| Company contact: | John B. Kelso, Director of Investor Relations |
| | 303.837.1661 or john.kelso@whiting.com |
Whiting Petroleum Corporation Announces Fourth Quarter and
Full-Year 2011 Financial and Operating Results
2011 Production: A Record 24.8 MMBOE (67,890 BOE/d)
2011 Proved Reserves: Up 13.2% to a Record 345.2 MMBOE
Replaces 274% of 2011 Production
Q4 2011 Net Income Available to Common Shareholders of $62.6
Million or $0.53 per Diluted Share and Adjusted Net Income of
$124.5 Million or $1.05 per Diluted Share
Q4 2011 Discretionary Cash Flow Totals a Record $328.8 Million
2012 Capital Budget of $1.6 Billion for 242 Gross (148 Net) Wells
January 2012 Production Averages over 76,000 BOE/d
Increasing Q1 and FY 2012 Production Guidance to 6.8 - 7.2 MMBOE
and 28.3 - 29.7 MMBOE (+14% to 20% YoY)
DENVER – February 22, 2012 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2011 totaled a record 6.50 million barrels of oil equivalent (MMBOE), of which 5.45 million barrels were crude oil/natural gas liquids (84%) and 1.05 MMBOE was natural gas (16%). This fourth quarter 2011 production total equates to a new record daily average production rate of 70,685 barrels of oil equivalent (BOE), which compared to an average daily rate of 67,900 BOE in the fourth quarter of 2010. Production of 73,240 BOE per day in December 2011 represented a 3% increase over the 71,370 BOE per day average rate in September 2011.
Production in 2011 totaled a record 24.8 MMBOE, or an average of 67,890 BOE per day, compared to 23.6 MMBOE, or an average of 64,650 BOE per day, in 2010. The 5% increase in production for 2011 versus 2010 was primarily the result of organic production growth in the North Dakota Bakken and Three Forks formations as well as the continued response from Whiting’s CO2 enhanced oil recovery (EOR) projects.
In January 2012 our production averaged more than 76,000 BOE per day as we experienced exceptional drilling results and brought on line an additional 11 shut-in wells in our Sanish field. We have increased our first quarter 2012 production guidance to a range of 75,700 – 79,100 BOE per day from the prior range of 72,500 – 74,700 BOE per day. We have also increased our full-year 2012 production guidance to a range of 77,300 – 81,100 BOE per day, up from our prior range of 76,500 – 80,600 BOE per day. Our revised guidance for 2012 translates into an estimated production increase of between 14% and 20% over 2011. This production guidance does not consider the impact of the announced offering of Whiting USA Trust II, which is projected to produce approximately 1,467 MBOE for the full-year 2012 based on the trust’s projected 90% ownership of the underlying properties.
Operating and Financial Results
The following tables summarize the fourth quarter and full-year operating and financial results for 2011 and 2010.
| | Three Months Ended December 31, (1) |
| | | 2011 | | 2010 | | Change | |
| Production (MMBOE/MBOE/d) | | | 6.50/70.69 | | | 6.25/67.90 | | | 4% | |
Discretionary Cash Flow-MM$ (2) | | | 328.8 | | | 277.2 | | | 19% | |
| Total Revenues-MM$ | | | 498.6 | | | 413.5 | | | 21% | |
| Net Income Available to Shareholders-MM$ | | | 62.6 | | | 65.9 | | | (5%) | |
| Per Basic Share | | $ | 0.54 | | $ | 0.56 | | | (5%) | |
| Per Diluted Share | | $ | 0.53 | | $ | 0.56 | | | (5%) | |
Adjusted Net Income Available to Common Shareholders-MM$ (3) | | | 124.5 | | | 99.0 | | | 26% | |
| Per Basic Share | | $ | 1.06 | | $ | 0.85 | | | 25% | |
| Per Diluted Share | | $ | 1.05 | | $ | 0.84 | | | 25% | |
| | Twelve Months Ended December 31, (1) | |
| | | 2011 | | 2010 | | Change | |
| Production (MMBOE/MBOE/d) | | | 24.78/67.89 | | | 23.60/64.65 | | | 5% | |
Discretionary Cash Flow-MM$ (2) | | | 1,242.7 | | | 949.3 | | | 31% | |
| Total Revenues-MM$ | | | 1,899.6 | | | 1,516.1 | | | 25% | |
| Net Income Available to Shareholders-MM$ | | | 490.6 | | | 272.7 | | | 80% | |
| Per Basic Share | | $ | 4.18 | | $ | 2.57 | | | 63% | |
| Per Diluted Share | | $ | 4.14 | | $ | 2.55 | | | 62% | |
Adjusted Net Income Available to Common Shareholders-MM$ (3) | | | 456.2 | | | 304.7 | | | 50% | |
| Per Basic Share | | $ | 3.89 | | $ | 2.99 | | | 30% | |
| Per Diluted Share | | $ | 3.85 | | $ | 2.71 | | | 42% | |
| (1) | Restated for the 2010 period to reflect the Company’s February 22, 2011 two-for-one stock split. |
| (2) | A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release. |
| (3) | A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release. |
Proved Reserves at December 31, 2011
As of December 31, 2011, Whiting had estimated proved reserves of 345.2 MMBOE, of which 69% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $7,404.7 million, of which approximately 97% came from properties located in Whiting’s Rocky Mountain, Permian Basin and Mid-Continent core areas. The following table summarizes by core area, Whiting’s estimated proved reserves as of December 31, 2011, their corresponding pre-tax PV10% values and the fourth quarter 2011 average daily production rates:
| | | Proved Reserves (1) | | | |
| Core Area | | Oil (MMBbl)(2) | | Natural Gas (Bcf) | | Total (MMBOE) | | % Oil(2) | | | Pre-Tax PV10% Value(3) (In MM) | | Q4 2011 Average Daily Production (MBOE/d) | |
| | | | | | | | | | | | | | | |
| Rocky Mountains | | 132.2 | | 162.3 | | 159.2 | | 83 | % | | $ | 4,157.1 | | 44.4 | |
| Permian Basin | | 122.5 | | 38.1 | | 128.8 | | 95 | % | | $ | 2,011.6 | | 13.4 | |
Other(4) | | 43.1 | | 84.6 | | 57.2 | | 75 | % | | $ | 1,236.0 | | 12.9 | |
| Total | | 297.8 | | 285.0 | | 345.2 | | 86 | % | | $ | 7,404.7 | | 70.7 | |
| (1) | 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, 2011, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu. |
| (2) | Oil includes natural gas liquids. |
| (3) | 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 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, 2011, our discounted future income taxes were $2,132.2 million and our standardized measure of after-tax discounted future net cash flows was $5,272.5 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. |
| (4) | Other consists of Mid-Continent, Michigan, and Gulf Coast. |
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2011:
| | | | | | | | | | |
Balance – December 31, 2010 | | 254,278 | | | 303,544 | | | 304,869 | |
Extensions and discoveries | | 44,684 | | | 23,211 | | | 48,552 | |
Sales of minerals in place | | (1,211 | ) | | (9,759 | ) | | (2,837 | ) |
| Purchases of minerals in place | | 172 | | | 1,639 | | | 445 | |
Production | | (20,373 | ) | | (26,443 | ) | | (24,780 | ) |
| Revisions to previous estimates | | 20,203 | | | (7,217 | ) | | 19,000 | (1) |
Balance – December 31, 2011 | | 297,753 | | | 284,975 | | | 345,249 | |
| (1) | Whiting has experienced positive reserve revisions in each of the last three years (2009-2011). Of the 19.0 MMBOE of upward revisions in 2011, 4.7 MMBOE were due to commodity prices and 14.3 MMBOE were the result of reservoir analysis and well performance. The liquids component of the net 14.3 MMBOE revision consisted of a 15.7 MMBOE increase that was primarily related to our Postle and North Ward Estes fields where performance of the EOR projects supported an increase in proved reserves. The gas component of the net 14.3 MMBOE revision consisted of a 1.4 MMBOE decrease due to production performance of two wells in our Flat Rock field. |
Whiting’s proved reserves of 345.2 MMBOE represented a 13.2% increase over the 304.9 MMBOE of proved reserves at year-end 2010. An estimated 48.6 MMBOE of proved reserves were added through exploration and development activities. In total, Whiting replaced 274% of its 2011 production of 24.8 MMBOE at an all-in finding and development cost of $27.09 per BOE, which includes $230.6 million in facilities and $186.9 million of land expenditures. The table at the end of this news release summarizes Whiting’s all-in finding and development costs and reserve replacement for the three-year period ended December 31, 2011.
