Whiting’s (NYSE: WLL) production in the fourth quarter 2014 totaled 12.1 million barrels of oil equivalent (MMBOE), 88% crude oil/natural gas liquids (NGLs). Fourth quarter 2014 production averaged 131,260 barrels of oil equivalent per day (BOE/d), which includes Kodiak production for 24 days. This represents a 30% increase over the fourth quarter 2013 and a 13% increase over the third quarter 2014. Production in 2014 totaled a record 41.8 MMBOE or 114,530 BOE/d. This represents a 22% increase over 2013. Our first quarter 2015 guidance is for 163,000 BOE/d.
James J. Volker, Whiting’s Chairman, President and CEO, commented, “2014 was a strong year for Whiting. We set records in production, proved reserves and discretionary cash flow. In the wake of our acquisition of Kodiak Oil & Gas, we became the largest Bakken/Three Forks producer in the Williston Basin. Our initial results on the properties acquired have been rewarding, with our first three-well pad in Dunn County testing an average rate of 3,473 BOE/d per well. These wells were completed with a Whiting completion design at a cost savings of approximately $750,000 per well relative to the prior design. In our Redtail area in Weld County, Colorado, results have been strong in the Niobrara “C” zone and Codell/Fort Hays formations with 120-day average rates of approximately 400 BOE/d. We believe returns could rival our Niobrara “A” and “B” drilling and after year-end 2014 we added 3,162 gross Niobrara “C” and Codell/Fort Hays locations to our potential drilling inventory. Given our high quality asset base, we are confident in our ability to navigate the current pricing environment.”
Mr. Volker continued, “We have taken prudent measures in 2015 to reduce our capital budget while maintaining our financial flexibility.Our 2015 capital budget of $2.0 billion reflects a disciplined approach to maintaining our financial strength while preserving our long-term growth plans. We are currently running 19 rigs, 16 in the Bakken/Three Forks and 3 in the Niobrara at Redtail. Our rig count will go to 13 rigs by mid-year, 10 in the Bakken/Three Forks and 3 in the Niobrara, down from 25 rigs for the combined companies in 2014.We will focus our operations on our highest rate-of-return properties.At the same time, we are seeing lower completed well costs through service company price reductions and technology applications. We expect our 2015 completed well cost in the Bakken/Three Forks to average $7 million, down from $8.5 million in 2014. We expect our 2015 Redtail Niobrara well cost to be $5.0 million. We continue to work on driving these costs lower while maintaining our EURs.”
Operating and Financial Results
The following table summarizes the operating and financial results for the fourth quarter of 2014 and 2013:
Three Months Ended | ||||||||||||
| 2014 | 2013 | Change | ||||||||||
| Production (MBOE/d) | 131.26 | 100.96 | 30 | % | ||||||||
| Discretionary cash flow-MM (1) | $ | 419.5 | $ | 457.6 | (8 | %) | ||||||
| Realized price ($/BOE) | $ | 59.86 | $ | 75.18 | (20 | %) | ||||||
| Total revenues-MM | $ | 696.1 | $ | 720.5 | (3 | %) | ||||||
| Net loss available to common shareholders-MM (2)(3) | $ | (353.7 | ) | $ | (59.3 | ) | (497 | %) | ||||
| Per basic share | $ | (2.69 | ) | $ | (0.50 | ) | (438 | %) | ||||
| Per diluted share | $ | (2.68 | ) | $ | (0.50 | ) | (436 | %) | ||||
| Adjusted net income available to common shareholders-MM (4) | $ | 58.3 | $ | 104.8 | (44 | %) | ||||||
| Per basic share | $ | 0.44 | $ | 0.88 | (50 | %) | ||||||
| Per diluted share | $ | 0.44 | $ | 0.88 | (50 | %) | ||||||
| (1) | A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release. | |
| (2) | For the three months ended December 31, 2014, net loss available to common shareholders included $77 million of pre-tax, non-cash derivative gains or $0.37 per basic and diluted share after tax. For the three months ended December 31, 2013, net loss available to common shareholders included $22 million of pre-tax, non-cash derivative gains or $0.11 per basic and diluted share after tax. | |
| (3) | For the three months ended December 31, 2014, this amount includes $587 million in non-cash pre-tax impairment charges for the partial write-down of non-core proved oil and gas properties not currently being developed primarily attributable to oil and gas reserves in legacy, non-core areas in Colorado, Louisiana, North Dakota and Utah related to the decrease in oil and gas prices at December 31, 2014, as well as $42 million of impairment write-downs on our CO2 development properties. For the three months ended December 31, 2013, this amount includes $267 million in non-cash pre-tax impairment charges for the partial write-down of proved properties, mainly in non-core portions of the Rocky Mountains and Michigan regions. | |
