Whiting Petroleum announces fourth quarter and full-year 2012 financial and operating results

Thursday, February 28, 2013      
 
  • 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.
  • 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.

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.

Operating and Financial Results

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The following table summarizes the fourth quarter operating and financial results for 2012 and 2011:

Three Months Ended December 31,
2012
2011
Change
Production (MBOE/d) 86.06 70.69 22 %
Discretionary Cash Flow-MM$ (1) 381.7 328.8 16 %
Realized Price ($/BOE) 71.09 75.07 (5 ) %
Total Revenues-MM$ 577.1 498.6 16 %
Net Income Available to Common Shareholders-MM$ 81.4 62.6 30 %
Per Basic Share $0.69 $0.54 28 %
Per Diluted Share $0.69 $0.53 30 %
Adjusted Net Income Available to Common Shareholders-MM$ (2) 97.9 124.5 (21 ) %
Per Basic Share $0.83 $1.06 (22 ) %
Per Diluted Share $0.83 $1.05 (21 ) %
Twelve Months Ended December 31,
2012
2011
Change
Production (MBOE/d) 82.54 67.89 22 %
Discretionary Cash Flow-MM$ (1) 1,387.5 1,242.7 12 %
Realized Price ($/BOE) 69.85 73.88 (5 ) %
Total Revenues-MM$ 2,173.5 1,899.6 14 %
Net Income Available to Common Shareholders-MM$ 413.1 490.6 (16 ) %
Per Basic Share $3.51 $4.18 (16 ) %
Per Diluted Share $3.48 $4.14 (16 ) %
Adjusted Net Income Available to Common Shareholders-MM$ (2) 393.5 456.2 (14 ) %
Per Basic Share $3.35 $3.89 (14 ) %
Per Diluted Share $3.31 $3.85 (14 ) %

(1) A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.
(2) 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, 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.

The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2012:

Oil (MBbl)


NGLs

(MBbl)
Natural

Gas

(MMcf)
Total (MBOE)
Balance – December 31, 2011 260,144 37,609 284,975 345,249
Extensions and discoveries 68,134 6,526 40,915 81,479
Sales of minerals in place (7,960 ) (320 ) (13,987 ) (10,611 )
Production (23,139 ) (2,766 ) (25,827 ) (30,209 )
Revisions to previous estimates 4,106 (951 ) (61,812 ) (7,148 )
Balance – December 31, 2012 301,285 40,098 224,264 378,760


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.

The following table summarizes our proved, probable and possible reserves:

3P Reserves (1)
Pre-Tax
Natural PV10%
Oil NGLS Gas Total % Value % of
(MMBbl)
(MMBbl)
(Bcf)
(MMBOE)
Oil
(In MM)
Total
Proved 301.3 40.1 224.3 378.8 80% $7,284(2) 73%
Probable 85.0 11.9 109.6 115.2 74% $1,262(3) 13%
Possible 123.2 21.9 156.4 171.2 72% $1,359(3) 14%

(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, 2012, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $94.71/Bbl and $2.76/MMBtu.
(2) 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.
(3) 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.

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.

The following table summarizes our potential gross and net drilling locations by core area:

Identified Primary Locations
Northern Rockies Gross
Net
Wells per Spacing Unit
Southern Williston (Lewis & Clark; Pronghorn) 1,104 410.2 3 Pronghorn Sand / 1280
Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks) 1,174 380.5 4 Middle BKN; 3 Upper TFK / 1280
Sanish (Sanish; Parshall) (2) 260 118.1 3.5 Middle BKN; 3 Upper TFK / 1280
Other (3) 588 340.3
Total 3,126 1,249.1
Central Rockies
Redtail Niobrara 2,420 1,215.7 8 Nio "B"; 4 Nio "A" / 640 - 960
Other (4) 958 654.1
Total 3,378 1,869.8
Gulf Coast 131 98.1
Mid-Cont 41 33.7
Permian Basin (5) 817 319.3
Michigan 63 53.3
Total Primary Inventory 7,556 3,623.3
Identified Prospective Locations
Williston Basin
Williston Basin New Objectives Gross
Net
Wells per Spacing Unit
Missouri Breaks Upper Three Forks 321 102.8 3 Upper TFK / 1280
Hidden Bench Lower Bakken Silt / Higher Density Pilot 556 161.9 4 BKN Silt; 4 Middle BKN per 1280
Cassandra Lower Three Forks 120 40.0 4 Lower TFK per 1280
Tarpon Lower Three Forks 40 15.0 3 Lower TFK per 1280
Total 1,037 319.7
Williston Basin Higher Density Locations
Pronghorn Sand Higher Density 453 167.3 3 Add'l Pronghorn Sand / 1280
Sanish Higher Density and Infill 191 175.9 3 Add'l Middle BKN / 1280
Total 644 343.2
Williston Basin Total Prospective Locations 1,681 662.9
Permian Basin
Big Tex Horizontal 424 217.0 6 Upper Wolfcamp / 640
Total Prospective Inventory 2,105 879.9
Total Potential Locations (6) 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.
(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.
(3)
Various fields in North Dakota and Montana, including Big Island, Starbuck, Big Stick and others.
(4)
Various fields in Colorado, Wyoming and Utah including Sulphur Creek, Fontenelle, Nitchie Gulch, Flat Rock and others.
(5)
Various fields in Texas and New Mexico including Jo-Mill, West Jo-Mill, Garza, Signal Peak and others.
(6)
Locations include both 3P reserves and Resource Potential.

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:

2013
CAPEX Gross Net
(MM)
Wells
Wells
% of Total
Northern Rockies $1,142
219 148 52%
EOR 240 NA(2) NA(2) 11%
Central Rockies 136 37 27 6%
Non-Operated 164 7%
Land 108 5%
Exploration (1) 82 4%
Facilities 178 8%
Well Work, Misc. Costs 150 7%
Total Budget $2,200 256 175 100%

(1) Comprised primarily of exploration salaries, seismic activities, delay rentals and exploratory drilling.
(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.


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
30-Day 60-Day 90-Day
Rate
Rate
Rate
2012 572 470 403
2011 432 373 338

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:

Well Name
IP Date
WI%
BOE/d
3J TRUST 44-8PH 11/24/2012 89% 2,696
FROEHLICH 11-28PH 11/27/2012 89% 2,644
MARSH 34-18PH 12/09/2012 65% 2,340
FROEHLICH 21-28PH 11/28/2012 89% 2,301
OBRIGEWITCH 41-17PH 11/24/2012 96% 2,292
FROEHLICH 41-28PH 11/27/2012 89% 2,288
FRANK 14-7PH 11/14/2012 90% 2,165
OBRIGEWITCH 41-16PH 11/27/2012 89% 2,110
Average 87% 2,355

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.

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.

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.

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.

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
Northern Rockies
20
Permian Basin --
Central Rockies 2
EOR Projects:
Postle 1
North Ward Estes 1
Total 24

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.

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 Twelve Months
Ended December 31, Ended 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.

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.


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%

Selected Operating and Financial Statistics
Three Months Ended Twelve Months Ended
December 31, 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.


 

Article Tags

Whiting Petroleum United States North America Finance Operations Update Production Update Fracking Houston Seismic Spud Watch


This article is for information and discussion purposes only and does not form a recommendation to invest or otherwise. The value of an investment may fall. The investments referred to in this article may not be suitable for all investors, and if in doubt, an investor should seek advice from a qualified investment adviser. More


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