Attached files
| file | filename |
|---|---|
| 8-K - WHITING PETROLEUM FORM 8-K, DATED APRIL 30, 2014 - WHITING PETROLEUM CORP | form8-k.htm |
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Company contact:
|
John B. Kelso, Director of Investor Relations
|
|
303.837.1661 or john.kelso@whiting.com
|
Whiting Petroleum Corporation Announces
First Quarter 2014 Financial and Operating Results
Production Reaches 100,065 BOE/d in Q1 2014; Record Williston Basin
Production of 73,325 BOE/d in Q1 2014 Up 27% Over Q1 2013
Q1 2014 Net Income Available to Common Shareholders of $109.1 Million
or $0.91 per Diluted Share and Adjusted Net Income of $126.2 Million or
$1.05 per Diluted Share
Q1 2014 Discretionary Cash Flow Totals a Record $482.0 Million
Redtail Niobrara Production of 4,550 BOE/d in Q1 2014
Up 41% Over Q4 2013
DENVER – April 30, 2014 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the first quarter of 2014 totaled 9.0 million barrels of oil equivalent (MMBOE), of which 88% was crude oil/natural gas liquids (NGLs). This first quarter 2014 production total equates to an average production rate of 100,065 barrels of oil equivalent per day (BOE/d) and produced record discretionary cash flow for the quarter.
James J. Volker, Whiting’s Chairman and CEO, commented, “Our North Dakota, Colorado and Texas teams overcame one of the most severe winters on record so that we met all of our guidance numbers in the first quarter. Recently, at our Missouri Breaks field our new completion design that better isolates the perforations to fracture the reservoir produced an initial production rate from the newest well 40% to 70% higher than our earlier wells. We also achieved our best well result to date at our Cassandra field with the completion of the Kaldahl 11-3H flowing 1,930 BOE/d on April 1, 2014 using a cemented liner.
“We also continue to streamline our asset base. We sold our remaining interests in the Big Tex prospect for $76 million. In total, we received $227 million for the two Big Tex asset sales or $3,100 per net acre and were pleased with this price given the light amount of drilling across this acreage.” Mr. Volker added, “We began selling gas at our Redtail field in mid-April as our gas plant there came on stream and the current gross inlet rate is over 8 MMcf per day. With the plant processing gas, we will generate new gas and plant product income streams and increase our net BOE daily production while being environmentally responsible by capturing and processing our gas.”
Operating and Financial Results
The following table summarizes the first quarter operating and financial results for 2014 and 2013:
|
Three Months Ended
March 31,
|
|||||||||||
|
2014
|
2013
|
Change
|
|||||||||
|
Production (MBOE/d)
|
100.07 | 89.14 | 12% | ||||||||
|
Discretionary Cash Flow-MM (1)
|
$ | 482.0 | $ | 401.1 | 20% | ||||||
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Realized Price ($/BOE)
|
$ | 80.00 | $ | 74.77 | 7% | ||||||
|
Total Revenues-MM
|
$ | 740.2 | $ | 613.4 | 21% | ||||||
|
Net Income Available to Common Shareholders-MM
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$ | 109.1 | $ | 86.0 | 27% | ||||||
|
Per Basic Share
|
$ | 0.92 | $ | 0.73 | 26% | ||||||
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Per Diluted Share
|
$ | 0.91 | $ | 0.72 | 26% | ||||||
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Adjusted Net Income Available to Common Shareholders-MM (2)
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$ | 126.2 | $ | 111.6 | 13% | ||||||
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Per Basic Share
|
$ | 1.06 | $ | 0.95 | 12% | ||||||
|
Per Diluted Share
|
$ | 1.05 | $ | 0.94 | 12% | ||||||
|
(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.
|
Operational Highlights
Core Development Areas
Williston Basin Development
In the first quarter of 2014, production from the Williston Basin averaged a record 73,325 BOE/d, an increase of 27% over the 57,785 BOE/d in the first quarter of 2013. The Williston Basin represented 73% of Whiting’s total first quarter production.
Missouri Breaks Field. We hold 99,930 gross (65,869 net) acres in the Missouri Breaks field, located in Richland County, Montana and McKenzie County, North Dakota. At our Skov 31-28 Unit at Missouri Breaks, we drilled three new Bakken wells in order to compare different completion designs. These wells used 3.0 to 4.0 million pounds of frac sand versus approximately 2.0 million pounds in wells completed using our prior method.