| (4) | A reconciliation of net income (loss) available to common shareholders to adjusted net income available to common shareholders is included later in this news release. | |
The following table summarizes the operating and financial results for the full year of 2014 and 2013:
Year Ended | ||||||||||
| 2014 | 2013 | Change | ||||||||
| Production (MBOE/d) (1) | 114.53 | 94.09 | 22 | % | ||||||
| Discretionary cash flow-MM (2) | $ | 1,995.9 | $ | 1,750.0 | 14 | % | ||||
| Realized price ($/BOE) | $ | 73.38 | $ | 76.76 | (4 | %) | ||||
| Total revenues-MM | $ | 3,085.1 | $ | 2,828.4 | 9 | % | ||||
| Net income available to common shareholders-MM (3)(4) | $ | 64.8 | $ | 365.5 | (82 | %) | ||||
| Per basic share | $ | 0.53 | $ | 3.09 | (83 | %) | ||||
| Per diluted share | $ | 0.53 | $ | 3.06 | (83 | %) | ||||
| Adjusted net income available to common shareholders-MM (5) | $ | 508.4 | $ | 490.9 | 4 | % | ||||
| Per basic share | $ | 4.16 | $ | 4.15 | <1% | |||||
| Per diluted share | $ | 4.15 | $ | 4.11 | 1 | % | ||||
| (1) | The production attributable to the Postle field, which was sold on July 15, 2013, was 1,492.3 MBOE for the year ended December 31, 2013 (7.6 MBOE/d over 196 days). | |
| (2) | A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release. | |
| (3) | For the year ended December 31, 2014, net income available to common shareholders included $57 million of pre-tax, non-cash derivative gains or $0.30 per basic and diluted share after tax. For the year ended December 31, 2013, net income available to common shareholders included $21 million of pre-tax, non-cash derivative gains or $0.11 per basic and diluted share after tax. | |
| (4) | For the year ended December 31, 2014, this amount includes $587 million in non-cash pre-tax impairment charges for the partial write-down of non-core proved oil and gas properties not currently being developed primarily attributable to oil and gas reserves in legacy, non-core areas in Colorado, Louisiana, North Dakota and Utah related to the decrease in oil and gas prices at December 31, 2014, as well as $42 million of impairment write-downs on our CO2 development properties. For the year ended December 31, 2013, this amount includes $267 million in non-cash pre-tax impairment charges for the partial write-down of proved properties, mainly in non-core portions of the Rocky Mountains and Michigan regions. | |
| (5) | A reconciliation of net income available to common shareholders to adjusted net income available to common shareholders is included later in this news release. | |
Proved Reserves at December 31, 2014
As of December 31, 2014, Whiting achieved record proved reserves of 780.3 MMBOE, of which 53% were proved developed. This total includes 191.8 MMBOE of reserve additions from the Kodiak acquisition. The estimated proved reserves total had a pre-tax PV10% value of $14.1 billion(1), using 2014 SEC NYMEX prices of $94.99 per barrel of oil and $4.35 per Mcf of gas. This represents an increase of 57% over the December 31, 2013 value of $9.0 billion, which used SEC NYMEX prices of $96.78 per barrel of oil and $3.67 per Mcf of gas.
(1) | 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, 2014, our discounted future income taxes were $3,292.0 million and our standardized measure of after-tax discounted future net cash flows was $10,843.4 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, NGL and natural gas reserves. | ||
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2014:
| Natural | |||||||||||||
| Oil | NGLs | Gas | Total | ||||||||||
| (MBbl) | (MBbl) | (MMcf) | (MBOE) | ||||||||||
| Balance – January 1, 2014 | 347,421 | 44,869 | 277,514 | 438,542 | |||||||||
| Extensions and discoveries | 146,122 | 12,947 | 94,452 | 174,811 | |||||||||
| Sales of minerals in place | (1,642 | ) | - | (2,925 | ) | (2,130 | ) | ||||||
| Acquisitions | 169,586 | - | 156,140 | 195,609 | |||||||||
| Production | (33,485 | ) | (3,283 | ) | (30,218 | ) | (41,804 | ) | |||||
| Revisions to previous estimates | 15,627 | 151 | (2,943 | ) | 15,288 | ||||||||
| Balance – December 31, 2014 | 643,629 | 54,684 | 492,020 | 780,316 | |||||||||
Whiting’s proved reserves of 780.3 MMBOE represents a 78% increase over the 438.5 MMBOE of proved reserves at year-end 2013. Adding Kodiak’s proved reserves at year-end 2013, proved reserves increased 29%.(2)
The 341.8 MMBOE increase in proved reserves translates into 923% reserve replacement.(3) A total of 174.8 MMBOE of extensions and discoveries of proved reserves were added by the combined companies. This represents a 61% increase over the 108.8 MMBOE of proved reserves that were added from extensions and discoveries in 2013 by Whiting alone.
Whiting booked 124.1 MMBOE of Bakken/Three Forks proved reserves in the Williston Basin during 2014. At our Redtail Niobrara field in northeastern Colorado we booked 49.5 MMBOE of new proved reserves during 2014.
