Attached files
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| 8-K - WHITING PETROLEUM FORM 8-K, DATED JULY 26, 2017 - WHITING PETROLEUM CORP | wll-20170726x8k.htm |
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1700 Broadway, Suite 2300, Denver, CO 80290-2300 Phone: 303.837.1661 | FAX: 303.861.4023 |
News Release
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Company Contact: Eric K. Hagen |
July 26, 2017 |
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Title: Vice President, Investor Relations |
For immediate release |
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Phone: 303-837-1661 |
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Email: Eric.Hagen@whiting.com |
Whiting Petroleum Corporation Announces Second Quarter 2017
Financial and Operating Results
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· |
Q2 2017 Average Production of 112,660 BOE/d |
|
· |
Revising Capital Budget to $950 Million; Forecast 14% Q1 to Q4 2017 Production Growth |
|
· |
New Enhanced Completions in Williams County Exceeding 1.0 MMBOE Type Curve |
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· |
69 Enhanced Completion Wells Drilled Across Williston Basin Since January 2016 Exceeding 1.0 MMBOE Type Curve |
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· |
Q2 2017 DD&A per BOE below Low End of Guidance; All Other Metrics within Guidance |
DENVER – July 26, 2017 – Whiting’s (NYSE: WLL) production in the second quarter 2017 totaled 10.3 million barrels of oil equivalent (MMBOE), comprised of 83% crude oil/natural gas liquids (NGLs). Second quarter 2017 production averaged 112,660 barrels of oil equivalent per day (BOE/d). 10 out of 22 wells completed during the quarter commenced production in June. The production benefit of these wells is expected to be experienced mainly during the second half of 2017. Whiting’s depreciation, depletion and amortization (DD&A) rate of $21.46 per BOE came in below the low end of guidance for $22.25 – $23.25 per BOE. This reflects the impact of strong reserve bookings in the Williston Basin area where the Company recorded a 59 MMBOE increase in proved reserves from upward performance revisions, extensions and discoveries. All other metrics were within guidance.
James J. Volker, Whiting’s Chairman, President and CEO, commented, “One of our priorities is to maintain a strong balance sheet while delivering high returns and sustainable growth to investors. We plan to reduce capital spending to $950 million while achieving 14% production growth from first quarter to fourth quarter 2017. This is a testament to the high quality of our asset base, which is also evident in the strong 23% growth in proved
reserves from year-end 2016 levels. A large component of this growth was driven by the effect of enhanced completions in the Williston Basin.”
Mr. Volker continued, “We continue to bring on enhanced completion wells in the Williston Basin with production profiles in the 1-1.5 MMBOE type curve range. These wells deliver strong rates of return, even at a $40 NYMEX oil price. In summary, the steps we took to strengthen our balance sheet and improve well productivity through enhanced completions empowers us to deliver strong growth at current commodity prices.”
Operating and Financial Results
The following table summarizes the operating and financial results for the second quarter of 2017 and 2016, including non-cash charges recorded during those periods:
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Three Months Ended |
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June 30, |
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2017 |
2016 |
||||
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Production (MBOE/d) (1) |
112.66 | 134.24 | ||||
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Net cash provided by operating activities-MM |
$ |
111.0 |
$ |
161.0 | ||
|
Discretionary cash flow-MM (2) |
$ |
139.3 |
$ |
151.6 | ||
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Realized price ($/BOE) |
$ |
30.83 |
$ |
30.39 | ||
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Total operating revenues-MM |
$ |
311.5 |
$ |
337.0 | ||
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Net loss attributable to common shareholders-MM (3) |
$ |
(66.0) |
$ |
(301.0) | ||
|
Per basic share |
$ |
(0.18) |
$ |
(1.33) | ||
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Per diluted share |
$ |
(0.18) |
$ |
(1.33) | ||
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||||||
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Adjusted net loss attributable to common shareholders-MM (4) |
$ |
(65.3) |
$ |
(158.7) | ||
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Per basic share |
$ |
(0.18) |
$ |
(0.70) | ||
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Per diluted share |
$ |
(0.18) |
$ |
(0.70) | ||
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(1) |
Second quarter 2016 includes 8,920 BOE/d from properties that have since been divested. |
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(2) |
A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release. |
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(3) |