Most of the proved reserve additions during 2011 came from the Company’s Bakken and Three Forks development in the Williston Basin of North Dakota and Montana. Whiting booked an estimated 45.1 MMBOE of new Bakken and Three Forks proved reserves, bringing its total proved reserves in the Northern Rockies to 128.6 MMBOE at year-end 2011. Of this 128.6 MMBOE, 69% were proved developed and 31% were proved undeveloped.
Probable and Possible Reserves at December 31, 2011
At year-end 2011, Whiting’s probable reserves were estimated to be 105.9 MMBOE and our possible reserves were estimated to be 195.3 MMBOE, for a total of 301.2 MMBOE. The year-end 2011 estimated pre-tax PV10% for our probable and possible reserves was $3,059.2 million, representing a 27% increase over the $2,415.2 million at year-end 2010.
The EOR project at our North Ward Estes field represented 115.5 MMBOE of the 301.2 MMBOE total, or 38%. The other primary contributors to Whiting’s probable and possible reserve estimates were additional Bakken and Three Forks reserves in the Williston Basin with 71.0 MMBOE. 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.
The following tables summarize Whiting’s estimated probable and possible reserves as of December 31, 2011 by core area and the corresponding pre-tax PV10% values.
Probable Reserves (1) | |
| Core Area | | Oil (MMBbl)(2) | | Natural Gas (Bcf) | | Total (MMBOE) | | % | | | Pre-Tax PV10% Value(3) | |
Oil(2) | | | (In MM) | |
| | | | | | | | | | | | | |
| Rocky Mountains | | 24.7 | | 133.5 | | 46.9 | | 53 | % | | $ | 374.9 | |
| Permian Basin | | 36.9 | | 53.0 | | 45.8 | | 81 | % | | $ | 576.6 | |
Other(4) | | 9.2 | | 24.4 | | 13.2 | | 69 | % | | $ | 83.9 | |
| Total | | 70.8 | | 210.9 | | 105.9 | | 67 | % | | $ | 1,035.4 | |
| | |
Possible Reserves (1) | |
| Core Area | | Oil (MMBbl)(2) | | Natural Gas (Bcf) | | Total (MMBOE) | | % | | | Pre-Tax PV10% Value(3) | |
Oil(2) | | | (In MM) | |
| | | | | | | | | | | | | | |
| Rocky Mountains | | 59.2 | | 150.0 | | 84.3 | | 70 | % | | $ | 1,086.9 | |
| Permian Basin | | 101.9 | | 8.9 | | 103.3 | | 99 | % | | $ | 861.0 | |
Other(4) | | 3.0 | | 28.3 | | 7.7 | | 39 | % | | $ | 75.9 | |
| Total | | 164.1 | | 187.2 | | 195.3 | | 84 | % | | $ | 2,023.8 | |
| (1) | 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, 2011, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu. |
| (2) | Oil includes natural gas liquids. |
| (3) | Pre-tax PV10% amounts above 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. |
| (4) | Other consists of Mid-Continent, Michigan, and Gulf Coast. |
Resource Potential at December 31, 2011
Whiting has internally estimated its unrisked total resource potential to be 479 MMBOE at year-end 2011, representing a 28% increase from the 374 MMBOE estimate at year-end 2010. The largest contributor to this 479 MMBOE total was continued Bakken and Three Forks exploration in North Dakota and Montana with 180 MMBOE. The year-end 2011 estimated PV10% for our resource potential was $4,734 million, representing a 12% increase over the $4,238 million at year-end 2010. Please refer to “Disclosure Regarding Reserves and Resources” later in this news release for information on resource potential.
The following table summarizes Whiting’s estimated resource potential as of December 31, 2011 by core area and the corresponding pre-tax PV10%.
Resource Potential (1) |
| Core Area | | Oil (MMBbl)(2) | | Natural Gas (Bcf) | | Total (MMBOE) | | % | | | Pre-Tax PV10% Value(3) | |
Oil(2) | | | (In MM) | |
| | | | | | | | | | | | | |
| Rocky Mountains | | 297.4 | | 506.7 | | 381.9 | | 78 | % | | $ | 3,944.9 | |
| Permian Basin | | 59.9 | | 86.1 | | 74.2 | | 81 | % | | $ | 706.8 | |
| Other | | 7.4 | | 91.8 | | 22.6 | | 32 | % | | $ | 82.2 | |
| Total | | 364.7 | | 684.6 | | 478.7 | | 76 | % | | $ | 4,733.9 | |
| (1) | 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, 2011, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $96.19/Bbl and $4.12/MMBtu. |
| (2) | Oil includes natural gas liquids. |
| (3) | Pre-tax PV10% amounts above represent the present value of estimated future revenues to be generated from the production of resource potential 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% values of resource potential reserves, there do not exist any directly comparable US GAAP measures and such amounts do not purport to present the fair value of our resource potential reserves. |
| (4) | Other consists of Mid-Continent, Michigan, and Gulf Coast. |
Total Drilling Locations at December 31, 2011
Based on independent engineering, Whiting has a total of 2,264 proved, probable and possible gross drilling locations. Of these, 31% are located in its core Northern Rockies Region, which includes Whiting’s Bakken/Three Forks projects in the Williston Basin. In addition, the Company estimates it has 3,741 gross resource locations across its company-wide acreage position. Of these, 49% are located in Whiting’s core Northern Rockies Region, which includes its Bakken/Three Forks projects in the Williston Basin.
The following tables summarize our potential gross and net drilling locations by core region from our proved, probable and possible reserves and our resource potential:
| Total 3P Drilling Locations |
| | Gross | Net |
| Northern Rockies | 707 | 334 |
| Central Rockies | 421 | 283 |
| Permian Basin | 838 | 338 |
| Mid-Continent | 210 | 189 |
| Gulf Coast | 72 | 58 |
| Michigan | 16 | 13 |
| Total | 2,264 | 1,215 |
| Total Resource Drilling Locations |
| | Gross | Net |
| Northern Rockies | 1,839 | 640 |
| Central Rockies | 1,416 | 889 |
| Permian Basin | 417 | 307 |
| Mid-Continent | 6 | 1 |
| Gulf Coast | 34 | 31 |
| Michigan | 29 | 22 |
| Total | 3,741 | 1,890 |
James J. Volker, Whiting’s Chairman and CEO, commented, “2011 was a year of discoveries for Whiting Petroleum. We de-risked a substantial portion of our acreage at Lewis & Clark/Pronghorn and generated excellent initial drilling results at Hidden Bench/Tarpon. Our 2011 drilling program sets the table for what we believe will be a strong year for production and reserves growth in 2012. Based on independent engineering at December 31, 2011, we had 2,264 gross locations from our 3P reserves. Based on internal estimates at year-end 2011, we had an additional 3,741 gross locations estimated from our resource potential.”