2
The original well in the unit, the Skov 31-28-1H, was completed using sliding sleeve technology on May 31, 2013 and flowed 927 BOE/d. On April 2, 2014, we completed two new wells in the unit using our new cemented liner method with an increased number of entry points. These wells, the Skov 31-28-2H and the Skov 31-28-4H, flowed at 1,072 BOE/d and 1,219 BOE/d, respectively. On April 1, 2014, we completed the Skov 31-28-3H with a new coiled tubing fracture stimulation method. This well flowed at 1,607 BOE/d, 73% higher than the initial well in the unit and 40% higher than the average of the two cemented liner wells. This new completion design better isolates the perforations to more effectively fracture the reservoir with fewer entry points. The following table summarizes our improving results:
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Well Name
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Method
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IP Date
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Entry Points
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Rate (BOE/d)
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||||
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Skov 31-28-1H (Original Well)
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Sliding Sleeve
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5/31/2013
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30
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927
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||||
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Skov 31-28-2H (New Well)
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Cemented Liner
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4/2/2014
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90
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1,072
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||||
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Skov 31-28-4H (New Well)
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Cemented Liner
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4/2/2014
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150
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1,219
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||||
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Skov 31-28-3H (New Well)
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Coiled Tubing Frac
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4/1/2014
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85
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1,607
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Hidden Bench Field. We hold 65,882 gross (37,314 net) acres in the Hidden Bench field, located in McKenzie County, North Dakota. Our cemented liner completion method has produced strong results. The 15 wells completed using this method had an average IP rate of 2,643 BOE/d.
Based on strong initial results from our high density pilot at Hidden Bench, we plan to commence a development drilling program on an eight-well per drilling spacing unit (DSU) pattern in the Middle Bakken versus our original development plan of four wells per 1,280-acre spacing unit.
Cassandra Field. We hold 29,827 gross (13,949 net) acres in the Cassandra field, located in Williams County, North Dakota. We utilized our cemented liner completion method on three recent wells. The Kaldahl 11-3H was completed in the Middle Bakken on April 1, 2014 flowing 1,930 BOE/d, 104% higher than the 10 prior wells completed in the Middle Bakken formation. The Olson 14-31TFH was completed in the Three Forks formation on March 14, 2014 flowing 1,375 BOE/d. The Sheldon 11-6 TFH was completed in the Three Forks on March 15, 2014 flowing 1,243 BOE/d. These wells produced at average initial rates 38% higher than the 10 prior wells completed in the Middle Bakken formation.
Sanish Field Area. We hold 174,666 gross (82,445 net) acres in the Sanish field area, which includes the Company’s interests in the Parshall field, located in Mountrail County, North Dakota. Based on strong initial results from our high density pilots, we plan to commence a development drilling program on a nine-well per DSU pattern in the Middle Bakken versus our original development plan of three to four wells per 1,280-acre spacing unit.
3
Denver Julesberg Basin Development
Redtail Niobrara Field. We hold a total of 174,892 gross (122,656 net) acres in our Redtail prospect, located in the Denver Julesberg Basin in Weld County, Colorado. Our Redtail acreage currently produces from both the Niobrara “B” and “A” zones and is also prospective in the Niobrara “C” zone as well as the Codell formation. We estimate that we have more than 3,300 gross locations to drill at Redtail based on a 16-well per DSU pattern in the “B” and “A” zones alone.
Production from our Redtail field averaged 4,550 BOE/d in the first quarter of 2014, representing a sequential increase of 41% over the fourth quarter of 2013.
Highlighting recent activity at our Redtail field was the initiation of gas sales from our Redtail gas plant. The plant has initial inlet capacity of 20 MMcf/d, which will be expanded to 70 MMcf/d in the first quarter of 2015. Gas sales are underway at a current gross inlet rate of over 8 MMcf/d.
Drilling to date is on a 16-well per 960-acre DSU pattern in the “B” and “A” zones and we expect our rate of completions to rise in the second quarter of 2014. We plan to spud our 30F super pad located in the Horsetail township in May 2014. This high density pilot will test a 32-well per DSU pattern in the “A”, “B” and “C” zones. If successful, our potential drilling locations at Redtail would increase to more than 6,600 gross wells.
We currently have three pad-capable drilling rigs running at Redtail, and we plan to add a fourth rig in the second half of 2014. This rig will initially drill in the northern portion of our acreage where we plan to test the Niobrara “A” zone and the Codell formation.