Net loss attributable to common shareholders includes $16 million of pre-tax, non-cash derivative gains and $31 million of pre-tax, non-cash derivative losses for the three months ended June 30, 2017 and 2016, respectively. |
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(4) |
A reconciliation of net loss attributable to common shareholders to adjusted net loss attributable to common shareholders is included later in this news release. |
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2
The following table summarizes the first six months operating and financial results for 2017 and 2016, including non-cash charges recorded during those periods:
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Six Months Ended |
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June 30, |
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2017 |
2016 |
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Production (MBOE/d) (1) |
115.00 | 140.51 | ||||
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Net cash provided by operating activities-MM |
$ |
191.1 |
$ |
206.9 | ||
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Discretionary cash flow-MM (2) |
$ |
321.9 |
$ |
253.9 | ||
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Realized price ($/BOE) |
$ |
33.10 |
$ |
28.00 | ||
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Total operating revenues-MM |
$ |
682.8 |
$ |
626.7 | ||
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Net loss attributable to common shareholders-MM (3) |
$ |
(152.9) |
$ |
(472.8) | ||
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Per basic share |
$ |
(0.42) |
$ |
(2.20) | ||
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Per diluted share |
$ |
(0.42) |
$ |
(2.20) | ||
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Adjusted net loss attributable to common shareholders-MM (4) |
$ |
(119.5) |
$ |
(333.0) | ||
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Per basic share |
$ |
(0.33) |
$ |
(1.55) | ||
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Per diluted share |
$ |
(0.33) |
$ |
(1.55) | ||
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(1) |
The six months ended June 30, 2016 includes 9,070 BOE/d from properties that have since been divested. |
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(2) |
A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release. |
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(3) |
Net loss attributable to common shareholders includes $22 million and $91 million of pre-tax, non-cash derivative losses for the six months ended June 30, 2017 and 2016, respectively. |
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(4) |
A reconciliation of net loss attributable to common shareholders to adjusted net loss attributable to common shareholders is included later in this news release. |
3
Adjusting Capital Budget to $950 Million; Project 14% Production Growth Q1 to Q4 2017
Whiting is revising its capital budget and production guidance. The Company’s new capital budget of $950 million allocates $518 million to the Williston Basin area, $332 million to the DJ Basin area, $62 million to non-operated activity and $38 million to exploration, facilities and land. Whiting plans to drop two rigs, one in the Williston Basin and one in the DJ Basin, and run a four-rig program (all Williston Basin) through year-end.
The Company plans to put 82 wells on production in the Redtail area in the third and fourth quarters and anticipates an inventory of 38 DUC (drilled uncompleted) wells at year-end. In the Williston Basin, Whiting plans to put 54 wells on production in the third and fourth quarters and anticipates an inventory of 55 DUC wells at year-end. The Company’s new production guidance forecasts full-year average production of 43.6 - 44.3 MMBOE (119,450 - 121,370 BOE/d). At the midpoint of guidance, Whiting projects third quarter average volumes of approximately 118.0 MBOE/d and fourth quarter volumes of approximately 133.5 MBOE/d. The fourth quarter rate represents a 14% production increase relative to first quarter levels.
Proved Reserves Grew 23% to 755 MMBOE from Year-End Levels
As of June 30, 2017, Whiting’s proved reserves are estimated at 755 MMBOE, a 23% increase from year-end 2016 levels of 616 MMBOE. The mid-year reserve estimate was audited by the Company’s third-party reservoir engineering firm Cawley, Gillespie & Associates.
Whiting Receives $35 Million for North Ward Estes Oil Price Contingent Payment Agreement
In July 2016, Whiting completed the sale of its interest in the North Ward Estes field and associated assets located in Ward and Winkler Counties, Texas. In addition to the $300 million cash purchase price, the buyer agreed to pay Whiting $100,000 for every one cent ($0.01) that the average of the NYMEX WTI crude oil futures contract price for the period of August 2018 through July 2021 is above $50.00/Bbl on June 28, 2018. On July 19, 2017, the buyer made a $35 million cash payment to Whiting to settle this contingent feature. The contract settlement amount would have been $4.2 million based on the NYMEX forward strip pricing for crude oil as of July 19, 2017.