Mr. Volker continued, “In 2012, we will focus on bringing a number of our prospects into development mode. These prospects include Hidden Bench/Tarpon and Missouri Breaks. We also plan further development of our resource play at Lewis & Clark/Pronghorn. With these key projects, we are optimistic about Whiting’s operational results in 2012. We will continue to focus on oil in the foreseeable future. Currently, crude oil trades at more than 40 times the price of natural gas, which compares to their 6 to 1 heating equivalency ratio. At year-end 2011, 86% of our proved reserves and 84% of our production consisted of oil and natural gas liquids. We expect that percentage to continue to increase over the next several years.”
2012 Capital Budget
Our 2012 capital budget is $1,600 million, which we expect to fund substantially with net cash provided by our operating activities. Whiting expects to invest $1,236 million of the 2012 capital budget in exploration and development activity, $136 million for land, and $228 million for facilities. Based on this level of capital spending, we forecast production of 28.3 MMBOE - 29.7 MMBOE for 2012, an increase of 14% - 20% over our 2011 production of 24.8 MMBOE.
Our 2012 capital budget is currently allocated among our major development areas as indicated in the table below:
| | | 2012 CAPEX (MM) | | Gross Wells | | | Net Wells | | | % of CAPEX | |
| Northern Rockies | | $ | 851 | | 218 | | | 124 | | | 53 | % |
| EOR | | | 177 | | NA | (2) | | NA | (2) | | 11 | % |
| Permian | | | 60 | | 13 | | | 13 | | | 4 | % |
| Central Rockies | | | 50 | | 11 | | | 11 | | | 3 | % |
| Non-Operated | | | 42 | | | | | | | | 3 | % |
| Land | | | 136 | | | | | | | | 9 | % |
Exploration Expense (1) | | | 56 | | | | | | | | 3 | % |
| Facilities | | | 228 | | | | | | | | 14 | % |
| Total Budget | | $ | 1,600 | | 242 | | | 148 | | | 100 | % |
| (1) | Comprised primarily of exploration salaries, seismic activities and delay rentals. |
| (2) | These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis. |
The following table breaks out our 2012 capital budget by category:
| | | 2012 CAPEX (MM) | | % of CAPEX | |
| Development Drilling | | $ | 892 | | 56 | % |
| Facilities | | | 229 | | 14 | % |
| Exploration Drilling | | | 144 | | 9 | % |
| Land | | | 136 | | 9 | % |
CO2 Purchases | | | 83 | | 5 | % |
| Workovers | | | 49 | | 3 | % |
| Seismic | | | 16 | | 1 | % |
Other (1) | | | 51 | | 3 | % |
Total | | $ | 1,600 | | 100 | % |
| (1) | Includes $40 million of exploration expense primarily for exploration salaries and delay rentals. |
Operations Update
Williston Basin Overview
Whiting is one of the largest oil and gas producers in North Dakota. We ranked first in total production per well during the first six months based on information from IHS Energy, Inc. and the NDIC, with an average first six months production of 91,000 BOE. This average was 6,000 BOE higher than the second ranked Bakken operator and 30,000 BOE better than the average of the next 25 operators. We have achieved these rankings while having some of the lowest completed well costs in our Bakken peer group. We are currently drilling and completing wells in the Sanish field for approximately $6.0 million. Outside of Sanish, in other North Dakota areas, our completed well costs are currently running between $6.0 and $8.0 million and declining as we move into development mode. In addition, our average lease cost in the Williston Basin, where we hold 681,504 net acres in the Bakken/Three Forks Hydrocarbon System, is $432 per net acre.
In 2012, we plan to invest $851 million for the drilling and completion of 218 gross (124 net) wells in the Williston Basin. This represents 69% of our total planned exploration and development expenditures of $1,236 million. We have initiated pad drilling at our Sanish field and our Lewis & Clark/Pronghorn prospects. We expect to drill two or three wells off of each pad at Sanish and, for the most part, two wells off of each pad at Lewis & Clark/Pronghorn. We currently estimate that we can save approximately $500,000 per well in mobilization costs and efficiencies utilizing pad drilling.
We currently have 21 drilling rigs operating in the Williston Basin. We have 33 service rigs running in the Basin, which is up from 20 at September 22, 2011, and three full-time dedicated frac crews. As of February 1, 2012, there were 292 Whiting-operated wells producing, 46 operated wells being completed or awaiting completion, 16 wells were being drilled and 31 wells were shut-in awaiting workover operations.
Core Development Areas
Bakken and Three Forks Development
Lewis & Clark/Pronghorn Prospects. Whiting’s net production from the Lewis & Clark/Pronghorn prospects averaged 5,870 BOE per day in the fourth quarter of 2011, up 48% from the 3,960 BOE per day average in the third quarter of 2011. We currently have six drilling rigs operating in the Pronghorn prospect and two drilling rigs running in the Lewis & Clark prospect. We own 385,665 gross (256,296 net) acres in the Lewis & Clark/Pronghorn prospects, which is three and a half times the area of Sanish field.
The following table summarizes our results from inception to December 31, 2011 from the Pronghorn Sand/Three Forks at Lewis & Clark/Pronghorn:
Lewis & Clark/Pronghorn Total Wells(1) |
| | Avg WI % | Avg NRI % | Avg IP BOE/d 24-hr Test | Avg 1st 30 Day | Avg 1st 60 Day | Avg 1st 90 Day |
| No. of Wells | 44 | 44 | 44 | 41 | 37 | 33 |
| Averages | 79% | 63% | 1,312 | 565 | 435 | 376 |
| (1) | Excludes five delineation wells drilled outside the reservoir boundary. |
The following table highlights some notable Pronghorn Prospect wells completed in the Pronghorn Sand during the fourth quarter of 2011 and to date in the first quarter of 2012:
| Well Name | WI | NRI | IP (BOE/d) |
| 24-Hour Test |
| Obrigewitch 21-16TFH | 89% | 71% | 3,373 |
| Pronghorn Federal 21-13TFH | 99% | 79% | 3,255 |
| Mastel 41-18TFH | 77% | 61% | 3,218 |
| DRS Federal 24-24TFH | 87% | 69% | 2,898 |
| Frank 34-7TFH | 90% | 72% | 2,811 |
| Marsh 21-16TFH-R | 82% | 66% | 2,694 |
| Buresh 34-10TFH | 44% | 35% | 2,171 |
| Pronghorn Federal 21-14TFH | 53% | 42% | 1,849 |
| Obrigewitch 11-17TFH | 96% | 77% | 1,740 |
| Pronghorn Federal 34-11TFH | 100% | 80% | 1,645 |
| Averages | 82% | 65% | 2,565 |
Hidden Bench/Tarpon Prospects. Whiting’s net production from the Hidden Bench prospect averaged 1,765 BOE per day, more than double the 855 BOE per day rate in the third quarter of 2011. We currently hold 59,894 gross (29,354 net) acres in the prospect, which is located in McKenzie County, North Dakota.
