 | $ | 39.36 | $ | 52.38 | ||||||||
|
Natural gas per Mcf (excludes hedging)
|
$ | 3.60 | $ | 4.72 | $ | 3.42 | $ | 4.92 | ||||||||
|
Per BOE Data
|
||||||||||||||||
|
Sales price (including hedging)
|
$ | 71.09 | $ | 75.07 | $ | 69.85 | $ | 73.88 | ||||||||
|
Lease operating
|
$ | 12.41 | $ | 12.69 | $ | 12.46 | $ | 12.33 | ||||||||
|
Production taxes
|
$ | 5.40 | $ | 5.96 | $ | 5.68 | $ | 5.62 | ||||||||
|
Depreciation, depletion and amortization
|
$ | 23.80 | $ | 19.58 | $ | 22.67 | $ | 18.89 | ||||||||
|
General and administrative (1)
|
$ | 3.03 | $ | 3.46 | $ | 3.59 | $ | 3.43 | ||||||||
|
Selected Financial Data
|
||||||||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||
|
Total revenues and other income
|
$ | 577,090 | $ | 498,637 | $ | 2,173,452 | $ | 1,899,622 | ||||||||
|
Total costs and expenses
|
$ | 447,033 | $ | 400,434 | $ | 1,511,441 | $ | 1,119,303 | ||||||||
|
Net income available to common shareholders
|
$ | 81,434 | $ | 62,620 | $ | 413,112 | $ | 490,610 | ||||||||
|
Earnings per common share, basic
|
$ | 0.69 | $ | 0.54 | $ | 3.51 | $ | 4.18 | ||||||||
|
Earnings per common share, diluted
|
$ | 0.69 | $ | 0.53 | $ | 3.48 | $ | 4.14 | ||||||||
|
Average shares outstanding, basic
|
117,631 | 117,381 | 117,601 | 117,345 | ||||||||||||
|
Average shares outstanding, diluted
|
118,992 | 118,644 | 119,028 | 118,668 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 383,270 | $ | 328,329 | $ | 1,401,215 | $ | 1,192,083 | ||||||||
|
Net cash used in investing activities
|
$ | (559,160 | ) | $ | (493,156 | ) | $ | (1,780,318 | ) | $ | (1,760,036 | ) | ||||
|
Net cash provided by financing activities
|
$ | 194,615 | $ | 174,550 | $ | 408,092 | $ | 564,812 | ||||||||
|
(1)
|
For the twelve months ended December 31, 2012, the price includes the effect of a one-time charge under our Production Participation Plan related to the Whiting USA Trust II divestiture of $0.28 per BOE.
|
17
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 28, 2013 at 11:00 a.m. EST (10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting’s fourth quarter and full-year 2012 financial and operating results. Please call (800) 591-6923 (U.S./Canada) or (617) 614-4907 (International) to be connected to the call and enter the pass code 31942801. Access to a live internet broadcast will be available at http://www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EST) on February 28, 2013.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 28, 2013 and continuing through Thursday, March 7, 2013. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 50698820. You may also access a web archive at http://www.whiting.com beginning approximately one hour after the conference call.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, natural gas and natural gas liquids primarily in the Rocky Mountain, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit http://www.whiting.com.
Forward-Looking Statements
This news release contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
18
These risks and uncertainties include, but are not limited to: declines in oil, NGL or natural gas prices; our level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; our ability to obtain sufficient quantities of CO2 necessary to carry out our enhanced oil recovery projects; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal government that could have a negative effect on the oil and gas industry; impacts of the global recession and tight credit markets; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions and the risks related thereto; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2012. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
Disclosure Regarding Reserves and Resources
Whiting uses in this news release the terms proved, probable and possible reserves. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.
19
Whiting uses in this news release the term “total resources,” which consists of contingent and prospective resources, which SEC rules prohibit in filings of U.S. registrants. Contingent resources are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.