Operations Update
Whiting controls 743,667 gross (449,857 net) acres in the Williston Basin and 159,994 gross (134,771 net) acres at its Redtail Niobrara/Codell play in the DJ Basin. In the second quarter 2017, total net production for the Company averaged 112,660 BOE/d. The Bakken/Three Forks play in the Williston Basin averaged 105,475 BOE/d. The Redtail Niobrara/Codell play in the DJ Basin averaged 6,610 BOE/d.
New Williston Basin Enhanced Completions in Williams County Tracking above 1.0 MMBOE Type Curve. In June 2017, Whiting completed its three-well Evitt 14-12 pad and its three-well Evitt 34-12 pad in Williams County, North Dakota. The wells are located in the southeastern portion of Whiting’s Williams County acreage. The Evitt 14-12 pad was completed with an average of 9.3 million pounds of sand per well and averaged 37 stages. The Evitt 34-12 pad was completed with an average of 10.1 million pounds of sand per well and averaged 42 stages. On average, the two pads are tracking above a 1.0 MMBOE type curve. In April, Whiting completed two enhanced completion wells on its Northern 31-30 pad, which is located approximately 15 miles northwest of
4
the Evitt pads. The two wells were completed with an average of 11.6 million pounds of sand per well and 43 stages and are tracking above a 1.0 MMBOE type curve. Whiting estimates it has approximately 1,650 gross future drilling locations in Williams County.
69 Enhanced Completion Wells Drilled Across Williston Basin Since January 2016 Exceeding 1.0 MMBOE Type Curve. Since January 2016, Whiting has drilled 69 enhanced completion wells that incorporate sand volumes of 7.0 million pounds or more per well, additional stages and new diverter technology. On average, these wells are producing above a 1.0 MMBOE type curve. The wells span Dunn, McKenzie, Mountrail and Williams Counties. Within these counties, the associated well pads are located across multiple operating areas that bracket Whiting’s acreage position. The Company believes this demonstrates the broad prospectivity of its acreage for enhanced completions. Whiting estimates it has approximately 4,500 gross future drilling locations in Dunn, McKenzie, Mountrail and Williams Counties.
Initial Enhanced Completion Results at DJ Basin Redtail Play Outperforming. In June and July 2017, Whiting began flowing back the seven-well Razor 12-H pad and the eight-well Razor 12-G pad at its DJ Basin Redtail play in Weld County, Colorado. The pads target the Niobrara “A”, “B” and “C” zones and Codell/Fort Hays formations. The Razor 12-H pad is testing higher sand volumes. It incorporated 8.0 million pounds of sand per well versus a typical well design of 4.0 to 5.0 million pounds. Early results are encouraging with the production profile of the 12-H pad outperforming the offsetting 12-G pad that was completed with 5.0 million pounds of sand per well.