Whiting’s first well at the Tarpon prospect set a new initial production record for all Bakken wells drilled in the Williston Basin. The Tarpon Federal 21-4H well was completed in the Middle Bakken (after a 30 stage sliding sleeve frac job) flowing 4,815 barrels of oil and 13,163 Mcf of gas (7,009 BOE) per day on October 17, 2011. As of December 31, 2011, the well was producing 1,528 BOE per day. The Company owns a 56% working interest and a 45% net revenue interest in the Tarpon well. Whiting drilling engineers and field personnel also set a new Tarpon Prospect area record by drilling this well to total depth in 13.3 days. Whiting holds 8,125 gross (6,265 net) acres at the Tarpon prospect, which is located in McKenzie County, North Dakota. We have the potential to drill a total of 12 Middle Bakken and eight Three Forks wells on this prospect. We expect to resume drilling at Tarpon in June 2012, subject to federal permitting.
The following table summarizes our results from inception to December 31, 2011 from the Hidden Bench/Tarpon prospects:
| Hidden Bench/Tarpon Total Wells |
| | Avg WI % | Avg NRI % | Avg IP BOE/d 24-hr Test | Avg 1st 30 Day | Avg 1st 60 Day | Avg 1st 90 Day |
| No. of Wells | 8 | 8 | 8 | 5 | 3 | 3 |
| Averages | 68% | 55% | 2,904 | 941 | 1,040 | 930 |
Missouri Breaks Prospect. In our Missouri Breaks prospect, we target the same Middle Bakken “C” zone that we target at our Hidden Bench/Tarpon prospects. We have initiated a one-rig drilling program in the play. We hold 58,840 gross (40,290 net) acres in the prospect and have controlling interests in 46 1,280-acre spacing units. Subsequent to year-end, we entered into a contract to add 51,200 gross (13,300 net) acres in the prospect. This transaction is expected to close in March 2012. Missouri Breaks is located in Richland County, Montana.
Sanish Field. During the fourth quarter, Whiting completed 19 gross operated wells at Sanish, bringing the total number of producing wells in the field to 218. The following table summarizes the Company’s operated and non-operated net production from the Sanish and Parshall fields in the fourth quarter and in December 2011:
Operated and Non-operated Net Production for Sanish and Parshall Fields (In BOE) | |
| | | Three Months Ended December 31, 2011 | | | | |
| | | | | | | | | | | | | | | |
| Whiting Operated | | 18,401 | | 1,904,524 | | 1,922,925 | | | 5,330 | | 718,824 | | 724,154 | |
| Non-Operated | | 262,051 | | 198,053 | | 460,104 | | | 82,711 | | 79,097 | | 161,808 | |
| | | 280,452 | | 2,102,577 | | 2,383,029 | | | 88,041 | | 797,921 | | 885,962 | |
| Daily BOE | | 3,050 | | 22,850 | | 25,900 | | | 2,840 | | 25,740 | | 28,580 | (1) |
| (1) | Up from 27,215 BOE/d in September 2011. |
Robinson Lake Gas Plant. As of February 1, 2012, the plant was processing 52.7 MMcf of gas per day (gross). Currently, there is inlet compression in place to process 60 MMcf per day. Compression can be added to 90 MMcf per day as the processing demand increases. Whiting owns a 50% interest in the plant.
Belfield Gas Processing Plant. Construction of our Belfield gas plant was completed on schedule, and the plant began processing gas on December 20, 2011 at a rate of 5.0 MMcf per day. Currently, there is inlet compression in place to process 24 MMcf per day.
Belfield Oil Pipeline. Whiting completed the installation of its seven mile oil transmission line to the Bridger Pipeline interconnect in late January 2012. Whiting’s oil production began flowing into the pipeline on February 1, 2012. We estimate that the completion of this pipeline will reduce transportation costs by $3.50 – $4.00 per barrel.
EOR Projects
North Ward Estes Field. Production from our North Ward Estes field averaged 8,795 BOE per day in the fourth quarter of 2011. This average rate represented a 4% increase from the 8,440 net daily rate in the third quarter of 2011. Since September 1, 2011, we have been receiving our full contract quantities of 134 MMcf of CO2 per day at North Ward Estes. Whiting is currently injecting approximately 300 MMcf of CO2 per day into the field, of which about 64% is recycled gas.
Residual Oil Zone. Whiting recently began drilling operations at a pilot project in North Ward Estes field to test a Residual Oil Zone (“ROZ”). Current EOR production from North Ward Estes is from the Yates formation at a depth of approximately 2,600 feet. We plan to initiate CO2 injection into the deeper ROZ by the end of the first quarter 2012. Resource potential from the ROZ has been independently estimated as 148 MMBOE based on well tests conducted to date. This is not currently reflected in our “Resource Potential” table as we await results from our initial pilot, which are expected by year-end 2012.
Postle Field. In the fourth quarter of 2011, the Postle field produced at an average net rate of 8,050 BOE per day, which is about flat with the 7,980 BOE average daily rate in the third quarter of 2011. Whiting is currently injecting 120 MMcf of CO2 per day into the field, of which approximately 71% is recycled gas.
Other Development Areas
Delaware Basin: Big Tex Prospect. Whiting’s lease position at Big Tex consists of 1 120,719 gross (89,820 net) acres. Targets include the Brushy Canyon, Bone Spring, and Wolfcamp horizons. Based on positive results from the Trainer Trust 16-2 vertical Bone Spring well and the Bissett 9701H horizontal Bone Spring well, we have planned a 13-well drilling program for Big Tex in 2012 with a budget of $57 million. The majority of these wells are expected to be horizontal Bone Spring wells. On the western half of our acreage, we are also initiating a vertical Wolfbone program. These wells will commingle production from the Wolfcamp and from as many as three benches in the Bone Spring. Whiting expects to continue to operate two rigs on the prospect in 2012.
Denver Basin: Redtail Niobrara Prospect. The Redtail prospect targets the Niobrara “B” zone in the Denver Basin, in Weld County, Colorado. Whiting controls 105,597 gross (73,611 net) acres in the play. Whiting recently completed its first well drilled on a 960-acre spacing unit, the Horsetail 18-0733H, with an initial production rate of 718 BOE per day from a 6,296-foot lateral. The Horsetail well was drilled about 12 miles northeast of the Wildhorse discovery well. Utilizing recently acquired 3D seismic, we plan to drill eight wells at Redtail in 2012. These include a three-well development program located between our Wildhorse discovery well and our Horsetail 18-0733H. Our Horsetail well was drilled to total depth in 16 days. Whiting expects to continue to operate one drilling rig on the prospect in 2012.
Operated Drilling and Workover Rig Count
As of December 31, 2011, 27 operated drilling rigs and 67 operated workover rigs were active on our properties. We were also participating in the drilling of two non-operated wells, all in North Dakota.
The breakdown of our operated rigs as of December 31, 2011 was as follows:
| Region | | Drilling | | Workover | |
| Northern Rockies | | 21 | | 23 | |
| Permian Basin | | 4 | | 7 | |
| EOR Projects | | | | | |
| Postle | | 1 | | 6 | |
| North Ward Estes | | 1 | | 30 | |
| Michigan | | -- | | 1 | |
Totals | | 27 | | 67 | |
As of February 1, 2012 we had 33 service units active in the Williston Basin. These service units have reduced the number of shut-in wells at the Sanish field from 66 to 31 as of February 1, 2012. We expect to reduce the number of shut-in wells awaiting service work in Sanish field to approximately 20 by the end of the first quarter.
