Attached files
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| 8-K - WHITING PETROLEUM CORPORATION FORM 8-K, DATED FEBRUARY 23, 2011 - WHITING PETROLEUM CORP | form8-k.htm |
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Company contact:
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John B. Kelso, Director of Investor Relations
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303.837.1661 or john.kelso@whiting.com
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Whiting Petroleum Corporation Announces Fourth Quarter and
Full-Year 2010 Financial and Operating Results
2010 Production Up 16% Over 2009 to a Record 23.60 MMBOE
Q4 2010 Production Up 3% Over Q3 2010 to a Record 67.9 BOE/D
Company Increases Proved Reserves 11% to a Record
304.9 MMBOE at Year-End 2010
Replaces 228% of 2010 Production
Company Reports Q4 2010 Net Income Available to Common
Shareholders of $65.9 Million or $0.56 per Diluted Share and
Adjusted Net Income of $99.0 Million or $0.84 per Diluted Share
NOTE: All share and per share amounts in this news release reflect
the Company’s 2-for-1 stock split effective February 22, 2011
Q4 2010 Discretionary Cash Flow Totals $277.2 Million
2011 Capital Budget of $1.350 Billion for 238-Well Drilling Program
DENVER – February 23, 2011 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2010 totaled a record 6.25 million barrels of oil equivalent (MMBOE), of which 5.03 million barrels were crude oil/natural gas liquids (80%) and 1.22 MMBOE was natural gas (20%). This fourth quarter 2010 production total equates to a new record daily average production rate of 67,900 barrels of oil equivalent (BOE), which represents a 20% increase over the 56,710 BOE average daily rate in the fourth quarter of 2009. Compared to the third quarter of 2010, production rose 3%.
Production in 2010 totaled a record 23.60 MMBOE, or 64,650 BOE per day, compared to 20.27 MMBOE, or 55,530 BOE per day, in 2009. The 16% increase in production for 2010 versus 2009 was primarily the result of organic production growth in the North Dakota Bakken and Three Forks formations as well as the continued response from Whiting’s two CO2 enhanced oil recovery (EOR) projects.
Financial Results
Discretionary cash flow in the fourth quarter of 2010 totaled $277.2 million, representing an increase of 49% over the $185.5 million reported for the same period in 2009. The increase in discretionary cash flow in the fourth quarter of 2010 versus the comparable 2009 period was primarily the result of the Company’s 20% production increase and a 14% increase in the Company’s realized oil price (net of hedging), including the price of natural gas liquids (NGLs). For the year ended December 31, 2010, Whiting’s discretionary cash flow totaled $949.3 million, an 85% increase from the $513.0 million in 2009. A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.
In the fourth quarter of 2010, Whiting reported net income available to common shareholders of $65.9 million, or $0.56 per basic and diluted share, on total revenues of $413.5 million. This compares to a fourth quarter 2009 loss available to common shareholders of $11.2 million, or $0.12 per basic and diluted share, on total revenues of $316.0 million. All share and per share amounts in this news release have been retroactively restated for all periods presented to reflect the Company’s February 22, 2011 two-for-one stock split, as discussed later in this news release.
The Company’s 2010 fourth quarter results include after-tax unrealized derivative losses of $26.1 million, or $0.22 per diluted share. Excluding this loss and certain other items, Whiting reported fourth quarter 2010 adjusted net income available to common shareholders of $99.0 million, or $0.85 per basic share and $0.84 per diluted share. This compared to fourth quarter 2009 adjusted net income available to common shareholders of $35.5 million, or $0.35 per basic and diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is included later in this news release.
For the year ended December 31, 2010, Whiting reported net income available to common shareholders of $272.7 million, or $2.57 per basic share and $2.55 per diluted share, on total revenues of $1,516.1 million. This compares to a 2009 loss available to common shareholders of $117.2 million, or $1.18 per basic and diluted share, on total revenues of $979.4 million.
Excluding after-tax unrealized derivative gains and losses and certain other items, Whiting reported adjusted net income available to common shareholders in 2010 of $304.7 million, or $2.99 per basic share and $2.71 per diluted share. This compared to adjusted net income available to common shareholders of $28.4 million, or $0.27 per basic and diluted share, in 2009.