5
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended June 30, 2017 and 2016:
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Three Months Ended |
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June 30, |
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2017 |
2016 |
Change |
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Production |
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Oil (MMBbl) |
6.91 | 8.72 |
(21%) |
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NGLs (MMBbl) |
1.65 | 1.69 |
(3%) |
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Natural gas (Bcf) |
10.17 | 10.81 |
(6%) |
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Total equivalent (MMBOE) (1) |
10.25 | 12.22 |
(16%) |
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Average sales price |
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Oil (per Bbl): |
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Price received |
$ |
40.12 |
$ |
35.67 |
12% |
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Effect of crude oil hedging (2) |
0.66 | 3.93 | ||||||
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Realized price |
$ |
40.78 |
$ |
39.60 |
3% |
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Weighted average NYMEX price (per Bbl) (3) |
$ |
48.32 |
$ |
45.57 |
6% |
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Realized price |
$ |
10.41 |
$ |
9.17 |
14% |
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Realized price |
$ |
1.68 |
$ |
0.96 |
75% |
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Weighted average NYMEX price (per MMBtu) (3) |
$ |
3.09 |
$ |
1.98 |
56% |
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(1) |
Second quarter 2016 includes 8,920 BOE/d from properties that have since been divested. |
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(2) |
Whiting received $5 million and $34 million in pre-tax cash settlements on its crude oil hedges during the second quarter of 2017 and 2016, respectively. A summary of Whiting’s outstanding hedges is included later in this news release. |
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(3) |
Average NYMEX prices weighted for monthly production volumes. |
6
Second Quarter and First Half 2017 Costs and Margins
A summary of production and cash revenues and cash costs on a per BOE basis is as follows:
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Three Months Ended |
Six Months Ended |
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June 30, |
June 30, |
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2017 |
2016 |
2017 |
2016 |
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(per BOE, except production) |
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Production (MMBOE) |
10.25 | 12.22 | 20.81 | 25.57 | ||||||||
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Sales price, net of hedging |
$ |
30.83 |
$ |
30.39 |
$ |
33.10 |
$ |
28.00 | ||||
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Lease operating expense |
8.41 | 8.61 | 8.49 | 8.59 | ||||||||
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Production tax |
2.64 | 2.20 | 2.84 | 2.06 | ||||||||
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Cash general & administrative |
2.45 | 2.21 | 2.39 | 2.55 | ||||||||
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Exploration |
0.62 | 0.85 | 0.60 | 1.21 | ||||||||
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Cash interest expense |
3.93 | 5.00 | 3.88 | 4.76 | ||||||||
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Cash income tax benefit |
(0.13) |
- |
(0.15) |
- |
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|
$ |
12.91 |
$ |
11.52 |
$ |
15.05 |
$ |
8.83 | ||||
Second Quarter and First Half 2017 Completions and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated completion activity and capital expenditures for the three and six months ended June 30, 2017.
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Gross/Net Wells Completed |
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Producing |
Non-Producing |
Total New Wells |
% Success Rate |
CAPEX (in MM) |
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Q2 17 |
22 / 10.4 |
- / - |
22 / 10.4 |
100% / 100% |
$ 234.7 (1) |
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6M 17 |
70 / 25.8 |
- / - |
70 / 25.8 |
100% / 100% |
$ 420.5 (2) |
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(1) |
Includes $10 million for non-operated drilling and completion, $10 million for land, and $2 million for facilities. |
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(2) |
Includes $21 million for non-operated drilling and completion, $12 million for land, and $3 million for facilities. |
7
Outlook for Third Quarter and Full-Year 2017
The following table provides guidance for the third quarter and full-year 2017 based on current forecasts, including Whiting’s full-year 2017 capital budget of $950 million:
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Guidance |
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Third Quarter |
Full Year |
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2017 |
2017 |
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Production (MMBOE) |
10.5 - 11.1 |
43.6 - 44.3 |
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Lease operating expense per BOE |
$ 8.25 - $ 8.75 |
$ 8.25 - $ 8.75 |
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General and administrative expense per BOE |
$ 2.90 - $ 3.30 |
$ 2.90 - $ 3.10 |
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Interest expense per BOE |
$ 4.40 - $ 4.80 |
$ 4.30 - $ 4.70 |
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Depreciation, depletion and amortization per BOE |
$21.00 - $22.00 |
$21.50 - $22.10 |
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Production taxes (% of sales revenue) |
8.5% - 8.9% |
8.5% - 8.9% |
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Oil price differentials to NYMEX per Bbl (1) |
($7.50) - ($8.50) |
($7.50) - ($8.50) |
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Gas price differential to NYMEX per Mcf |
($1.00) - ($1.40) |
($1.00) - ($1.40) |
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(1) |
Does not include the effects of NGLs. |
Commodity Derivative Contracts
Whiting is more than 64% hedged for the remainder of 2017 as a percentage of June 2017 production.