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2011 and 2010:
| | | Three Months Ended December 31, | | | | |
| Production | | | | | | | | | |
| Oil and NGLs (MMBbls) | | | 5.45 | | | | 5.03 | | | 8% | |
| Natural gas (Bcf) | | | 6.35 | | | | 7.32 | | | (13%) | |
| Total equivalent (MMBOE) | | | 6.50 | | | | 6.25 | | | 4% | |
| | | | | | | | | | | | |
| | | | Three Months Ended December 31, | | | | |
| Average Sales Price | | | 2011 | | | | 2010 | | | | |
| Oil and NGLs (per Bbl): | | | | | | | | | | | |
| Price received | | $ | 84.86 | | | $ | 74.53 | | | 14% | |
Effect of crude oil hedging (1) | | | (0.77 | ) | | | (1.80 | ) | | | |
| Realized price | | $ | 84.09 | | | $ | 72.73 | | | 16% | |
| | | | | | | | | | | | |
| Natural gas (per Mcf): | | | | | | | | | | | |
| Price received | | $ | 4.72 | | | $ | 4.34 | | | 9% | |
Effect of natural gas hedging (1) | | | 0.05 | | | | 0.05 | | | | |
| Realized price | | $ | 4.77 | | | $ | 4.39 | | | 9% | |
| (1) | Whiting realized pre-tax cash settlement losses of $4.2 million on its crude oil hedges and gains of $0.4 million on its natural gas hedges during the fourth quarter of 2011. A summary of Whiting’s outstanding hedges is included later in this news release. |
Fourth Quarter and Full-Year 2011 Costs and Margins
A summary of production, cash revenues and cash costs is as follows:
| | | Per BOE, Except Production | |
| | | Three Months | | | Twelve Months | |
| | | | | | | |
| | | | | | | | | | | | | |
| Production (MMBOE) | | | 6.50 | | | | 6.25 | | | | 24.78 | | | | 23.60 | |
| | | | | | | | | | | | | | | | | |
| Sales price, net of hedging | | $ | 75.07 | | | $ | 63.66 | | | $ | 73.88 | | | $ | 61.48 | |
| Lease operating expense | | | 12.69 | | | | 11.33 | | | | 12.33 | | | | 11.37 | |
| Production tax | | | 5.96 | | | | 4.25 | | | | 5.62 | | | | 4.40 | |
| General & administrative | | | 3.46 | | | | 2.59 | | | | 3.43 | | | | 2.74 | |
| Exploration | | | 1.45 | | | | 1.12 | | | | 1.85 | | | | 1.39 | |
| Cash interest expense | | | 2.20 | | | | 1.78 | | | | 2.17 | | | | 2.05 | |
| Cash income tax expense (benefit) | | | (0.11 | ) | | | (0.24 | ) | | | 0.16 | | | | 0.21 | |
| | | $ | 49.42 | | | $ | 42.83 | | | $ | 48.32 | | | $ | 39.32 | |
During the fourth quarter of 2011, the company-wide basis differential for crude oil compared to NYMEX was $9.16 per barrel, which compared to $8.85 per barrel in the third quarter of 2011. We expect our company-wide oil price differential to average between $13.00 and $14.00 during the first quarter of 2012. Within the Bakken, Whiting’s operated production had a differential of approximately $14.00 per barrel in February 2012.
The company-wide basis differential for natural gas compared to NYMEX in the fourth quarter of 2011 was at a premium of $1.18 per Mcf, which compared to a premium of $0.80 per Mcf in the third quarter of 2011. We expect our natural gas to sell at a premium price of between $0.60 and $0.90 during the first quarter of 2012.
Fourth Quarter and Full-Year 2011 Drilling and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and exploration and development costs incurred for the three and twelve months ended December 31, 2011:
| | | | Gross/Net Wells Completed | | | | |
| | | | | | | | | | | | | | | | Capital | |
| | | | | | | | | | Total New | | | % Success | | | Costs | |
| | | | | | | | | | | | | | | | | |
| Q4 11 | | | | 76 / 38.8 | | | | 1 / 0.3 | (1) | | | 77 / 39.1 | | | | 99% / 99 | % | | $ | 523.5 | (2) |
| 12M 11 | | | | 278 / 130.5 | | | | 6 / 4.5 | (1) | | | 284 / 135.0 | | | | 98% / 97 | % | | $ | 1,840.2 | (2) |
| (1) | Includes one exploratory dry hole and one development dry hole for shallow Wilcox at Greenbranch field in McMullen Co., TX, one re-entry mechanical failure exploratory well at the Big Tex prospect, Pecos Co., TX, one exploratory Niobrara dry hole in Carbon Co., WY, one non-op development Red River oil test in Richland Co., MT, and one non-op development test in Kent Co., TX. |
| (2) | Includes $7.2 million and $186.9 million of acreage acquisition costs for the three and twelve months ended December 31, 2011, respectively. |
Outlook for First Quarter and Full-Year 2012
As mentioned earlier in this news release, we have increased our production guidance for the first quarter and full-year 2012. This production guidance does not consider the impact of the announced offering of Whiting USA Trust II, which is projected to produce approximately 1,467 MBOE for the full-year 2012 based on the trust’s projected 90% ownership of the underlying properties. We have also adjusted our costs per BOE and have increased our company-wide differential due to the recent widening of Bakken differentials in the Williston Basin.