4
Operated Drilling Rig Count
As of April 15, 2014, 18 operated drilling rigs were active on our properties. The breakdown of our operated rigs as of April 15, 2014 was as follows:
|
Area
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Drilling Rigs
|
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Northern Rockies
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14 |
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Central Rockies
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3 |
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North Ward Estes
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1 |
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Total
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18 |
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended March 31, 2014 and 2013:
|
Three Months Ended
|
|||||||||||
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March 31,
|
|||||||||||
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Production
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2014
|
2013
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Change
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||||||||
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Oil (MMBbl)
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7.24 | 6.25 | 16% | ||||||||
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NGLs (MMBbl)
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0.65 | 0.71 | (9%) | ||||||||
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Natural gas (Bcf)
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6.70 | 6.37 | 5% | ||||||||
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Total equivalent (MMBOE)
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9.00 | 8.02 | 12% | ||||||||
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Average sales price
|
|||||||||||
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Oil (per Bbl):
|
|||||||||||
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Price received
|
$ | 88.85 | $ | 88.11 | 1% | ||||||
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Effect of crude oil hedging
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(0.10 | )(1) | (0.85 | ) (1) | |||||||
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Realized price
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$ | 88.75 | $ | 87.26 | 2% | ||||||
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NYMEX
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$ | 98.62 | $ | 94.34 | 5% | ||||||
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NGLs (per Bbl):
|
|||||||||||
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Realized price
|
$ | 52.95 | $ | 42.56 | 24% | ||||||
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Natural gas (per Mcf):
|
|||||||||||
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Realized price
|
$ | 6.50 | $ | 3.80 | 71% | ||||||
|
NYMEX
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$ | 4.93 | $ | 3.34 | 48% | ||||||
|
(1)
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Whiting paid $0.7 million and $5.3 million in pre-tax cash settlements on its crude oil and natural gas hedges during the first quarter of 2014 and 2013, respectively. A summary of Whiting’s outstanding hedges is included later in this news release.
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5
First Quarter 2014 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
|
Three Months Ended
|
||||||||
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March 31,
|
||||||||
|
2014
|
2013
|
|||||||
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(Per BOE, Except Production)
|
||||||||
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Production (MMBOE)
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9.00 | 8.02 | ||||||
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Sales price, net of hedging
|
$ | 80.00 | $ | 74.77 | ||||
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Lease operating expense
|
12.75 | 12.45 | ||||||
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Production tax
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6.67 | 6.39 | ||||||
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General & administrative
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3.59 | 3.60 | ||||||
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Exploration
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2.68 | 2.35 | ||||||
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Cash interest expense
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4.08 | 2.37 | ||||||
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Cash income tax expense
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0.11 | 0.05 | ||||||
| $ | 50.12 | $ | 47.56 | |||||
First Quarter 2014 Drilling and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three months ended March 31, 2014:
|
Gross/Net Wells Completed
|
||||||||||||
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Total New
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% Success
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CAPEX
|
||||||||||
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Producing
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Non-Producing
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Drilling
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Rate
|
(in MM)
|
||||||||
| Q1 14 | 143 / 53.3 | 2 / 1.2 | 145 / 54.5 | 99% / 98% | $ | 683.4 | (1) | |||||
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(1)
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Includes $30 million for land and $41 million for facilities.
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Outlook for Second Quarter and Full-Year 2014
The following table provides guidance for the second quarter and full-year 2014 based on current forecasts, including Whiting’s full-year 2014 capital budget of $2,700.0 million:
| Guidance | ||||||||||||||||||||
| Second Quarter |
Full-Year
|
|||||||||||||||||||
| 2014 |
2014
|
|||||||||||||||||||
|
Production (MMBOE)
|
9.70 | - | 9.90 | 40.20 | - | 40.80 | ||||||||||||||
|
Lease operating expense per BOE
|
$ | 12.25 | - | $ | 12.75 | $ | 12.20 | - | $ | 12.60 | ||||||||||
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General and admin. expense per BOE
|
$ | 3.30 | - | $ | 3.70 | $ | 3.25 | - | $ | 3.55 | ||||||||||
|
Interest expense per BOE
|
$ | 3.80 | - | $ | 4.20 | $ | 3.75 | - | $ | 4.15 | ||||||||||
|
Depr., depletion and amort. per BOE
|
$ | 25.75 | - | $ | 26.75 | $ | 25.60 | - | $ | 26.20 | ||||||||||
|
Prod. taxes (% of sales revenue)
|
8.35% | - | 8.55% | 8.35% | - | 8.55% | ||||||||||||||
|
Oil price differentials to NYMEX per Bbl(1)
|
( | $ | 9.00 | ) | - | ( | $ | 11.00 | ) | ( | $ | 8.50 | ) | - | ( | $ | 10.50 | ) | ||
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Gas price premium to NYMEX per Mcf(2)
|
$ | 0.50 | - | $ | 1.00 | $ | 0.60 | - | $ | 1.10 | ||||||||||
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(1)
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Does not include the effect of NGLs.