(2) | 438,542 MBOE total company proved reserves as of year-end 2013 plus 167,255 MBOE proved reserves as of year-end 2013 acquired in the Kodiak Oil & Gas transaction equals 605,797 MBOE. 780,316 MBOE total company proved reserves as of year-end 2014 represents a 29% increase over the adjusted year-end 2013 total. | ||
(3) | 174,811 MBOE extensions and discoveries plus 195,609 MBOE acquisitions plus 15,288 MBOE revisions to previous estimates equals 385,708 MBOE reserves added; 385,708 MBOE divided by 41,804 MBOE production equals 923% reserve replacement. | ||
Probable and Possible Reserves at December 31, 2014
At year-end 2014, Whiting’s probable and possible reserves were estimated to be a total of 624.8 MMBOE. The year-end 2014 estimated pre-tax PV10% for our probable and possible reserves was $5.2 billion, an increase of 44% over the $3.6 billion at year-end 2013(4).
As with our proved reserves, 100% of Whiting’s probable and possible reserve estimates were independently engineered by Cawley, Gillespie & Associates, Inc. Please refer to “Disclosure Regarding Reserves and Resources” later in this news release for information on probable and possible reserves.
(4) | 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, 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 does not exist any directly comparable U.S. GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves. | ||
2015 Capital Budget and Production Forecast
Our 2015 capital budget is $2.0 billion. Whiting expects to invest $1.8 billion of the 2015 capital budget on exploration and development activity, $59 million for land and $123 million for facilities. Based on this level of capital spending, we forecast production of 59.0 MMBOE – 59.7 MMBOE for 2015, an increase of 42% over our 2014 production of 41.8 MMBOE. With Kodiak’s full-year production included, 2014 pro forma production was approximately 55.8 MMBOE. Thus, while spending at approximately 50% of our combined company pro forma 2014 capex rate, we expect to grow production at 6% year-over-year.
Our 2015 capital budget is currently allocated among our major development areas as indicated in the table below:
| 2015 | |||||||||||
| CAPEX | Percent | ||||||||||
| (MM) | of Total | ||||||||||
| Northern Rockies | $ | 961 | 48 | % | |||||||
| Central Rockies | 386 | 19 | % | ||||||||
| Non-operated | 133 | 7 | % | ||||||||
| EOR project (1) | 82 | 4 | % | ||||||||
| Well work and other | 195 | 10 | % | ||||||||
| Exploration (2) | 61 | 3 | % | ||||||||
| Facilities | 123 | 6 | % | ||||||||
| Undeveloped acreage | 59 | 3 | % | ||||||||
| Total Budget | $ | 2,000 | 100 | % | |||||||
(1) | 2015 planned capital expenditures at our EOR projects include $80 million for North Ward Estes CO2 purchases. | |
(2) | Comprised primarily of exploration salaries, seismic activities, lease delay rentals and exploratory drilling. | |
Operations Update
Core Development Areas
Williston Basin Development
We hold a total of 1,311,845 gross (811,737 net) acres in the Williston Basin in North Dakota and Montana. In the fourth quarter of 2014, production from the Bakken/Three Forks averaged a record 100,870 BOE/d, a sequential increase of 15% over the 87,480 BOE/d in the third quarter of 2014. The Bakken/Three Forks represented 77% of Whiting’s total fourth quarter production. Whiting has an estimated 7,541 future gross drilling locations in the Bakken/Three Forks formations.
Tarpon Field Continues to Perform. Tarpon field continues to prove itself as a strong performer in the Bakken. During the fourth quarter, we completed three highly productive wells off of a pad. The Tarpon Federal 24-20-1H was completed in the Bakken formation on December 16, 2014 flowing 6,234 BOE/d. The Tarpon Federal 24-20-1RTF was completed in the Three Forks formation on December 17, 2014 flowing 4,818 BOE/d and the Federal 24-20-2RTF was completed in the Three Forks formation on December 17, 2014 flowing 4,105 BOE/d. Whiting holds a 75% working interest in all three wells.
Slickwater Frac Design Shows Strong Results at Pronghorn and Sanish Fields. We have favorable results from slickwater fracs at our Pronghorn field, which is located primarily in Stark and Billings counties, North Dakota. The Pronghorn Federal 14-12PH was completed on November 12, 2014. During its first 60 days of production, the well averaged 1,524 BOE/d. The Pronghorn Federal 11-13PH was completed on November 16, 2014. During its first 60 days of production, the well averaged 1,303 BOE/d.
As reported in our third quarter 2014 earnings release, we completed the Brehm 13-7H in the Sanish field in the Middle Bakken formation using a slickwater frac and a cemented liner on August 31, 2014. Production from the Brehm 13-7H has held up well with 60 and 90-day rates averaging 1,338 BOE/d and 1,111 BOE/d, respectively.
First Wells Completed on Kodiak Acreage Show Strong Initial Results. Whiting completed its first wells on acreage acquired from Kodiak. On a three-well pad in Dunn County, North Dakota, we completed the Moccasin Creek 14-33-28-4H in the Middle Bakken on January 17, 2015 flowing 3,850 BOE/d. The Moccasin Creek 14-33-28-3H was completed in the Middle Bakken on January 20, 2015 flowing 3,464 BOE/d and the Moccasin Creek 14-33-28-4H3 was completed in the Middle Bakken on January 15, 2015 flowing 3,104 BOE/d.