The following table provides guidance for the first quarter and full-year 2012 based on current forecasts, including Whiting’s full-year 2012 capital budget of $1,600 million:
| | | Guidance | |
| | | First Quarter | | | Full-Year | |
| | | 2012 | | | 2012 | |
| Production (MMBOE) | | | | 6.80 | | - | | | 7.20 | | | | | 28.30 | | - | | | 29.70 | |
| Lease operating expense per BOE | | | $ | 12.80 | | - | | $ | 13.10 | | | | $ | 13.00 | | - | | $ | 13.40 | |
| General and admin. expense per BOE | | | $ | 3.60 | | - | | $ | 3.80 | | | | $ | 3.70 | | - | | $ | 3.90 | |
| Interest expense per BOE | | | $ | 2.55 | | - | | $ | 2.75 | | | | $ | 2.50 | | - | | $ | 2.70 | |
| Depr., depletion and amort. per BOE | | | $ | 20.00 | | - | | $ | 20.50 | | | | $ | 20.50 | | - | | $ | 20.90 | |
| Prod. taxes (% of production revenue) | | | | 7.8% | | - | | | 8.0% | | | | | 7.9% | | - | | | 8.2% | |
| Oil price differentials to NYMEX per Bbl | | ( | $ | 13.00 | ) | - | ( | $ | 14.00 | ) | | ( | $ | 10.50 | ) | - | ( | $ | 11.50 | ) |
Gas price premium to NYMEX per Mcf (1) | | | $ | 0.60 | | - | | $ | 0.90 | | | | $ | 0.60 | | - | | $ | 0.90 | |
| (1) | Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release. |
Oil Hedges
The following summarizes Whiting’s crude oil hedges as of January 31, 2012:
| | | | | Weighted Average | | As a Percentage of |
| Hedge | | Contracted Volume | | NYMEX Price Collar Range | | December 2011 |
| | | | | | |
| | | | | | | |
| 2012 | | | | | | |
| Q1 | | 984,054 | | $66.63 - $108.56 | | 51.2% |
| Q2 | | 983,850 | | $66.63 - $108.56 | | 51.2% |
| Q3 | | 983,650 | | $66.63 - $108.55 | | 51.1% |
| Q4 | | 983,477 | | $66.63 - $108.55 | | 51.1% |
| | | | | | | |
| 2013 | | | | | | |
| Q1 | | 290,000 | | $47.67 - $90.21 | | 15.1% |
| Q2 | | 290,000 | | $47.67 - $90.21 | | 15.1% |
| Q3 | | 290,000 | | $47.67 - $90.21 | | 15.1% |
| Oct | | 290,000 | | $47.67 - $90.21 | | 15.1% |
| Nov | | 190,000 | | $47.22 - $85.06 | | 9.9% |
The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of January 31, 2012:
| | | | | Weighted Average | | As a Percentage of |
| Hedge | | Contracted Volume | | NYMEX Price Collar Range | | December 2011 |
| | | | | | |
| | | | | | | |
| 2012 | | | | | | |
| Q1 | | 33,381 | | $7.00 - $15.55 | | 1.6% |
| Q2 | | 32,477 | | $6.00 - $13.60 | | 1.6% |
| Q3 | | 31,502 | | $6.00 - $14.45 | | 1.5% |
| Q4 | | 30,640 | | $7.00 - $13.40 | | 1.5% |
Whiting also had the following fixed-price natural gas contracts in place as of January 31, 2012:
| | | | | Weighted Average | | As a Percentage of |
| Hedge | | Contracted Volume | | Contracted Price | | December 2011 |
| | | | | | |
| | | | | | | |
| 2012 | | | | | | |
| Q1 | | 576,963 | | $5.30 | | 27.7% |
| Q2 | | 461,296 | | $5.41 | | 22.1% |
| Q3 | | 465,630 | | $5.41 | | 22.4% |
| Q4 | | 398,667 | | $5.46 | | 19.1% |
| | | | | | | |
| 2013 | | | | | | |
| Q1 | | 360,000 | | $5.47 | | 17.3% |
| Q2 | | 364,000 | | $5.47 | | 17.5% |
| Q3 | | 368,000 | | $5.47 | | 17.7% |
| Q4 | | 368,000 | | $5.47 | | 17.7% |
| | | | | | | |
| 2014 | | | | | | |
| Q1 | | 330,000 | | $5.49 | | 15.8% |
| Q2 | | 333,667 | | $5.49 | | 16.0% |
| Q3 | | 337,333 | | $5.49 | | 16.2% |
| Q4 | | 337,333 | | $5.49 | | 16.2% |
Selected Operating and Financial Statistics
| | | Three Months Ended December 31, | | | Twelve Months Ended December 31, | |
| | | | | | | | | | | | | |
| Selected operating statistics | | | | | | | | | | | | |
| Production | | | | | | | | | | | | |
Oil and NGLs, MBbl | | | 5,445 | | | | 5,026 | | | | 20,373 | | | | 19,030 | |
Natural gas, MMcf | | | 6,347 | | | | 7,323 | | | | 26,443 | | | | 27,392 | |
Oil equivalents, MBOE | | | 6,503 | | | | 6,246 | | | | 24,780 | | | | 23,596 | |
| Average Prices | | | | | | | | | | | | | | | | |
Oil per Bbl (excludes hedging) | | $ | 84.86 | | | $ | 74.53 | | | $ | 84.92 | | | $ | 70.53 | |
| Natural gas per Mcf (excludes hedging) | | $ | 4.72 | | | $ | 4.34 | | | $ | 4.92 | | | $ | 4.86 | |
| Per BOE Data | | | | | | | | | | | | | | | | |
Sales price (including hedging) | | $ | 75.07 | | | $ | 63.66 | | | $ | 73.88 | | | $ | 61.48 | |
Lease operating | | $ | 12.69 | | | $ | 11.33 | | | $ | 12.33 | | | $ | 11.37 | |
Production taxes | | $ | 5.96 | | | $ | 4.25 | | | $ | 5.62 | | | $ | 4.40 | |
| Depreciation, depletion and amortization | | $ | 19.58 | | | $ | 16.66 | | | $ | 18.89 | | | $ | 16.69 | |
General and administrative | | $ | 3.46 | | | $ | 2.59 | | | $ | 3.43 | | | $ | 2.74 | |
| Selected Financial Data | | | | | | | | | | | | | | | | |
| (In thousands, except per share data) | | | | | | | | | | | | | | | | |
Total revenues and other income | | $ | 498,637 | | | $ | 413,469 | | | $ | 1,899,622 | | | $ | 1,516,099 | |
Total costs and expenses | | $ | 400,434 | | | $ | 308,429 | | | $ | 1,119,303 | | | $ | 974,656 | |
| Net income available to common shareholders | | $ | 62,620 | | | $ | 65,925 | | | $ | 490,610 | | | $ | 272,683 | |
Earnings per common share, basic (1) | | $ | 0.54 | | | $ | 0.56 | | | $ | 4.18 | | | $ | 2.57 | |
Earnings per common share, diluted (1) | | $ | 0.53 | | | $ | 0.56 | | | $ | 4.14 | | | $ | 2.55 | |
| | | | | | | | | | | | | | | | | |
Average shares outstanding, basic (1) | | | 117,381 | | | | 117,098 | | | | 117,345 | | | | 106,338 | |
Average shares outstanding, diluted (1) | | | 118,644 | | | | 118,564 | | | | 118,668 | | | | 107,846 | |
| Net cash provided by operating activities | | $ | 328,329 | | | $ | 277,022 | | | $ | 1,192,083 | | | $ | 997,289 | |
Net cash used in investing activities | | $ | (493,156 | ) | | $ | (346,496 | ) | | $ | (1,760,036 | ) | | $ | (914,574 | ) |
| Net cash provided by (used in) financing activities | | $ | 174,550 | | | $ | 85,215 | | | $ | 564,812 | | | $ | (75,723 | ) |
| (1) | All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011. |
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 23, 2012 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 2011 financial and operating results. Please call (800) 320-2978 (U.S./Canada) or (617) 614-4923 (International) and enter the pass code 77936886 to be connected to the call. Access to a live Internet broadcast will be available at 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 23, 2012.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 23, 2012 and continuing through Thursday, March 1, 2012. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 36375988. 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 acquires, exploits, develops and explores for 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 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.
These risks and uncertainties include, but are not limited to: declines in oil or natural gas prices; our level of success in exploitation, exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO2; 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; impacts of the global recession and tight credit markets; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state regulatory 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; 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; 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, 2011. 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.
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.