2
Proved Reserves at December 31, 2010
As of December 31, 2010, Whiting had estimated proved reserves of 304.9 MMBOE, of which 71% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $5,044.4 million, of which approximately 96% came from properties located in Whiting’s Permian Basin, Rocky Mountains and Mid-Continent core areas. The following table summarizes Whiting’s estimated proved reserves as of December 31, 2010 by core area, the corresponding pre-tax PV10% value and the fourth quarter 2010 average daily production rate:
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Proved Reserves (1)
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Core Area
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Oil (MMBbl)(2)
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Natural Gas (Bcf)
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Total (MMBOE)
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% Oil(2)
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Pre-Tax PV10% Value(3)
(In millions)
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Q4 2010
Average Daily Production (MBOE/d)
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Permian Basin
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115.6 | 47.9 | 123.6 | 94 | % | $ | 1,471.5 | 12.2 | ||||||||||||||||
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Rocky Mountains
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94.5 | 162.8 | 121.6 | 78 | % | $ | 2,425.5 | 40.8 | ||||||||||||||||
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Mid-Continent
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38.2 | 19.9 | 41.5 | 92 | % | $ | 955.2 | 9.3 | ||||||||||||||||
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Gulf Coast
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3.2 | 36.9 | 9.4 | 34 | % | $ | 113.3 | 2.7 | ||||||||||||||||
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Michigan
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2.8 | 36.0 | 8.8 | 32 | % | $ | 78.9 | 2.9 | ||||||||||||||||
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Total
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254.3 | 303.5 | 304.9 | 83 | % | $ | 5,044.4 | 67.9 | ||||||||||||||||
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(1)
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Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month NYMEX price for each month within the 12 months ended December 31, 2010, pursuant to SEC and FASB guidelines. The NYMEX prices used were $79.43/Bbl and $4.38/Mcf.
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(2)
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Oil includes natural gas liquids.
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(3)
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Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable 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, 2010, our discounted future income taxes were $1,376.8 million and our standardized measure of after-tax discounted future net cash flows was $3,667.6 million. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil and natural gas reserves.
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3
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2010:
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Oil (MBbl)
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Natural Gas (MMcf)
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Total (MBOE)
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Balance – December 31, 2009
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223,796 | 307,393 | 275,029 | |||||||||
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Extensions and discoveries
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29,434 | 23,135 | 33,290 | |||||||||
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Sales of minerals in place
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(225 | ) | (500 | ) | (308 | ) | ||||||
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Purchases of minerals in place
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505 | 1,526 | 759 | |||||||||
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Production
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(19,031 | ) | (27,392 | ) | (23,596 | ) | ||||||
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Revisions to previous estimates
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19,799 | (618 | ) | 19,695 | (1) | |||||||
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Balance – December 31, 2010
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254,278 | 303,544 | 304,869 | |||||||||
(1) Of the 19.7 MMBOE of upward revisions, 15.4 MMBOE were due to commodity prices and 4.3 MMBOE were the result of well performance and new data. The liquids component of the net 4.3 MMBOE revision consisted of a 7.4 MMBOE increase that was primarily related to the Sanish field, where reserve assignments for proved developed producing as well as proved undeveloped well locations were adjusted upward to reflect the current performance of producing wells. The gas component of the net 4.3 MMBOE revision consisted of a 3.1 MMBOE decrease that was primarily related to the Beall East field, where three proved undeveloped locations were removed from our proved reserve estimate since those wells are not planned to be drilled due to low gas prices.
Whiting’s proved reserves as of December 31, 2010 totaled 304.9 MMBOE, which represents an 11% increase over the 275.0 MMBOE of proved reserves at year-end 2009. An estimated 33.3 MMBOE of proved reserves were added through exploration and development activities. In total, Whiting replaced 228% of its 2010 production of 23.6 MMBOE with 53.7 MMBOE (33.290 + 0.759 + 19.695 = 53.744 MMBOE) of proved reserve additions at an all-in finding and development cost of $20.51 per BOE ($1.102 billion / 53.744 = $20.51). The table at the end of this news release summarizes Whiting’s all-in finding and development costs and reserve replacement for the two-year period ended December 31, 2010.
Proved developed reserves as a component of our total proved reserves increased this year. Our total proved reserves were up 29.8 MMBOE or 11% and our proved developed reserves were up 40.6 MMBOE or 23% from year-end 2009. The proved developed portion of our proved reserve base was 71% at year-end 2010 compared to 64% at year-end 2009.