Denver Julesberg Basin Development
Redtail Niobrara Field. We hold a total of 185,703 gross (132,155 net) acres in our Redtail field, located in the Denver Julesberg Basin in Weld County, Colorado. Whiting has established production in the Niobrara “A”, “B” and “C” zones as well as the Codell/Fort Hays. Net production from the Redtail field averaged 10,155 BOE/d in the fourth quarter of 2014, an 18% sequential increase over the third quarter 2014. At year-end 2014, we had an estimated 3,523 future gross drilling locations in the Niobrara “A”, “B” and “C” zones as well as the Codell/Fort Hays formation. After year-end, we added 3,162 Niobrara “C” and Codell/Fort Hays future gross drilling locations to bring our total to 6,685 future gross drilling locations.
Our first Niobrara “C” zone and Codell/Fort Hays formation tests continue to perform well. The Razor 25B-2551 well, completed in the Codell/Fort Hays on September 9, 2014, averaged 397 BOE/d in its first 120 days on production. The Razor 25B-2549 well, completed in the Niobrara “C” zone on September 11, 2014, averaged 384 BOE/d in its first 120 days on production. Both wells were drilled on 640-acre spacing units and are trending above a 350 MBOE type curve, which indicates returns should be competitive with Niobrara “A” and “B” wells drilled on 960-acre spacing units with an estimated 450 MBOE EUR per well.
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2014 and 2013.
| Three Months Ended | ||||||||||
| December 31, | ||||||||||
Production | 2014 | 2013 | Change | |||||||
| Oil (MMBbl) | 9.70 | 7.35 | 32 | % | ||||||
| NGLs (MMBbl) | 0.94 | 0.75 | 25 | % | ||||||
| Natural gas (Bcf) | 8.65 | 7.14 | 21 | % | ||||||
| Total equivalent (MMBOE) | 12.08 | 9.29 | 30 | % | ||||||
Average sales price | ||||||||||
| Oil (per Bbl): | ||||||||||
| Price received | $ | 61.84 | $ | 86.77 | (29 | %) | ||||
| Effect of crude oil hedging(1) | 5.19 | (0.64 | ) | |||||||
| Realized price | $ | 67.03 | $ | 86.13 | (22 | %) | ||||
| Weighted average NYMEX price (per Bbl) (2) | $ | 71.80 | $ | 97.46 | (26 | %) | ||||
NGLs (per Bbl): | ||||||||||
| Realized price | $ | 32.60 | $ | 44.89 | (27 | %) | ||||
Natural gas (per Mcf): | ||||||||||
| Realized price | $ | 4.89 | $ | 4.44 | 10 | % | ||||
| Weighted average NYMEX price (per Mcf) (2) | $ | 4.06 | $ | 3.61 | 12 | % | ||||
| (1) | Whiting received $50 million and paid $5 million in pre-tax cash settlements on its crude oil hedges during the fourth quarter of 2014 and 2013, respectively. A summary of Whiting’s outstanding hedges is included later in this news release. | |
| (2) | Average NYMEX prices weighted for monthly production volumes. | |
Fourth Quarter and Full-Year 2014 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
| Three Months Ended | Year Ended | |||||||||||||
| December 31, | December 31, | |||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||
| (per BOE, except production) | ||||||||||||||
| Production (MMBOE) | 12.08 | 9.29 | 41.80 | 34.34 | ||||||||||
| Sales price, net of hedging | $ | 59.86 | $ | 75.18 | $ | 73.38 | $ | 76.76 | ||||||
| Lease operating expense | 11.57 | 12.51 | 11.89 | 12.53 | ||||||||||
| Production tax | 4.56 | 6.37 | 6.05 | 6.56 | ||||||||||
| General & administrative(1) | 5.98 | 3.18 | 4.24 | 4.02 | ||||||||||
| Exploration | 3.08 | 2.49 | 2.08 | 2.76 | ||||||||||
| Cash interest expense | 3.91 | 4.17 | 3.80 | 2.93 | ||||||||||
| Cash income tax expense (benefit) | (0.42 | ) | (0.45 | ) | 0.06 | 0.03 | ||||||||
| $ | 31.18 | $ | 46.91 | $ | 45.26 | $ | 47.93 | |||||||
| (1) | For the three and twelve months ended December 31, 2014, the cost includes $3.38 per BOE and $1.26 per BOE, respectively, for transaction-related costs incurred for the Kodiak Acquisition. | |
Outlook for First Quarter and Full-Year 2015
The following table provides guidance for the first quarter and full-year 2015 based on current forecasts, including Whiting’s full-year 2015 capital budget of $2.0 billion.