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, 2011, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
| | | | | | | |
| | | | | | | |
| ASSETS | | | | | | |
| | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 15,811 | | | $ | 18,952 | |
| Accounts receivable trade, net | | | 262,515 | | | | 199,713 | |
| Prepaid expenses and other | | | 20,377 | | | | 14,878 | |
| Total current assets | | | 298,703 | | | | 233,543 | |
| | | | | | | | | |
| Property and equipment: | | | | | | | | |
| Oil and gas properties, successful efforts method: | | | | | | | | |
| Proved properties | | | 7,221,550 | | | | 5,661,619 | |
| Unproved properties | | | 354,774 | | | | 226,336 | |
| Other property and equipment | | | 150,933 | | | | 98,092 | |
| Total property and equipment | | | 7,727,257 | | | | 5,986,047 | |
| Less accumulated depreciation, depletion and amortization | | | (2,088,517 | ) | | | (1,630,824 | ) |
| Total property and equipment, net | | | 5,638,740 | | | | 4,355,223 | |
| | | | | | | | | |
| Debt issuance costs | | | 33,306 | | | | 34,226 | |
| | | | | | | | | |
| Other long term assets | | | 74,860 | | | | 25,785 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 6,045,609 | | | $ | 4,648,777 | |
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
| | | | | | | |
| LIABILITIES AND EQUITY | | | | | | |
| | | | | | | |
| Current liabilities: | | | | | | |
Accounts payable trade | | $ | 56,673 | | | $ | 35,016 | |
Accrued capital expenditures | | | 142,827 | | | | 84,789 | |
Accrued liabilities and other | | | 157,214 | | | | 153,062 | |
Revenues and royalties payable | | | 103,894 | | | | 82,124 | |
Taxes payable | | | 31,195 | | | | 30,291 | |
Derivative liabilities | | | 73,647 | | | | 69,375 | |
Deferred income taxes | | | 1,584 | | | | 4,548 | |
Total current liabilities | | | 567,034 | | | | 459,205 | |
Long-term debt | | | 1,380,000 | | | | 800,000 | |
Deferred income taxes | | | 823,643 | | | | 539,071 | |
Derivative liabilities | | | 47,763 | | | | 95,256 | |
Production Participation Plan liability | | | 80,659 | | | | 81,524 | |
Asset retirement obligations | | | 61,984 | | | | 76,994 | |
Deferred gain on sale | | | 29,619 | | | | 41,460 | |
| Other long-term liabilities | | | 25,776 | | | | 23,952 | |
Total liabilities | | | 3,016,478 | | | | 2,117,462 | |
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, 2011 and 172,500 issued and outstanding as of December 31, 2010, aggregate liquidation preference of $17,239,100 at December 31, 2011 | | | - | | | | - | |
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011, 117,967,876 issued and 117,098,506 outstanding as of December 31, 2010 (1) | | | 118 | | | | 59 | |
Additional paid-in capital | | | 1,554,223 | | | | 1,549,822 | |
Accumulated other comprehensive income | | | 240 | | | | 5,768 | |
Retained earnings | | | 1,466,276 | | | | 975,666 | |
Total Whiting shareholders’ equity | | | 3,020,857 | | | | 2,531,315 | |
Noncontrolling interest | | | 8,274 | | | | - | |
Total equity | | | 3,029,131 | | | | 2,531,315 | |
| | | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 6,045,609 | | | $ | 4,648,777 | |
| (1) | All common share amounts (except par value and par value per share amounts) have been retroactively restated as of December 31, 2010 to reflect the Company’s two-for-one stock split in February 2011. |
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
| | | Three Months Ended December 31, | | | Twelve Months Ended December 31, | |
| | | | | | | | | | | | | |
| REVENUES AND OTHER INCOME: | | | | | | | | | | | | |
Oil and natural gas sales | | $ | 492,025 | | | $ | 406,327 | | | $ | 1,860,146 | | | $ | 1,475,288 | |
Gain on hedging activities | | | 1,432 | | | | 3,558 | | | | 8,758 | | | | 23,198 | |
| Amortization of deferred gain on sale | | | 3,482 | | | | 4,000 | | | | 13,937 | | | | 15,613 | |
Gain (loss) on sale of properties | | | 1,581 | | | | (530 | ) | | | 16,313 | | | | 1,388 | |
Interest income and other | | | 117 | | | | 114 | | | | 468 | | | | 612 | |
Total revenues and other income | | | 498,637 | | | | 413,469 | | | | 1,899,622 | | | | 1,516,099 | |
| COSTS AND EXPENSES: | | | | | | | | | | | | | | | | |
Lease operating | | | 82,550 | | | | 70,762 | | | | 305,487 | | | | 268,348 | |
Production taxes | | | 38,778 | | | | 26,539 | | | | 139,190 | | | | 103,880 | |
| Depreciation, depletion and amortization | | | 127,335 | | | | 104,061 | | | | 468,203 | | | | 393,897 | |
Exploration and impairment | | | 23,318 | | | | 21,456 | | | | 84,644 | | | | 59,371 | |
General and administrative | | | 22,515 | | | | 16,178 | | | | 84,985 | | | | 64,694 | |
Interest expense | | | 16,649 | | | | 13,175 | | | | 62,516 | | | | 59,078 | |
| Loss on early extinguishment of debt | | | - | | | | - | | | | - | | | | 6,235 | |
| Change in Production Participation Plan liability | | | (3,925 | ) | | | 2,541 | | | | (865 | ) | | | 12,091 | |
| Commodity derivative (gain) loss, net | | | 93,214 | | | | 53,717 | | | | (24,857 | ) | | | 7,062 | |
Total costs and expenses | | | 400,434 | | | | 308,429 | | | | 1,119,303 | | | | 974,656 | |
INCOME BEFORE INCOME TAXES | | | 98,203 | | | | 105,040 | | | | 780,319 | | | | 541,443 | |
| INCOME TAX EXPENSE (BENEFIT): | | | | | | | | | | | | | | | | |
Current | | | (737 | ) | | | (1,489 | ) | | | 3,853 | | | | 4,979 | |
Deferred | | | 36,110 | | | | 40,335 | | | | 284,838 | | | | 199,811 | |
| Total income tax expense (benefit) | | | 35,373 | | | | 38,846 | | | | 288,691 | | | | 204,790 | |
NET INCOME | | | 62,830 | | | | 66,194 | | | | 491,628 | | | | 336,653 | |
| Net loss attributable to noncontrolling interest | | | 59 | | | | - | | | | 59 | | | | - | |
| NET INCOME AVAILABLE TO SHAREHOLDERS | | | 62,889 | | | | 66,194 | | | | 491,687 | | | | 336,653 | |
| Preferred stock dividends and inducement premium | | | (269 | ) | | | (269 | ) | | | (1,077 | ) | | | (63,970 | ) |
| NET INCOME AVAILABLE TO COMMON SHAREHOLDERS | | $ | 62,620 | | | $ | 65,925 | | | $ | 490,610 | | | $ | 272,683 | |
EARNINGS PER COMMON SHARE (1): | | | | | | | | | | | | | | | | |
Basic | | $ | 0.54 | | | $ | 0.56 | | | $ | 4.18 | | | $ | 2.57 | |
Diluted | | $ | 0.53 | | | $ | 0.56 | | | $ | 4.14 | | | $ | 2.55 | |
WEIGHTED AVERAGE SHARES OUTSTANDING (1): | | | | | | | | | | | | | | | | |
Basic | | | 117,381 | | | | 117,098 | | | | 117,345 | | | | 106,338 | |