|
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(2)
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Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
|
6
Commodity Derivative Contracts
The following summarizes Whiting’s crude oil hedges as of April 1, 2014:
|
Weighted Average
|
As a Percentage of
|
|||||||
|
Derivative
|
Hedge
|
Contracted Volume
|
NYMEX Price
|
March 2014
|
||||
|
Instrument
|
Period
|
(Bbls per Month)
|
(per Bbl)
|
Oil Production
|
||||
|
Three-way collars(1)
|
2014
|
|||||||
|
Q2
|
1,380,000
|
$ 71.23 - $ 85.36 - $ 103.54
|
53%
|
|||||
|
Q3
|
1,380,000
|
$ 71.23 - $ 85.36 - $ 103.54
|
53%
|
|||||
|
Q4
|
1,380,000
|
$ 71.23 - $ 85.36 - $ 103.54
|
53%
|
|||||
|
Collars
|
2014
|
|||||||
|
Q2
|
4,150
|
$ 80.00 - $ 122.50
|
<1%
|
|||||
|
Q3
|
4,060
|
$ 80.00 - $ 122.50
|
<1%
|
|||||
|
Q4
|
3,970
|
$ 80.00 - $ 122.50
|
<1%
|
|
(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.
|
The following summarizes Whiting’s fixed-price natural gas contracts as of April 1, 2014:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
March 2014
|
|||
|
Period
|
(MMBtu per Day)
|
(per MMBtu)
|
Gas Production
|
|||
|
2014
|
||||||
|
Q2
|
11,000
|
$5.49
|
14%
|
|||
|
Q3
|
11,000
|
$5.49
|
14%
|
|||
|
Q4
|
11,000
|
$5.49
|
14%
|
Whiting also has the following fixed-differential crude oil sales contracts in place as of April 1, 2014:
|
Differential
|
As a Percentage of
|
|||||
|
Contracted Volume
|
from NYMEX
|
March 2014
|
||||
|
Period
|
(Bbls per Day)
|
(per Bbl)
|
Oil Production
|
|||
|
2015
|
25,000
|
$4.75
|
29%
|
|||
|
2016
|
30,000
|
$4.75
|
35%
|
|||
|
2017
|
35,000
|
$4.75
|
41%
|
|||
|
2018
|
40,000
|
$4.75
|
47%
|
|||
|
2019
|
45,000
|
$4.75
|
53%
|
7
Selected Operating and Financial Statistics
|
Three Months Ended
March 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
Selected operating statistics:
|
||||||||
|
Production
|
||||||||
|
Oil, MBbl
|
7,241 | 6,250 | ||||||
|
NGLs, MBbl
|
648 | 710 | ||||||
|
Natural gas, MMcf
|
6,702 | 6,371 | ||||||
|
Oil equivalents, MBOE
|
9,006 | 8,022 | ||||||
|
Average prices
|
||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 88.85 | $ | 88.11 | ||||
|
NGLs per Bbl
|
$ | 52.95 | $ | 42.56 | ||||
|
Natural gas per Mcf
|
$ | 6.50 | $ | 3.80 | ||||
|
Per BOE data
|
||||||||
|
Sales price (including hedging)
|
$ | 80.00 | $ | 74.77 | ||||
|
Lease operating
|
$ | 12.75 | $ | 12.45 | ||||
|
Production taxes
|
$ | 6.67 | $ | 6.39 | ||||
|
Depreciation, depletion and amortization
|
$ | 26.12 | $ | 25.08 | ||||
|
General and administrative
|
$ | 3.59 | $ | 3.60 | ||||
|
Selected financial data:
(In thousands, except per share data)
|
||||||||
|
Total revenues and other income
|
$ | 740,249 | $ | 613,371 | ||||
|
Total costs and expenses
|
$ | 554,837 | $ | 475,607 | ||||
|
Net income available to common shareholders
|
$ | 109,069 | $ | 85,994 | ||||
|
Earnings per common share, basic
|
$ | 0.92 | $ | 0.73 | ||||
|
Earnings per common share, diluted
|
$ | 0.91 | $ | 0.72 | ||||
|
Average shares outstanding, basic
|
118,923 | 117,788 | ||||||
|
Average shares outstanding, diluted
|
119,931 | 119,263 | ||||||
|
Net cash provided by operating activities
|
$ | 323,897 | $ | 297,614 | ||||
|
Net cash used in investing activities
|
$ | (579,554 | ) | $ | (628,491 | ) | ||
|
Net cash provided by (used in) financing activities
|
$ | (37,366 | ) | $ | 294,259 | |||
8
Selected Financial Data
For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
March 31, 2014
|
December 31, 2013
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 406,437 | $ | 699,460 | ||||
|
Accounts receivable trade, net
|
378,111 | 341,177 | ||||||
|
Prepaid expenses and other
|
38,059 | 28,981 | ||||||
|
Total current assets
|
822,607 | 1,069,618 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method
|
10,642,189 | 10,065,150 | ||||||
|
Other property and equipment
|
225,106 | 206,385 | ||||||
|
Total property and equipment
|
10,867,295 | 10,271,535 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(2,889,910 | ) | (2,676,490 | ) | ||||
|
Total property and equipment, net