| Guidance | |||||
| First Quarter | Full-Year | ||||
| 2015 | 2015 | ||||
| Production (MMBOE) | 14.45 - 14.85 | 59.00 - 59.70 | |||
| Lease operating expense per BOE | $ 11.00 - $ 11.60 | $ 10.90 - $ 11.30 | |||
| General and admin. expense per BOE | $ 2.90 - $ 3.10 | $ 2.90 - $ 3.10 | |||
| Interest expense per BOE | $ 4.80 - $ 5.20 | $ 5.00 - $ 5.40 | |||
| Depr., depletion and amort. per BOE | $ 20.50 - $ 21.50 | $ 21.00 - $ 22.00 | |||
| Prod. taxes (% of sales revenue) | 8.2% - 8.4% | 8.3% - 8.5% | |||
| Oil price differentials to NYMEX per Bbl (1) | ($ 8.50) - ($ 9.50) | ($ 8.50) - ($ 9.50) | |||
| Gas price premium to NYMEX per Mcf | $ 0.50 - $ 1.00 | $ 0.50 - $ 1.00 | |||
| (1) | Does not include the effect of NGLs. | |
Commodity Derivative Contracts
The following summarizes Whiting’s crude oil hedges as of February 13, 2015:
| Weighted Average | As a % of | |||||||
| Derivative | Hedge | Contracted Crude | NYMEX Price | December 2014 | ||||
| Instrument | Period | (Bbls per Month) | (per Bbl) | Oil Production | ||||
| Three-way collars (1) | 2015 | |||||||
| Q1 | 100,000 | $70.00 - $85.00 - $107.90 | 2.6% | |||||
| Q2 | 100,000 | $70.00 - $85.00 - $107.90 | 2.6% | |||||
| Q3 | 500,000 | $47.00 - $58.00 - $78.99 | 12.8% | |||||
| Q4 | 500,000 | $47.00 - $58.00 - $78.99 | 12.8% | |||||
| 2016 | ||||||||
| Q1 | 550,000 | $43.18 - $53.18 - $76.26 | 14.1% | |||||
| Q2 | 550,000 | $43.18 - $53.18 - $76.26 | 14.1% | |||||
| Q3 | 550,000 | $43.18 - $53.18 - $76.26 | 14.1% | |||||
| Q4 | 550,000 | $43.18 - $53.18 - $76.26 | 14.1% | |||||
| Collars | 2015 | |||||||
| Q1 | 9,000 | $85.00 - $102.75 | 0.2% | |||||
| Q2 | 9,100 | $85.00 - $102.75 | 0.2% | |||||
| Q3 | 209,200 | $51.06 - $57.37 | 5.4% | |||||
| Q4 | 209,200 | $51.06 - $57.37 | 5.4% | |||||
| 2016 | ||||||||
| Q1 | 250,000 | $51.00 - $63.48 | 6.4% | |||||
| Q2 | 250,000 | $51.00 - $63.48 | 6.4% | |||||
| Q3 | 250,000 | $51.00 - $63.48 | 6.4% | |||||
| Q4 | 250,000 | $51.00 - $63.48 | 6.4% | |||||
| 2017 | ||||||||
| Q1 | 250,000 | $53.00 - $70.44 | 6.4% | |||||
| Q2 | 250,000 | $53.00 - $70.44 | 6.4% | |||||
| Q3 | 250,000 | $53.00 - $70.44 | 6.4% | |||||
| Q4 | 250,000 | $53.00 - $70.44 | 6.4% | |||||
| Swaps | 2015 | |||||||
| Q1 | 335,700 | $93.33 | 8.6% | |||||
| Q2 | 339,430 | $93.33 | 8.7% | |||||
| Q3 | 259,160 | $76.57 | 6.7% | |||||
| Q4 | 251,230 | $76.25 | 6.5% |
| (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-differential crude oil sales contracts in place as of January 1, 2015:
| Differential | ||||
| Contracted Volume | from NYMEX | |||
| Period | (Bbls per Day) | (per Bbl) | ||
| 04/2015 to 12/2015 | 25,000 | $4.75 | ||
| 01/2016 to 12/2016 | 28,750 | $4.75 | ||
| 01/2017 to 12/2017 | 33,750 | $4.75 | ||
| 01/2018 to 12/2018 | 38,750 | $4.75 | ||
| 01/2019 to 12/2019 | 43,750 | $4.75 | ||
| 01/2020 to 03/2020 | 45,000 | $4.75 |
| Differential | ||||
| Contracted Volume | from NYMEX(1) | |||
| Period | (Bbls per Day) | (per Bbl) | ||
| 04/2015 to 12/2015 | 20,000 | $ 5.00 - $6.00 | ||
| 01/2016 to 12/2016 | 20,000 | $ 5.00 - $6.00 | ||
| 01/2017 to 12/2017 | 20,000 | $ 5.00 - $6.00 | ||
| 01/2018 to 12/2018 | 20,000 | $ 5.00 - $6.00 | ||
| 01/2019 to 12/2019 | 20,000 | $ 5.00 - $6.00 | ||
| 01/2020 to 03/2020 | 20,000 | $ 5.00 - $6.00 | ||
| (1) | The future production volumes in the table above will be sold at a price equal to NYMEX less certain fixed differentials depending on the delivery methods specified in the contract. Based on prevailing storage and transportation costs, we estimate a fixed differential of $5.00 to $6.00 per barrel below NYMEX. | |
Selected Operating and Financial Statistics
| Three Months Ended | Year Ended | ||||||||||||||||
| December 31, | December 31, | ||||||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||||||
| Selected operating statistics: | |||||||||||||||||
| Production | |||||||||||||||||
| Oil, MBbl | 9,697 | 7,348 | 33,485 | 27,035 | |||||||||||||
| NGLs, MBbl | 937 | 751 | 3,283 | 2,821 | |||||||||||||
| Natural gas, MMcf | 8,650 | 7,138 | 30,219 | 26,915 | |||||||||||||
| Oil equivalents, MBOE | 12,076 | 9,289 | 41,804 | 34,342 | |||||||||||||
| Average prices | |||||||||||||||||
| Oil per Bbl (excludes hedging) | $ | 61.84 | $ | 86.77 | $ | 81.50 | $ | 90.39 | |||||||||
| NGLs per Bbl | $ | 32.60 | $ | 44.89 | $ | 39.17 | $ | 40.41 | |||||||||
| Natural gas per Mcf | $ | 4.89 | $ | 4.44 | $ | 5.53 | $ | 4.04 | |||||||||
| Per BOE data | |||||||||||||||||
| Sales price (including hedging) | $ | 59.86 | $ | 75.18 | $ | 73.38 | $ | 76.76 | |||||||||