The following summarizes Whiting’s crude oil hedges as of July 19, 2017:
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Average |
Weighted Average |
As a Percentage of |
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Derivative |
Hedge |
Contracted Crude |
NYMEX Price |
June 2017 |
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Instrument |
Period |
(Bbls per Month) |
(per Bbl) |
Oil Production |
||||
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Three-way collars (1) |
2017 |
|||||||
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Q3 |
1,216,667 |
$35.00 - $45.21 - $59.22 |
53.5% |
||||
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Q4 |
1,250,000 |
$35.00 - $45.20 - $58.95 |
55.0% |
||||
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2018 |
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Q1 |
350,000 |
$38.57 - $48.57 - $58.46 |
15.4% |
||||
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Q2 |
350,000 |
$38.57 - $48.57 - $58.46 |
15.4% |
||||
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Q3 |
350,000 |
$38.57 - $48.57 - $58.46 |
15.4% |
||||
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Q4 |
350,000 |
$38.57 - $48.57 - $58.46 |
15.4% |
||||
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Collars |
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2017 |
|
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Q3 |
250,000 |
$53.00 - $70.44 |
11.0% |
||||
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Q4 |
250,000 |
$53.00 - $70.44 |
11.0% |
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(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. |
8
Selected Operating and Financial Statistics
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Three Months Ended |
Six Months Ended |
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June 30, |
June 30, |
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2017 |
2016 |
2017 |
2016 |
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Selected operating statistics: |
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Production |
||||||||||||
|
Oil, MBbl |
6,911 | 8,722 | 14,209 | 18,684 | ||||||||
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NGLs, MBbl |
1,647 | 1,692 | 3,266 | 3,334 | ||||||||
|
Natural gas, MMcf |
10,166 | 10,813 | 20,039 | 21,327 | ||||||||
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Oil equivalents, MBOE(1) |
10,252 | 12,216 | 20,814 | 25,572 | ||||||||
|
Average prices |
||||||||||||
|
Oil per Bbl (excludes hedging) |
$ |
40.12 |
$ |
35.67 |
$ |
42.07 |
$ |
31.09 | ||||
|
NGLs per Bbl |
$ |
10.41 |
$ |
9.17 |
$ |
14.02 |
$ |
7.35 | ||||
|
Natural gas per Mcf |
$ |
1.68 |
$ |
0.96 |
$ |
1.96 |
$ |
1.00 | ||||
|
Per BOE data |
||||||||||||
|
Sales price (including hedging) |
$ |
30.83 |
$ |
30.39 |
$ |
33.10 |
$ |
28.00 | ||||
|
Lease operating |
$ |
8.41 |
$ |
8.61 |
$ |
8.49 |
$ |
8.59 | ||||
|
Production taxes |
$ |
2.64 |
$ |
2.20 |
$ |
2.84 |
$ |
2.06 | ||||
|
Depreciation, depletion and amortization |
$ |
21.46 |
$ |
24.89 |
$ |
22.12 |
$ |
24.10 | ||||
|
General and administrative |
$ |
3.12 |
$ |
2.74 |
$ |
3.01 |
$ |
3.06 | ||||
|
Selected financial data: (In thousands, except per share data) |
||||||||||||
|
Total operating revenues |
$ |
311,515 |
$ |
337,036 |
$ |
682,832 |
$ |
626,733 | ||||
|
Total operating expenses |
$ |
368,229 |
$ |
490,646 |
$ |
817,052 |
$ |
1,026,374 | ||||
|
Total other expense, net |
$ |
(47,494) |
$ |
(257,420) |
$ |
(96,435) |
$ |
(248,313) | ||||
|
Net loss attributable to common shareholders |
$ |
(65,981) |
$ |
(301,041) |
$ |
(152,938) |
$ |
(472,789) | ||||
|
Loss per common share, basic |
|
$ |
(0.18) |
|
$ |
(1.33) |
|
$ |
(0.42) |
|
$ |
(2.20) |
|