|
7,977,385 | 7,595,045 | ||||||
|
Debt issuance costs
|
45,535 | 48,530 | ||||||
|
Other long-term assets
|
136,197 | 120,277 | ||||||
|
TOTAL ASSETS
|
$ | 8,981,724 | $ | 8,833,470 | ||||
9
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
March 31, 2014
|
December 31, 2013
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable trade
|
116,673 | 107,692 | ||||||
|
Accrued capital expenditures
|
210,133 | 158,739 | ||||||
|
Accrued liabilities and other
|
109,607 | 214,109 | ||||||
|
Revenues and royalties payable
|
197,416 | 198,558 | ||||||
|
Taxes payable
|
55,268 | 50,052 | ||||||
|
Accrued interest
|
17,676 | 44,405 | ||||||
|
Derivative liabilities
|
11,799 | 3,482 | ||||||
|
Deferred income taxes
|
8,786 | 648 | ||||||
|
Total current liabilities
|
727,358 | 777,685 | ||||||
|
Long-term debt
|
2,653,674 | 2,653,834 | ||||||
|
Deferred income taxes
|
1,345,253 | 1,278,030 | ||||||
|
Production Participation Plan liability
|
91,139 | 87,503 | ||||||
|
Asset retirement obligations
|
146,188 | 116,442 | ||||||
|
Deferred gain on sale
|
72,250 | 79,065 | ||||||
|
Other long-term liabilities
|
4,365 | 4,212 | ||||||
|
Total liabilities
|
5,040,227 | 4,996,771 | ||||||
|
Commitments and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Common stock, $0.001 par value, 300,000,000 shares authorized; 120,614,246 issued and 118,959,061 outstanding as of March 31, 2014 and 120,101,555 issued and 118,657,245 outstanding as of December 31, 2013
|
121 | 120 | ||||||
|
Additional paid-in capital
|
1,579,288 | 1,583,542 | ||||||
|
Retained earnings
|
2,353,974 | 2,244,905 | ||||||
|
Total Whiting shareholders’ equity
|
3,933,383 | 3,828,567 | ||||||
|
Noncontrolling interest
|
8,114 | 8,132 | ||||||
|
Total equity
|
3,941,497 | 3,836,699 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 8,981,724 | $ | 8,833,470 | ||||
10
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended
March 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
REVENUES AND OTHER INCOME:
|
||||||||
|
Oil, NGL and natural gas sales
|
$ | 721,250 | $ | 605,114 | ||||
|
Loss on hedging activities
|
- | (211 | ) | |||||
|
Amortization of deferred gain on sale
|
7,744 | 7,976 | ||||||
|
Gain on sale of properties
|
10,559 | - | ||||||
|
Interest income and other
|
696 | 492 | ||||||
|
Total revenues and other income
|
740,249 | 613,371 | ||||||
|
COSTS AND EXPENSES:
|
||||||||
|
Lease operating
|
114,786 | 99,878 | ||||||
|
Production taxes
|
60,030 | 51,271 | ||||||
|
Depreciation, depletion and amortization
|
235,265 | 201,159 | ||||||
|
Exploration and impairment
|
42,107 | 37,280 | ||||||
|
General and administrative
|
32,334 | 28,885 | ||||||
|
Interest expense
|
42,144 | 21,470 | ||||||
|
Change in Production Participation Plan liability
|
3,636 | 4,407 | ||||||
|
Commodity derivative loss, net
|
24,535 | 31,257 | ||||||
|
Total costs and expenses
|
554,837 | 475,607 | ||||||
|
INCOME BEFORE INCOME TAXES
|
185,412 | 137,764 | ||||||
|
INCOME TAX EXPENSE:
|
||||||||
|
Current
|
1,000 | 422 | ||||||
|
Deferred
|
75,361 | 51,098 | ||||||
|
Total income tax expense
|
76,361 | 51,520 | ||||||
|
NET INCOME
|
109,051 | 86,244 | ||||||
|
Net loss attributable to noncontrolling interest
|
18 | 19 | ||||||
|
NET INCOME AVAILABLE TO SHAREHOLDERS
|
109,069 | 86,263 | ||||||
|
Preferred stock dividends
|
- | (269 | ) | |||||
|
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 109,069 | $ | 85,994 | ||||
|
EARNINGS PER COMMON SHARE:
|
||||||||
|
Basic
|
$ | 0.92 | $ | 0.73 | ||||
|
Diluted
|
$ | 0.91 | $ | 0.72 | ||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||
|
Basic
|
118,923 | 117,788 | ||||||
|
Diluted
|
119,931 | 119,263 | ||||||
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WHITING PETROLEUM CORPORATION
Reconciliation of Net Income Available to Common Shareholders to
Adjusted Net Income Available to Common Shareholders
(In thousands, except per share data)
|
Three Months Ended
|
||||||||
|
March 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
Net income available to common shareholders
|