20
SELECTED FINANCIAL DATA
For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2012, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
December 31, 2012
|
December 31, 2011
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 44,800 | $ | 15,811 | ||||
|
Accounts receivable trade, net
|
318,265 | 262,515 | ||||||
|
Prepaid expenses and other
|
21,347 | 20,377 | ||||||
|
Total current assets
|
384,412 | 298,703 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method:
|
||||||||
|
Proved properties
|
8,849,515 | 7,221,550 | ||||||
|
Unproved properties
|
362,483 | 354,774 | ||||||
|
Other property and equipment
|
141,738 | 150,933 | ||||||
|
Total property and equipment
|
9,353,736 | 7,727,257 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(2,590,203 | ) | (2,088,517 | ) | ||||
|
Total property and equipment, net
|
6,763,533 | 5,638,740 | ||||||
|
Debt issuance costs
|
28,748 | 33,306 | ||||||
|
Other long-term assets
|
95,726 | 74,860 | ||||||
|
TOTAL ASSETS
|
$ | 7,272,419 | $ | 6,045,609 | ||||
21
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
December 31, 2012
|
December 31, 2011
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable trade
|
$ | 131,370 | $ | 56,673 | ||||
|
Accrued capital expenditures
|
110,663 | 142,827 | ||||||
|
Accrued liabilities and other
|
180,622 | 157,214 | ||||||
|
Revenues and royalties payable
|
149,692 | 103,894 | ||||||
|
Taxes payable
|
33,283 | 31,195 | ||||||
|
Derivative liabilities
|
21,955 | 73,647 | ||||||
|
Deferred income taxes
|
9,394 | 1,584 | ||||||
|
Total current liabilities
|
636,979 | 567,034 | ||||||
|
Long-term debt
|
1,800,000 | 1,380,000 | ||||||
|
Deferred income taxes
|
1,063,681 | 823,643 | ||||||
|
Derivative liabilities
|
1,678 | 47,763 | ||||||
|
Production Participation Plan liability
|
94,483 | 80,659 | ||||||
|
Asset retirement obligations
|
86,179 | 61,984 | ||||||
|
Deferred gain on sale
|
110,395 | 29,619 | ||||||
|
Other long-term liabilities
|
25,852 | 25,776 | ||||||
|
Total liabilities
|
3,819,247 | 3,016,478 | ||||||
|
Commitments and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,391 issued and outstanding as of December 31, 2012 and 2011, aggregate liquidation preference of $17,239,100 at December 31, 2012
|
- | - | ||||||
|
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012, 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011
|
119 | 118 | ||||||
|
Additional paid-in capital
|
1,566,717 | 1,554,223 | ||||||
|
Accumulated other comprehensive income (loss)
|
(1,236 | ) | 240 | |||||
|
Retained earnings
|
1,879,388 | 1,466,276 | ||||||
|
Total Whiting shareholders’ equity
|
3,444,988 | 3,020,857 | ||||||
|
Noncontrolling interest
|
8,184 | 8,274 | ||||||
|
Total equity
|
3,453,172 | 3,029,131 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 7,272,419 | $ | 6,045,609 | ||||
22
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended December 31,
|
Twelve Months Ended December 31,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
REVENUES AND OTHER INCOME:
|
||||||||||||||||
|
Oil, NGL and natural gas sales
|
$ | 565,066 | $ | 492,025 | $ | 2,137,714 | $ | 1,860,146 | ||||||||
|
Gain on hedging activities
|
54 | 1,432 | 2,338 | 8,758 | ||||||||||||
|
Amortization of deferred gain on sale
|
8,177 | 3,482 | 29,458 | 13,937 | ||||||||||||
|
Gain on sale of properties
|
3,686 | 1,581 | 3,423 | 16,313 | ||||||||||||
|
Interest income and other
|
107 | 117 | 519 | 468 | ||||||||||||
|
Total revenues and other income
|
577,090 | 498,637 | 2,173,452 | 1,899,622 | ||||||||||||
|
COSTS AND EXPENSES:
|
||||||||||||||||
|
Lease operating
|
98,271 | 82,550 | 376,424 | 305,487 | ||||||||||||
|
Production taxes
|
42,732 | 38,778 | 171,625 | 139,190 | ||||||||||||
|
Depreciation, depletion and amortization
|
188,428 | 127,335 | 684,724 | 468,203 | ||||||||||||
|
Exploration and impairment
|
87,610 | 23,318 | 166,972 | 84,644 | ||||||||||||
|
General and administrative
|
23,962 | 22,515 | 108,573 | 84,985 | ||||||||||||
|
Interest expense
|
20,115 | 16,649 | 75,210 | 62,516 | ||||||||||||
|
Change in Production Participation Plan liability
|