The increase in proved developed reserves was primarily attributable to the proved undeveloped (PUD) reserves that were converted to proved developed at the Sanish and North Ward Estes fields. This drilling also caused more PUD locations to be added in the Sanish field. The Sanish PUD conversion was the result of our active drilling program in that field during 2010. The PUD conversion at North Ward Estes was due to the continuing expansion of our CO2 enhanced recovery project in that field. There were 25.8 MMBOE of PUDs that were converted into proved developed reserves due to 71 proved undeveloped gross well locations (58 at Sanish field, seven at Flat Rock field and six elsewhere) that were drilled and placed on production during 2010. We incurred $208.7 million in capital expenditures, or $8.09 per BOE, to drill and bring on-line these 71 PUD locations. In addition, there were approximately 18.2 MMBOE of PUDs that became proved developed reserves in 2010 at our CO2 enhanced recovery projects in the Postle and North Ward Estes fields. These PUDs were converted to proved developed at an average cost over two years of approximately $15.11 per BOE ($486.34 million in 2009-2010 / 13.97 MMBOE (2009) + 18.22 MMBOE (2010) = $15.11 per BOE).
4
Most of the proved reserve additions during 2010 came from the Company’s Bakken and Three Forks development in the Sanish field in Mountrail County, North Dakota. An estimated 24.1 MMBOE of new Bakken and Three Forks proved reserves were booked at year-end 2010, bringing Whiting’s total proved reserves in the Sanish and Parshall fields to 66.4 MMBOE at year-end 2010. Of this 66.4 MMBOE, 68% were proved, developed and producing, 32% were proved undeveloped, 88% were attributed to the Sanish field and 12% to Whiting’s interests in the Parshall field. The Company’s net production from the Sanish and Parshall fields in 2010 totaled approximately 9.4 MMBOE, or 40% of the Company’s total production of 23.6 MMBOE.
Probable and Possible Reserves at December 31, 2010
At year-end 2010, Whiting’s probable reserves were estimated to be 100 MMBOE and our possible reserves were estimated to be 217 MMBOE, for a total of 317 MMBOE. This total represents an increase of 11% over the 287 MMBOE estimate at year-end 2009. The EOR project at our North Ward Estes field represented 130 MMBOE of the 317 MMBOE total, or 41%. The probable and possible reserves attributable to North Ward Estes are associated with Whiting’s election at year-end 2009 to expand the scope of its CO2 project in the field to include eight phases, up from four phases previously. In order to fully develop the EOR probable and possible reserves at North Ward Estes, we will need to utilize significant quantities of purchased CO2. We are currently in negotiations and planning for future sources capable of generating sufficient CO2 quantities to carry out the development of all probable and possible reserves at North Ward Estes.
The other primary contributors to Whiting’s probable and possible reserve estimates were additional Bakken and Three Forks reserves in the Williston Basin with 75 MMBOE and the Sulphur Creek gas field in the Piceance Basin with 32 MMBOE, which could be captured with an additional 225 down-spaced wells drilled on 20- and 10-acre spacing. As with our proved reserves, 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.
5
Resource Potential at December 31, 2010
Whiting has internally estimated its unrisked total resource potential to be 374 MMBOE at year-end 2010, representing a 123% increase from the 168 MMBOE estimate at year-end 2009. The largest contributor to this 374 MMBOE total was continued Bakken and Three Forks exploration in North Dakota and Montana with 149 MMBOE. An estimated 149 MMBOE was attributable to other exploration projects in Colorado, Michigan, North Dakota, Texas, Utah and Wyoming. Also contributing was our Niobrara exploration project in the Denver Julesburg Basin of Colorado with an estimated 42 MMBOE and our Sulphur Creek gas field in the Piceance Basin of Colorado with 34 MMBOE. The resource potential at Sulphur Creek is contingent on higher natural gas prices of approximately $6.00 per Mcf. Please refer to “Disclosure Regarding Reserves and Resources” later in this news release for information on resource potential.
James J. Volker, Whiting’s Chairman and CEO, commented, “2010 was an exceptional year for Whiting Petroleum and our shareholders. In 2010, we generated 33.3 MMBOE of reserve additions through the drillbit, replacing 141% of our record 2010 production of 23.6 MMBOE. We also generated 20.5 MMBOE of reserve additions through upward revisions and acquisitions, replacing an additional 87% of our 2010 production. We expect our organic growth to continue in 2011. We have a 238-well drilling program planned for 2011 and have substantially added to our drilling inventory primarily through a very active leasing program in 2010. In the Bakken and Three Forks hydrocarbon system in the Williston Basin alone, we hold 580,000 net acres and continue to add to that position. Importantly, our average cost in this acreage is $243 per net acre. Our geoscientists have been able to identify prospective areas ahead of the crowd. Our Land Department has taken leases quickly. Therefore, we have not paid an exorbitant cover charge to enter the Bakken / Three Forks play. This also holds true for our Niobrara acreage in the Denver Julesburg Basin as well as our acreage in the Delaware Basin of West Texas that we believe is prospective in a number of zones, including the Wolfcamp and Bone Spring.”