$ | 109,069 | $ | 85,994 | ||||
|
Adjustments net of tax:
|
||||||||
|
Amortization of deferred gain on sale
|
(4,883 | ) | (4,993 | ) | ||||
|
Gain on sale of properties
|
(6,658 | ) | (28 | ) | ||||
|
Impairment expense
|
11,341 | 11,528 | ||||||
|
Change in Production Participation Plan liability
|
2,293 | 2,759 | ||||||
|
Total measure of derivative loss reported under U.S. GAAP
|
15,472 | 19,700 | ||||||
|
Total net cash settlements paid on commodity derivatives during the period
|
(468 | ) | (3,320 | ) | ||||
|
Adjusted net income (1)
|
$ | 126,166 | $ | 111,640 | ||||
|
Adjusted net income available to common shareholders per share, basic
|
$ | 1.06 | $ | 0.95 | ||||
|
Adjusted net income available to common shareholders per share, diluted
|
$ | 1.05 | $ | 0.94 | ||||
|
(1)
|
Adjusted Net Income Available to Common Shareholders is a non-GAAP financial measure. Management believes it provides useful information to investors for analysis of Whiting’s fundamental business on a recurring basis. In addition, management believes that Adjusted Net Income Available to Common Shareholders is widely used by professional research analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted Net Income Available for Common Shareholders should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
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WHITING PETROLEUM CORPORATION
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(In thousands)
|
Three Months Ended
|
||||||||
|
March 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
Net cash provided by operating activities
|
$ | 323,897 | $ | 297,614 | ||||
|
Exploration
|
24,122 | 18,866 | ||||||
|
Exploratory dry hole costs
|
(3,552 | ) | - | |||||
|
Changes in working capital
|
137,494 | 84,859 | ||||||
|
Preferred stock dividends paid
|
- | (269 | ) | |||||
|
Discretionary cash flow (1)
|
$ | 481,961 | $ | 401,070 | ||||
|
(1)
|
Discretionary cash flow is a non-GAAP measure. Discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
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Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, May 1, 2014 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s first quarter 2014 financial and operating results. Please call (866) 318-8618 (U.S./Canada) or (617) 399-5137 (International) to be connected to the call and enter the pass code 43163055. Access to a live internet broadcast will be available at http://www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EDT) on May 1, 2014.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, May 1, 2014 and continuing through Thursday, May 8, 2014. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 71525583. You may also access a web archive at http://www.whiting.com beginning approximately one hour after the conference call.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, natural gas and natural gas liquids primarily in the Rocky Mountain and Permian Basin regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota, the Niobrara play in northeast Colorado and its Enhanced Oil Recovery field in Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit http://www.whiting.com.
Forward-Looking Statements
This news release contains statements that we believe to be “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. 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.
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These risks and uncertainties include, but are not limited to: declines in oil, NGL or natural gas prices; our level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; our ability to obtain sufficient quantities of CO2 necessary to carry out our enhanced oil recovery projects; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write downs; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal Government that could have a negative effect on the oil and gas industry; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions and the risks related thereto; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
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