| Lease operating | $ | 11.57 | $ | 12.51 | $ | 11.89 | $ | 12.53 | |||||||||
| Production taxes | $ | 4.56 | $ | 6.37 | $ | 6.05 | $ | 6.56 | |||||||||
| Depreciation, depletion and amortization | $ | 24.85 | $ | 26.63 | $ | 26.06 | $ | 25.96 | |||||||||
| General and administrative(1)(2) | $ | 5.98 | $ | 3.18 | $ | 4.24 | $ | 4.02 | |||||||||
Selected financial data: | |||||||||||||||||
(In thousands, except per share data) | |||||||||||||||||
| Total revenues and other income | $ | 696,095 | $ | 720,460 | $ | 3,085,097 | $ | 2,828,385 | |||||||||
| Total costs and expenses | $ | 1,240,383 | $ | 799,611 | $ | 2,941,182 | $ | 2,256,514 | |||||||||
| Net income (loss) available to common shareholders | $ | (353,681 | ) | $ | (59,265 | ) | $ | 64,807 | $ | 365,517 | |||||||
| Earnings (loss) per common share, basic | $ | (2.69 | ) | $ | (0.50 | ) | $ | 0.53 | $ | 3.09 | |||||||
| Earnings (loss) per common share, diluted | $ | (2.68 | ) | $ | (0.50 | ) | $ | 0.53 | $ | 3.06 | |||||||
Weighted average shares outstanding, basic | 131,535 | 118,656 | 122,138 | 118,260 | |||||||||||||
| Weighted average shares outstanding, diluted | 131,839 | 118,656 | 122,519 | 119,588 | |||||||||||||
| Net cash provided by operating activities | $ | 465,996 | $ | 490,618 | $ | 1,815,302 | $ | 1,744,745 | |||||||||
| Net cash used in investing activities | $ | (780,668 | ) | $ | (560,744 | ) | $ | (2,860,517 | ) | $ | (1,902,499 | ) | |||||
| Net cash provided by (used in) financing activities | $ | 364,719 | $ | (255,993 | ) | $ | 423,855 | $ | 812,414 | ||||||||
| (1) | For the twelve months ended December 31, 2013, the cost includes the effect of a charge under our Production Participation Plan (the “Plan”) related to the sale of the Postle Properties of $0.63 per BOE. The Plan was terminated in June 2014 with an effective date of December 31, 2013. | |
| (2) | For the three and twelve months ended December 31, 2014, the cost includes $3.38 per BOE and $1.26 per BOE, respectively, for transaction-related costs incurred for the Kodiak Acquisition. | |
Selected Financial Data
For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2014, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION | ||||||||
| December 31, | December 31, | |||||||
| 2014 | 2013 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 78,100 | $ | 699,460 | ||||
| Accounts receivable trade, net | 543,172 | 341,177 | ||||||
| Derivative assets | 135,577 | 1,274 | ||||||
| Prepaid expenses and other | 86,150 | 27,707 | ||||||
| Total current assets | 842,999 | 1,069,618 | ||||||
| Property and equipment: | ||||||||
| Oil and gas properties, successful efforts method | 14,949,702 | 10,065,150 | ||||||
| Other property and equipment | 276,582 | 206,385 | ||||||
| Total property and equipment | 15,226,284 | 10,271,535 | ||||||
| Less accumulated depreciation, depletion and amortization | (3,083,572 | ) | (2,676,490 | ) | ||||
| Total property and equipment, net | 12,142,712 | 7,595,045 | ||||||
| Goodwill | 875,676 | - | ||||||
| Debt issuance costs | 53,274 | 48,530 | ||||||
| Other long-term assets | 104,843 | 120,277 | ||||||
| TOTAL ASSETS | $ | 14,019,504 | $ | 8,833,470 | ||||
WHITING PETROLEUM CORPORATION | ||||||
| December 31, | December 31, | |||||
| 2014 | 2013 | |||||
| LIABILITIES AND EQUITY | ||||||
| Current liabilities: | ||||||
| Accounts payable trade | $ | 62,664 | $ | 107,692 | ||
| Accrued capital expenditures | 429,970 | 158,739 | ||||
| Revenues and royalties payable | 254,018 | 198,558 | ||||
| Current portion of Production Participation Plan liability | 113,391 | 73,264 | ||||
| Accrued liabilities and other | 169,193 | 144,327 | ||||
| Taxes payable | 63,822 | 50,052 | ||||
| Accrued interest | 67,913 | 44,405 | ||||
| Deferred income taxes | 47,545 | 648 | ||||
| Total current liabilities | 1,208,516 | 777,685 | ||||
| Long-term debt | 5,628,782 | 2,653,834 | ||||
| Deferred income taxes | 1,230,630 | 1,278,030 | ||||
| Production Participation Plan liability | - | 87,503 | ||||
| Asset retirement obligations | 167,741 | 116,442 | ||||
| Deferred gain on sale | 60,305 | 79,065 | ||||
| Other long-term liabilities | 20,486 | 4,212 | ||||
| Total liabilities | 8,316,460 | 4,996,771 | ||||
| Commitments and contingencies | ||||||
| Equity: | ||||||
Common stock, $0.001 par value, 300,000,000 shares authorized; | 168 | 120 | ||||
| Additional paid-in capital | 3,385,094 | 1,583,542 | ||||
| Retained earnings | 2,309,712 | 2,244,905 | ||||