Mr. Volker continued, “We believe that the combination of our drilling plays and our two EOR projects provides a diversified mix of organic growth opportunities and long-term, reliable cash flow. We also believe that our EOR project at the North Ward Estes field in the Permian Basin offers significant upside for reserves and production growth at a reasonable cost. We plan to continue to focus on oil in the foreseeable future. At year-end 2010, 83% of our proved reserves consisted of oil and natural gas liquids. We expect that percentage to increase over the next several years. We delivered our results in 2010 by focusing on our Bakken drilling program and our two EOR projects. In 2011, another focus will be the further development of our Lewis & Clark resource play. With these key projects, we are optimistic about Whiting’s operational results in 2011 and beyond.”
6
2011 Capital Budget
Our current 2011 capital budget is $1,350.0 million, which we expect to fund substantially all with net cash provided by our operating activities. The 2011 capital budget represents a 38% increase from the $978.3 million incurred on exploration, development and acreage expenditures during 2010. Acreage acquisition costs increased during 2010 to $155.5 million. We anticipate investing at least $110.0 million in acreage acquisitions during 2011 and have therefore included this category in our 2011 capital budget. To the extent net cash provided by operating activities is higher or lower than currently anticipated, we would adjust our capital budget accordingly or use a portion of our available capacity under our bank credit agreement. Our 2011 capital budget currently is allocated among our major development areas as indicated in the table below:
7
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2011 Planned
Capital Expenditures
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Planned Wells
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Gross
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Net
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Northern Rockies
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Sanish Field
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$ | 352 | 95 | 54 | ||||||||
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Parshall Field
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$ | 12 | 11 | 2 | ||||||||
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Lewis & Clark Area
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$ | 278 | 51 | 30 | ||||||||
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Other Northern Rockies
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$ | 65 | 23 | 14 | ||||||||
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Subtotal
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$ | 707 | 180 | 100 | ||||||||
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EOR Projects
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North Ward Estes
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$ | 201 | -- | -- | ||||||||
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Postle
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$ | 113 | -- | -- | ||||||||
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Subtotal
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$ | 314 | -- | -- | ||||||||
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Permian Basin
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Big Tex
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$ | 89 | 23 | 23 | ||||||||
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Other Permian
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$ | 3 | 23 | 23 | ||||||||
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Subtotal
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$ | 92 | 46 | 46 | ||||||||
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Central Rockies
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Redtail
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$ | 35 | 6 | 6 | ||||||||
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Other Central Rockies
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$ | 17 | 4 | 3 | ||||||||
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Subtotal
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$ | 52 | 10 | 9 | ||||||||
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Gulf Coast
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Various
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$ | 2 | 1 | 1 | ||||||||
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Michigan
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PDC Expl. & Dvlp.
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$ | 5 | 1 | 1 | ||||||||
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Other, Exploration
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$ | 11 | -- | -- | ||||||||
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Other, Non-Operated
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$ | 17 | -- | -- | ||||||||
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Exploration Expense (1)
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$ | 40 | -- | -- | ||||||||
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Land
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$ | 110 | -- | -- | ||||||||
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Grand Total
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$ | 1,350 | 238 | 157 | ||||||||
(1) Comprised primarily of exploration salaries, lease delay rentals and seismic activities.
8
Operations Update
Core Development Areas
Bakken and Three Forks Development Increases Production
The following table summarizes the Company’s operated and non-operated net production from the Sanish and Parshall fields in the fourth quarter and in December 2010:
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Operated and Non-operated Net Production for Sanish and Parshall Fields
(In BOE)
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4th Qtr 2010
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December 2010
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Parshall
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Sanish
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Total
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Parshall
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Sanish
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Total
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Whiting Operated
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42,422 | 1,986,819 | 2,029,241 | 11,656 | 633,687 | 645,343 | ||||||||||||||||||
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Non-Operated
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376,420 | 172,193 | 548,613 | 123,538 | 56,629 | 180,167 | ||||||||||||||||||
| Total | 418,842 | 2,159,012 | 2,577,854 | 135,194 | 690,316 | 825,510 | ||||||||||||||||||
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Daily BOE
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4,555 | 23,465 | 28,020 | 4,360 | 22,270 | 26,630 | (1) | |||||||||||||||||
(1) Includes approximately 1,070 net BOE per day of NGLs and natural gas from plant operations.
Whiting’s net production from the Middle Bakken and Three Forks formations in the Sanish and Parshall fields of Mountrail County, North Dakota averaged 28,020 BOE per day in the fourth quarter of 2010, up 2% from the 27,385 BOE average daily rate in the third quarter of 2010 and up 50% from the 18,625 BOE average daily rate in the fourth quarter of 2009.