7,625 | (3,925 | ) | 13,824 | (865 | ) | ||||||||||
|
Commodity derivative (gain) loss, net
|
(21,710 | ) | 93,214 | (85,911 | ) | (24,857 | ) | |||||||||
|
Total costs and expenses
|
447,033 | 400,434 | 1,511,441 | 1,119,303 | ||||||||||||
|
INCOME BEFORE INCOME TAXES
|
130,057 | 98,203 | 662,011 | 780,319 | ||||||||||||
|
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
|
Current
|
(1,345 | ) | (737 | ) | (669 | ) | 3,853 | |||||||||
|
Deferred
|
49,713 | 36,110 | 248,581 | 284,838 | ||||||||||||
|
Total income tax expense
|
48,368 | 35,373 | 247,912 | 288,691 | ||||||||||||
|
NET INCOME
|
81,689 | 62,830 | 414,099 | 491,628 | ||||||||||||
|
Net loss attributable to noncontrolling interest
|
14 | 59 | 90 | 59 | ||||||||||||
|
NET INCOME AVAILABLE TO SHAREHOLDERS
|
81,703 | 62,889 | 414,189 | 491,687 | ||||||||||||
|
Preferred stock dividends
|
(269 | ) | (269 | ) | (1,077 | ) | (1,077 | ) | ||||||||
|
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 81,434 | $ | 62,620 | $ | 413,112 | $ | 490,610 | ||||||||
|
EARNINGS PER COMMON SHARE:
|
||||||||||||||||
|
Basic
|
$ | 0.69 | $ | 0.54 | $ | 3.51 | $ | 4.18 | ||||||||
|
Diluted
|
$ | 0.69 | $ | 0.53 | $ | 3.48 | $ | 4.14 | ||||||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||||||||||
|
Basic
|
117,631 | 117,381 | 117,601 | 117,345 | ||||||||||||
|
Diluted
|
118,992 | 118,644 | 119,028 | 118,668 | ||||||||||||
23
WHITING PETROLEUM CORPORATION
Reconciliation of Net Income Available to Common Shareholders to
Adjusted Net Income Available to Common Shareholders
(In thousands, except for per share data)
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Net Income Available to Common Shareholders
|
$ | 81,434 | $ | 62,620 | $ | 413,112 | $ | 490,610 | ||||||||
|
Adjustments Net of Tax:
|
||||||||||||||||
|
Amortization of Deferred Gain on Sale
|
(5,136 | ) | (2,227 | ) | (18,427 | ) | (8,781 | ) | ||||||||
|
Gain on Sale of Properties
|
(2,315 | ) | (1,012 | ) | (2,141 | ) | (10,278 | ) | ||||||||
|
Impairment Expense
|
38,996 | 8,869 | 67,465 | 24,435 | ||||||||||||
|
One-time Charge Under Production Participation Plan Related to Trust II Offering
|
- | - | 5,930 | - | ||||||||||||
|
Unrealized Derivative (Gains) Losses
|
(15,056 | ) | 56,273 | (72,393 | ) | (39,751 | ) | |||||||||
|
Adjusted Net Income (1)
|
$ | 97,923 | $ | 124,523 | $ | 393,546 | $ | 456,235 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Basic
|
$ | 0.83 | $ | 1.06 | $ | 3.35 | $ | 3.89 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Diluted
|
$ | 0.83 | $ | 1.05 | $ | 3.31 | $ | 3.85 | ||||||||
|
(1)
|
Adjusted Net Income Available to Common Shareholders is a non-GAAP financial measure. Management believes it provides useful information to investors for analysis of Whiting’s fundamental business on a recurring basis. In addition, management believes that Adjusted Net Income Available to Common Shareholders is widely used by professional research analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted Net Income Available for Common Shareholders should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
24
WHITING PETROLEUM CORPORATION
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(In thousands)
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Net cash provided by operating activities
|
$ | 383,270 | $ | 328,329 | $ | 1,401,215 | $ | 1,192,083 | ||||||||
|
Exploration
|
25,525 | 9,455 | 59,117 | 45,861 | ||||||||||||
|
Exploratory dry hole costs
|
(16,288 | ) | (210 | ) | (18,428 | ) | (4,924 | ) | ||||||||
|
Changes in working capital
|
(10,513 | ) | (8,496 | ) | (53,318 | ) | 10,762 | |||||||||
|
Preferred stock dividends paid
|
(269 | ) | (269 | ) | (1,077 | ) | (1,077 | ) | ||||||||
|
Discretionary cash flow (1)
|
$ | 381,725 | $ | 328,809 | $ | 1,387,509 | $ | 1,242,705 | ||||||||
|
(1)
|
Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-current items less the gain on sale of properties, amortization of deferred gain on sale, non-cash gains on mark-to-market derivatives, and preferred stock dividends paid. The non-GAAP measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
25