Diluted | | | 118,644 | | | | 118,564 | | | | 118,668 | | | | 107,846 | |
| (1) | All common share amounts have been retroactively restated as of 2010 periodsto reflect the Company’s two-for-one stock split in February 2011. |
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)
| | | | | | | |
| | | | | | | |
| | | | | | | | | | | | | |
Net Income Available to Common Shareholders | | $ | 62,620 | | | $ | 65,925 | | | $ | 490,610 | | | $ | 272,683 | |
| | | | | | | | | | | | | | | | | |
Cash Premium on Induced Conversion | | | - | | | | - | | | | - | | | | 47,529 | |
| Adjustments Net of Tax: | | | | | | | | | | | | | | | | |
Amortization of Deferred Gain on Sale | | | (2,227 | ) | | | (2,521 | ) | | | (8,781 | ) | | | (9,708 | ) |
(Gain) Loss on Sale of Properties | | | (1,012 | ) | | | 334 | | | | (10,278 | ) | | | (863 | ) |
Impairment Expense | | | 8,869 | | | | 9,119 | | | | 24,435 | | | | 16,492 | |
Loss on Early Extinguishment of Debt | | | - | | | | - | | | | - | | | | 3,877 | |
Unrealized Derivative (Gains) Losses | | | 56,273 | | | | 26,137 | | | | (39,751 | ) | | | (25,329 | ) |
Adjusted Net Income (1) | | $ | 124,523 | | | $ | 98,994 | | | $ | 456,235 | | | $ | 304,681 | |
| | | | | | | | | | | | | | | | | |
Adjusted Net Income Available to Common Shareholders per Share, Basic (2) | | $ | 1.06 | | | $ | 0.85 | | | $ | 3.89 | | | $ | 2.99 | |
Adjusted Net Income Available to Common Shareholders per Share, Diluted (2) | | $ | 1.05 | | | $ | 0.84 | | | $ | 3.85 | | | $ | 2.71 | |
| (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 US GAAP and may not be comparable to other similarly titled measures of other companies. |
| (2) | All per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011. |
WHITING PETROLEUM CORPORATION
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(In thousands)
| | | Three Months Ended | |
| | | | |
| | | | | | | |
Net cash provided by operating activities | | $ | 328,329 | | | $ | 277,022 | |
Exploration | | | 9,455 | | | | 6,985 | |
Exploratory dry hole costs | | | (210 | ) | | | (1,023 | ) |
Changes in working capital | | | (8,496 | ) | | | (5,555 | ) |
Preferred stock dividends paid | | | (269 | ) | | | (269 | ) |
Discretionary cash flow (1) | | $ | 328,809 | | | $ | 277,160 | |
| | | Twelve Months Ended | |
| | | | |
| | | | | | | |
Net cash provided by operating activities | | $ | 1,192,083 | | | $ | 997,289 | |
Exploration | | | 45,861 | | | | 32,846 | |
Exploratory dry hole costs | | | (4,924 | ) | | | (3,819 | ) |
Changes in working capital | | | 10,762 | | | | (60,545 | ) |
Preferred stock dividends paid | | | (1,077 | ) | | | (16,441 | ) |
Discretionary cash flow (1) | | $ | 1,242,705 | | | $ | 949,330 | |
| (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, loss on early extinguishment of debt, 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, not including the preferred stock inducement premium. 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 US GAAP and may not be comparable to other similarly titled measures of other companies. |
WHITING PETROLEUM CORPORATION
Finding Cost and Reserve Replacement Schedule
12/31/11 (1)
(In thousands)
| | | | | | | | | | | | Three Years | |
| | | | | | | | | | | | | 2009-2011 | |
| | | 2009 | | | 2010 | | | 2011 | | | Total/Avg. | |
| Proved Acquisition | | $ | 78,800 | | | $ | 22,763 | | | $ | 4,324 | | | $ | 105,887 | |
| Unproved Acquisition | | $ | 12,872 | | | $ | 155,472 | | | $ | 191,482 | | | $ | 359,826 | |
| Development Cost | | $ | 436,721 | | | $ | 723,687 | | | $ | 1,245,150 | | | $ | 2,405,558 | |
| Exploration Cost | | $ | 50,970 | | | $ | 114,012 | | | $ | 400,823 | | | $ | 565,805 | |
| Total | | $ | 579,363 | | | $ | 1,015,934 | | | $ | 1,841,779 | | | $ | 3,437,076 | |
| | | | | | | | | | | | | | | | | |
| Acquisition Reserves | | | | | | | | | | | | | | | | |
| Acquisition Res. – Oil (MBbl) | | | 3,177 | | | | 505 | | | | 172 | | | | 3,854 | |
| Acquisition Res. – Gas (MMcf) | | | 4,155 | | | | 1,526 | | | | 1,639 | | | | 7,320 | |
| Total – Aqu. Res. – MBOE | | | 3,870 | | | | 759 | | | | 445 | | | | 5,074 | |
| | | | | | | | | | | | | | | | | |
| Development Reserves | | | | | | | | | | | | | | | | |
| Development Res. – Oil (MBbl) | | | 25,115 | | | | 29,434 | | | | 44,684 | | | | 99,233 | |
| Development Res. – Gas (MMcf) | | | 41,969 | | | | 23,135 | | | | 23,211 | | | | 88,315 | |
| Total – Dev. Res. – MBOE | | | 32,109 | | | | 33,290 | | | | 48,553 | | | | 113,952 | |
| | | | | | | | | | | | | | | | | |
| Revisions | | | | | | | | | | | | | | | | |
| Reserve Revisions – Oil (MBbl) | | | 33,566 | | | | 19,799 | | | | 20,203 | | | | 73,568 | |
| Reserve Revisions – Gas (MMcf) | | | (62,618 | ) | | | (618 | ) | | | (7,217 | ) | | | (70,453 | ) |
| Total - Reserve Rev. – MBOE | | | 23,130 | | | | 19,695 | | | | 19,000 | | | | 61,825 | |
| | | | | | | | | | | | | | | | | |
| Cost Per BOE to Acquire | | $ | 20.36 | | | $ | 29.98 | | | $ | 9.71 | | | $ | 20.87 | |
| Cost Per BOE to Develop | | $ | 9.06 | | | $ | 18.74 | | | $ | 27.20 | | | $ | 18.95 | |
| All-in Finding Cost per BOE | | $ | 9.80 | | | $ | 18.90 | | | $ | 27.09 | | | $ | 19.01 | |
| | | | | | | | | | | | | | | | | |
| FUTURE DEVELOPMENT COSTS | | | | | | | | | | | | | | | | |
Proved Undeveloped CapEx (1) | | | $ | 1,982,813 | |
Proved Undeveloped Reserves - MBOE (1) | | | | 106,949 | |
| | | | | | | | | | | | | | | $ | 18.54 | |
| | | | | | | | | | | | | | | | | |
Probable and Possible CapEx (1) | | | $ | 4,265,947 | |
Probable and Possible Reserves – MBOE (1) | | | | 301,235 | |
All-In Rate with Future Development Cost and Prob. and Poss. (1) | | | $ | 14.16 | |
| | | | | | | | | | | | | | | | | |
| RESERVE REPLACEMENT | | | | | | | | | | | | | | | | |
| Acquisition Reserves | | | 3,870 | | | | 759 | | | | 445 | | | | 5,074 | |
| Development Reserves | | | 32,109 | | | | 33,290 | | | | 48,553 | | | | 113,952 | |
| Reserve Revisions | | | 23,130 | | | | 19,695 | | | | 19,000 | | | | 61,825 | |
| Total New Reserves – MBOE | | | 59,109 | | | | 53,744 | | | | 67,998 | | | | 180,851 | |
| | | | | | | | | | | | | | | | | |
| Production (MBOE) | | | 20,269 | | | | 23,596 | | | | 24,780 | | | | 68,645 | |
| Reserve Replacement % | | | 292 | % | | | 228 | % | | | 274 | % | | | 263 | % |
| (1) | See “Disclosure Regarding Reserves and Resources” earlier in this news release. |