Loss per common share, diluted |
$ |
(0.18) |
$ |
(1.33) |
$ |
(0.42) |
$ |
(2.20) | ||||
|
Weighted average shares outstanding, basic |
362,734 | 226,039 | 362,672 | 215,203 | ||||||||
|
Weighted average shares outstanding, diluted |
362,734 | 226,039 | 362,672 | 215,203 | ||||||||
|
Net cash provided by operating activities |
|
$ |
110,993 |
|
$ |
160,986 |
|
$ |
191,063 |
|
$ |
206,934 |
|
Net cash provided by (used in) investing activities |
|
$ |
(204,126) |
|
$ |
(96,698) |
|
$ |
39,014 |
|
$ |
(356,961) |
|
Net cash provided by (used in) financing activities |
|
$ |
99,947 |
|
$ |
(50,011) |
|
$ |
(280,059) |
|
$ |
149,312 |
|
(1) |
The three and six months ended June 30, 2016 include 8,920 BOE/d and 9,070 BOE/d, respectively, from properties that have since been divested. |
||||||
9
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 June 30, 2017 to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands)
|
|
||||||
|
|
June 30, |
December 31, |
||||
|
|
2017 |
2016 |
||||
|
ASSETS |
||||||
|
Current assets: |
||||||
|
Cash and cash equivalents |
$ |
23,243 |
$ |
55,975 | ||
|
Restricted cash |
- |
17,250 | ||||
|
Accounts receivable trade, net |
210,204 | 173,919 | ||||
|
Derivative assets |
26,964 |
- |
||||
|
Prepaid expenses and other |
30,727 | 26,312 | ||||
|
Assets held for sale(1) |
- |
349,146 | ||||
|
Total current assets |
291,138 | 622,602 | ||||
|
Property and equipment: |
||||||
|
Oil and gas properties, successful efforts method |
13,604,214 | 13,230,851 | ||||
|
Other property and equipment |
136,782 | 134,638 | ||||
|
Total property and equipment |
13,740,996 | 13,365,489 | ||||
|
Less accumulated depreciation, depletion and amortization |
(4,699,342) | (4,222,071) | ||||
|
Total property and equipment, net |
9,041,654 | 9,143,418 | ||||
|
Other long-term assets |
72,627 | 110,122 | ||||
|
TOTAL ASSETS |
$ |
9,405,419 |
$ |
9,876,142 | ||
|
(1) |
As of December 31, 2016, “Assets held for sale” is comprised of Whiting’s North Dakota midstream assets. This transaction closed on January 1, 2017. |
||||||
10
WHITING PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share data)
|
|
||||||
|
|
June 30, |
December 31, |
||||
|
|
2017 |
2016 |
||||
|
LIABILITIES AND EQUITY |
||||||
|
Current liabilities: |
||||||
|
Accounts payable trade |
$ |
70,541 |
$ |
32,126 | ||
|
Revenues and royalties payable |
130,495 | 147,226 | ||||
|
Accrued capital expenditures |
95,499 | 56,830 | ||||
|
Accrued interest |
40,726 | 44,749 | ||||
|
Accrued lease operating expenses |
45,606 | 45,015 | ||||
|
Accrued liabilities and other |
24,863 | 63,538 | ||||
|
Taxes payable |
20,447 | 39,547 | ||||
|
Derivative liabilities |
23,616 | 17,628 | ||||
|
Accrued employee compensation and benefits |
16,940 | 31,134 | ||||
|
Liabilities related to assets held for sale |
- |
538 | ||||
|
Total current liabilities |
468,733 | 478,331 | ||||
|
Long-term debt |
3,274,807 | 3,535,303 | ||||
|
Deferred income taxes |
401,191 | 475,689 | ||||
|
Asset retirement obligations |
171,419 | 168,504 | ||||
|
Other long-term liabilities |
93,162 | 69,123 | ||||
|
Total liabilities |
4,409,312 | 4,726,950 | ||||
|
Commitments and contingencies |
||||||
|
Equity: |
||||||
|
Common stock, $0.001 par value, 600,000,000 shares authorized; 368,133,400 issued and 362,793,720 outstanding as of June 30, 2017 and 367,174,542 issued and 362,013,928 outstanding as of December 31, 2016 |
|
|
368 |
|
|
367 |
|
Additional paid-in capital |
6,397,469 | 6,389,435 | ||||
|
Accumulated deficit |
(1,401,730) | (1,248,572) | ||||
|
Total Whiting shareholders' equity |
4,996,107 | 5,141,230 | ||||
|
Noncontrolling interest |
- |
7,962 | ||||
|
Total equity |
4,996,107 | 5,149,192 | ||||
|
TOTAL LIABILITIES AND EQUITY |
$ |