| Total Whiting shareholders' equity | 5,694,974 | 3,828,567 | ||||
| Noncontrolling interest | 8,070 | 8,132 | ||||
| Total equity | 5,703,044 | 3,836,699 | ||||
| TOTAL LIABILITIES AND EQUITY | $ | 14,019,504 | $ | 8,833,470 | ||
WHITING PETROLEUM CORPORATION | ||||||||||||||||
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| REVENUES AND OTHER INCOME: | ||||||||||||||||
| Oil, NGL and natural gas sales | $ | 672,553 | $ | 703,024 | $ | 3,024,617 | $ | 2,666,549 | ||||||||
| Loss on hedging activities | - | (645 | ) | - | (1,958 | ) | ||||||||||
| Amortization of deferred gain on sale | 7,588 | 8,057 | 30,494 | 31,737 | ||||||||||||
| Gain on sale of properties | 15,352 | 8,942 | 27,657 | 128,648 | ||||||||||||
| Interest income and other | 602 | 1,082 | 2,329 | 3,409 | ||||||||||||
| Total revenues and other income | 696,095 | 720,460 | 3,085,097 | 2,828,385 | ||||||||||||
| COSTS AND EXPENSES: | ||||||||||||||||
| Lease operating | 139,703 | 116,157 | 496,925 | 430,221 | ||||||||||||
| Production taxes | 55,015 | 59,175 | 253,008 | 225,403 | ||||||||||||
| Depreciation, depletion and amortization | 300,113 | 247,381 | 1,089,545 | 891,516 | ||||||||||||
| Exploration and impairment | 750,886 | 325,445 | 854,430 | 453,210 | ||||||||||||
| General and administrative | 72,252 | 29,528 | 177,211 | 137,994 | ||||||||||||
| Interest expense | 49,821 | 43,357 | 170,642 | 112,936 | ||||||||||||
| Loss on early extinguishment of debt | - | 4,412 | - | 4,412 | ||||||||||||
| Change in Production Participation Plan liability | - | (8,312 | ) | - | (6,980 | ) | ||||||||||
| Commodity derivative (gain) loss, net | (127,407 | ) | (17,532 | ) | (100,579 | ) | 7,802 | |||||||||
| Total costs and expenses | 1,240,383 | 799,611 | 2,941,182 | 2,256,514 | ||||||||||||
| INCOME BEFORE INCOME TAXES | (544,288 | ) | (79,151 | ) | 143,915 | 571,871 | ||||||||||
| INCOME TAX EXPENSE (BENEFIT): | ||||||||||||||||
| Current | (5,070 | ) | (4,145 | ) | 2,625 | 986 | ||||||||||
| Deferred | (185,525 | ) | (15,730 | ) | 76,545 | 204,882 | ||||||||||
| Total income tax expense (benefit) | (190,595 | ) | (19,875 | ) | 79,170 | 205,868 | ||||||||||
| NET INCOME (LOSS) | (353,693 | ) | (59,276 | ) | 64,745 | 366,003 | ||||||||||
| Net loss attributable to noncontrolling interests | 12 | 11 | 62 | 52 | ||||||||||||
| NET INCOME (LOSS) AVAILABLE TO SHAREHOLDERS | (353,681 | ) | (59,265 | ) | 64,807 | 366,055 | ||||||||||
| Preferred stock dividends | - | - | - | (538 | ) | |||||||||||
| NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS | $ | (353,681 | ) | $ | (59,265 | ) | $ | 64,807 | $ | 365,517 | ||||||
| EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||||
| Basic | $ | (2.69 | ) | $ | (0.50 | ) | $ | 0.53 | $ | 3.09 | ||||||
| Diluted | $ | (2.68 | ) | $ | (0.50 | ) | $ | 0.53 | $ | 3.06 | ||||||
| WEIGHTED AVERAGE SHARES OUTSTANDING: | ||||||||||||||||
| Basic | 131,535 | 118,656 | 122,138 | 118,260 | ||||||||||||
| Diluted | 131,839 | 118,656 | 122,519 | 119,588 | ||||||||||||
WHITING PETROLEUM CORPORATION | ||||||||||||||||
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net income (loss) available to common shareholders | $ | (353,681 | ) | $ | (59,265 | ) | $ | 64,807 | $ | 365,517 | ||||||
| Adjustments net of tax: | ||||||||||||||||
| Amortization of deferred gain on sale | (4,776 | ) | (5,088 | ) | (19,196 | ) | (20,042 | ) | ||||||||
| Gain on sale of properties | (9,664 | ) | (5,647 | ) | (17,410 | ) | (81,241 | ) | ||||||||
| Impairment expense | 449,245 | 190,918 | 483,221 | 226,365 | ||||||||||||
|
Transaction-related costs for Kodiak Acquisition | 25,745 | - | 33,166 | - | ||||||||||||
| Early extinguishment of debt | - | 2,786 | - | 2,786 | ||||||||||||
|
Charge under Production Participation Plan related to sale of Postle properties | - | - | - | 15,114 | ||||||||||||
|
Change in Production Participation Plan liability | - | (5,249 | ) | - | (4,408 | ) | ||||||||||
| Total measure of derivative (gain) loss reported under U.S. GAAP | (80,203 | ) | (10,664 | ) | (63,314 | ) | 6,164 | |||||||||
| Total net cash settlements paid on commodity derivatives during the period | 31,652 | (2,957 | ) | 27,140 | (19,318 | ) | ||||||||||
| Adjusted net income (1) | $ | 58,318 | $ | 104,834 | $ | 508,414 | $ | 490,937 | ||||||||
| Adjusted net income available to common shareholders per share, basic | $ | 0.44 | $ | 0.88 | $ | 4.16 | $ | 4.15 | ||||||||
| Adjusted net income available to common shareholders per share, diluted | $ | 0.44 | $ | 0.88 | $ | 4.15 | $ | 4.11 | ||||||||