9,405,419 |
$ |
9,876,142 | ||
11
WHITING PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
|
|
||||||||||||
|
|
Three Months Ended |
Six Months Ended |
||||||||||
|
|
June 30, |
June 30, |
||||||||||
|
|
2017 |
2016 |
2017 |
2016 |
||||||||
|
OPERATING REVENUES |
||||||||||||
|
Oil, NGL and natural gas sales |
$ |
311,515 |
$ |
337,036 |
$ |
682,832 |
$ |
626,733 | ||||
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
86,269 | 105,172 | 176,662 | 219,548 | ||||||||
|
Production taxes |
27,066 | 26,826 | 59,122 | 52,753 | ||||||||
|
Depreciation, depletion and amortization |
220,035 | 304,016 | 460,442 | 616,308 | ||||||||
|
Exploration and impairment |
25,295 | 25,781 | 46,136 | 61,272 | ||||||||
|
General and administrative |
31,943 | 33,523 | 62,560 | 78,319 | ||||||||
|
Derivative (gain) loss, net |
(20,163) | (2,761) | 16,414 | 2,000 | ||||||||
|
Loss on sale of properties |
1,024 | 1,861 | 2,298 | 3,795 | ||||||||
|
Amortization of deferred gain on sale |
(3,240) | (3,772) | (6,582) | (7,621) | ||||||||
|
Total operating expenses |
368,229 | 490,646 | 817,052 | 1,026,374 | ||||||||
|
LOSS FROM OPERATIONS |
|
|
(56,714) |
|
|
(153,610) |
|
|
(134,220) |
|
|
(399,641) |
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
(47,937) | (78,660) | (95,948) | (160,567) | ||||||||
|
Loss on extinguishment of debt |
- |
(179,396) | (1,540) | (88,777) | ||||||||
|
Interest income and other |
443 | 636 | 1,053 | 1,031 | ||||||||
|
Total other expense |
(47,494) | (257,420) | (96,435) | (248,313) | ||||||||
|
LOSS BEFORE INCOME TAXES |
|
|
(104,208) |
|
|
(411,030) |
|
|
(230,655) |
|
|
(647,954) |
|
INCOME TAX EXPENSE (BENEFIT) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
(1,316) | (1) | (3,206) | 2 | ||||||||
|
Deferred |
(36,911) | (109,983) | (74,497) | (175,152) | ||||||||
|
Total income tax benefit |
(38,227) | (109,984) | (77,703) | (175,150) | ||||||||
|
NET LOSS |
|
|
(65,981) |
|
|
(301,046) |
|
|
(152,952) |
|
|
(472,804) |
|
Net loss attributable to noncontrolling interests |
|
|
- |
|
|
5 |
|
|
14 |
|
|
15 |
|
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS |
$ |
(65,981) |
$ |
(301,041) |
$ |
(152,938) |
$ |
(472,789) | ||||
|
LOSS PER COMMON SHARE |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
(0.18) |
$ |
(1.33) |
$ |
(0.42) |
$ |
(2.20) | ||||
|
Diluted |
$ |
(0.18) |
$ |
(1.33) |
$ |
(0.42) |
$ |
(2.20) | ||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING |
||||||||||||
|
Basic |
362,734 | 226,039 | 362,672 | 215,203 | ||||||||
|
Diluted |
362,734 | 226,039 | 362,672 | 215,203 | ||||||||
12
WHITING PETROLEUM CORPORATION
Reconciliation of Net Loss Attributable to Common Shareholders to
Adjusted Net Loss Attributable to Common Shareholders
(in thousands, except per share data)
|
|
||||||||||||
|
|
Three Months Ended |
Six Months Ended |
||||||||||
|
|
June 30, |
June 30, |
||||||||||
|
|
2017 |
2016 |
2017 |
2016 |
||||||||
|
Net loss attributable to common shareholders |
|
$ |
(65,981) |
|
$ |
(301,041) |
|
$ |
(152,938) |
|
$ |
(472,789) |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of deferred gain on sale |
|
|
(3,240) |
|
|
(3,772) |
|
|
(6,582) |
|
|
(7,621) |
|
Loss on sale of properties |
|
|
1,024 |
|
|
1,861 |
|
|
2,298 |
|
|
3,795 |
|
Impairment expense |
|
|
18,943 |
|
|
15,388 |
|
|
33,646 |
|
|
30,360 |
|
Penalties for early termination of drilling rig contracts |
|
|
- |
|
|
2,257 |
|
|
- |
|
|
15,944 |
|
Loss on extinguishment of debt |
|
|
- |
|
|
179,396 |
|
|
1,540 |
|
|
88,777 |
|
Total measure of derivative (gain) loss reported under U.S. GAAP |
|
|
(20,163) |
|
|
(2,761) |
|
|
16,414 |
|
|
2,000 |
|
Total net cash settlements received on commodity derivatives during the period |
|
|
4,588 |
|
|
34,253 |
|
|
6,058 |
|
|
89,414 |
|
Tax impact of adjustments above |
|
|
(429) |
|
|
(84,304) |
|
|
(19,908) |
|
|
(82,833) |
|
Adjusted net loss attributable to common shareholders (1) |
|
$ |
(65,258) |
|
$ |
(158,723) |
|
$ |
(119,472) |
|
$ |
(332,953) |
|
|
||||||||||||
|
Adjusted net loss attributable to common shareholders per share, basic |
|
$ |
(0.18) |
|
$ |
(0.70) |
|
$ |
(0.33) |
|
$ |
(1.55) |
|
Adjusted net loss attributable to common shareholders per share, diluted |
|
$ |
(0.18) |
|
$ |
(0.70) |
|
$ |
(0.33) |
|
$ |
(1.55) |
|
(1) |
Adjusted Net Loss Attributable 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 Loss Attributable 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 Loss Attributable 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. |
13
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(in thousands)
|
|
||||||||||||
|
|
Three Months Ended |
Six Months Ended |
||||||||||
|
|
June 30, |
June 30, |
||||||||||
|
|
2017 |
2016 |
2017 |
2016 |
||||||||
|
Net cash provided by operating activities |
$ |
110,993 |
$ |
160,986 |
$ |
191,063 |
$ |
206,934 | ||||
|
Exploration |
6,352 | 10,393 | 12,490 | 30,912 | ||||||||
|
Changes in working capital |
22,003 | (19,731) | 118,384 | 16,095 | ||||||||
|
Discretionary cash flow (1) |
$ |
139,348 |
$ |
151,648 |
$ |
321,937 |
$ |
253,941 | ||||
|
(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. |
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, July 27, 2017 at 11:00 a.m. ET (10:00 a.m. CT, 9:00 a.m. MT) to discuss Whiting’s second quarter 2017 financial and operating results. Participants are encouraged to pre-register for the conference call by clicking on the following link: http://dpregister.com/10109215. Callers who pre-register will be given a unique telephone number and PIN to gain immediate access on the day of the call.
Those without internet access or unable to pre-register may join the live call by dialing: (877) 328-5506 (U.S.); (866) 450-4696 (Canada) or (412) 317-5422 (International) to be connected to the call. Presentation slides will be available at http://www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled "Presentations & Events."
A telephonic replay will be available beginning one to two hours after the call on Thursday, July 27, 2017 and continuing through Thursday, August 3, 2017. You may access this replay at (877) 344-7529 (U.S.); 855-669-9658 (Canada) or (412) 317-0088 (International) and enter the pass code 10109213. You may also access a web archive at http://www.whiting.com beginning one to two hours after the conference call.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that develops, produces, acquires and explores for crude oil, natural gas and natural gas liquids primarily in the Rocky Mountains region of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and Montana and the Niobrara play in northeast Colorado. 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 27A of the Securities Act of 1933 and 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.
14
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 or extended periods of low oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness, ability to comply with debt covenants and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; 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; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; 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; the potential impact of changes in laws, including tax reform, that could have a negative effect on the oil and gas industry; 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; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2016. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
15