| (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. | |
WHITING PETROLEUM CORPORATION | |||||||||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||||||||||
| Net cash provided by operating activities | $ | 465,996 | $ | 490,618 | $ | 1,815,302 | $ | 1,744,745 | |||||||||||||
| Exploration | 37,231 | 23,120 | 86,803 | 94,755 | |||||||||||||||||
| Exploratory dry hole costs | (22,355 | ) | (7,575 | ) | (26,327 | ) | (28,725 | ) | |||||||||||||
| Changes in working capital | (61,392 | ) | (48,610 | ) | 120,083 | (60,224 | ) | ||||||||||||||
| Preferred dividends paid | - | - | - | (538 | ) | ||||||||||||||||
| Discretionary cash flow(1) | $ | 419,480 | $ | 457,553 | $ | 1,995,861 | $ | 1,750,013 | |||||||||||||
| (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, February 26, 2015 at 11:00 a.m. EST (10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting’s fourth quarter 2014 financial and operating results. Please call 1-866-777-2509 (U.S.); 1-866-450-4696 (Canada) or 1-412-317-5413 (International) to be connected to the call. Access to a live internet broadcast will be available at http://www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EST) on February 26, 2015.
A replay will be available on Thursday, February 26, 2015 and continuing through Thursday, March 6, 2015. You may access this replay at 1-877-344-7529 (U.S.); 1-855-669-9658 (Canada) or 1-412-317-0088 (International) and entering the pass code 10060090.
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.
Canadian Securities Law Disclosure
In connection with Whiting’s acquisition of Kodiak, it became subject to certain Canadian securities law disclosure requirements; however, pursuant to a decision (the "Decision") of the Alberta securities commission, Whiting has been granted exemptive relief from the disclosure requirements contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), including the obligation to file Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information, Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor and Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure. In lieu of such filings, the Decision permits Whiting to provide disclosure with respect to its oil and gas activities in accordance with the disclosure requirements applicable to Whiting imposed by the United States Securities Exchange Commission (the "SEC"), the United States Securities Exchange Act of 1933, the United States Securities Exchange Act of 1934, the United States Sarbanes-Oxley Act of 2002 and the rules of the New York Stock Exchange (collectively, the "U.S. Rules").
Readers should be aware that Whiting’s future disclosure relating to its oil and gas activities will comply with the U.S. Rules rather than NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The U.S. Rules differ in a number of respects from the disclosure otherwise required under NI 51-101 and the Canadian Oil and Gas Evaluation Handbook and readers are urged to consider these differences when considering all future disclosures made by Whiting relating to its oil and gas activities.
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.
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; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our amended 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; 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; regulation and other factors; 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 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; 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; 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; our ability to successfully integrate Kodiak after the Kodiak Acquisition and achieve anticipated benefits from the transaction; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2013 and in our quarterly report on Form 10-Q for the period ended September 30, 2014. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
Disclosure Regarding Reserves and Resources
Whiting uses in this news release the terms proved, probable and possible reserves. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.
Whiting uses in this news release the term “total resources,” which consists of contingent and prospective resources, which SEC rules prohibit in filings of U.S. registrants. Contingent resources are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.
Contacts:
John B. Kelso, 303-837-1661
Director
of Investor Relations
john.kelso@whiting.com