Sanish Field. Whiting owns 109,233 gross (66,537 net) acres in the Sanish field, located in Mountrail County, North Dakota. Whiting’s net production from the Sanish field in the fourth quarter of 2010 averaged 23,465 BOE per day, up 5% from the third quarter 2010 average rate of 22,275 BOE per day and up 96% over the fourth quarter 2009 average rate of 11,955 BOE per day. Our net production from the Sanish field averaged 22,270 BOE per day in December 2010, a 3% decrease from 22,935 BOE per day in September 2010. The decrease was due to well completion delays from inclement weather in North Dakota.
Based on results of the Company’s microseismic studies and reservoir pressure monitoring in both the Bakken and Three Forks formations, it appears that additional infill drilling is necessary to maximize recovery in the Sanish field. As a result, Whiting has increased by 153 the total number of gross operated wells that it expects to drill in the Sanish field to 535 gross wells from the 382 gross wells previously planned. Approximately 83 of these additional well locations are planned to be “wing wells,” which are expected to have 7,500-foot laterals and to be drilled primarily in the northeast and southwest portions of the field’s 1,280-acre units. Whiting has elected to drill three Three Forks wells per 1,280-acre unit as compared to its previous plan of two Three Forks wells per unit. This decision adds 80 potential gross well locations in the Sanish field. Including non-operated wells, Whiting estimates that more than 300 gross wells remain to be drilled in the Sanish field as of February 15, 2011.
9
In 2010, Whiting completed 65 operated Bakken wells and seven operated Three Forks wells in the Sanish field, bringing to 136 the number of Whiting-operated wells in the field as of December 31, 2010. Including non-operated wells, there were 197 producing wells in the Sanish field at year-end 2010. The Company plans to continue with its current nine operated drilling rig count in the Sanish field through 2012. In 2011, Whiting intends to drill 95 operated wells (54 net wells) in the field, of which 70 are planned Three Forks wells, 15 are cross-unit Bakken wells, seven are Bakken infill wells and three are wing wells. Whiting has contracted a full-time dedicated frac crew at Sanish that the Company estimates is capable of fracture stimulating 100 wells per year. As of February 15, 2011, 20 operated wells and four non-operated wells were being completed or awaiting completion and nine operated wells were being drilled in the Sanish field.
The average initial production rate for the 65 Bakken wells completed from January 1, 2010 through December 31, 2010 averaged 2,478 BOE per day, representing an 18% increase over the 2,102 BOE average initial production rate for wells completed prior to January 1, 2010. The average initial production rate for the seven Three Forks wells completed from January 1, 2010 through December 31, 2010 averaged 1,302 per day, representing a 29% increase over the 1,012 BOE average initial production rate for the three wells completed prior to January 1, 2010.
Whiting believes that additional frac stages have contributed to the higher initial production rates for wells completed in 2010. In 2010, the Company fracture stimulated its wells with between 15 and 30 separate fracs, averaging 21 frac stages per well. Prior to 2010, most of Whiting’s wells in the Sanish field were fraced in 10 stages. The Company is also using more proppant and frac fluid in its fracing operations. For a 30-stage frac, Whiting is currently using 30,000 to 45,000 barrels of frac fluid and 2.4 to 3.3 million pounds of sand. The Company recently ran a new sliding sleeve assembly in the Smith 14-29XH well in the Sanish field for a planned 40-stage frac. Further, Whiting was recently provided with a new down-hole assembly that is capable of performing up to 60 separate fracture stimulations within 20 intervals along the horizontal portion of the wellbore.
Whiting estimates that the total completed well costs for its most recently completed wells in the Sanish field will come in below $5.5 million per well. The last five wells that Whiting drilled in Sanish field reached a total measured depth of approximately 20,000 feet, including 10,000 feet of lateral, in an average of 22 days. The Company’s record from spud date to total depth is just under 14 days. The reduction in drilling time and associated costs is primarily the result of our “Drill Wells On Paper” (DWOP) program, which applies the best practices and best logistical planning of all our drilling and completion contractors to produce drilling and completion efficiencies. Prior to the implementation of our DWOP program in June 2009, it took an average of 38 days from spud date to total depth. With an average of 18 fewer days on location, we are saving approximately $900,000 per well in drilling costs.
10
The 17-mile oil line connecting the Sanish field to the Enbridge pipeline in Stanley, North Dakota is currently transporting approximately 27,200 barrels per day. This 8-inch diameter line has a daily capacity of approximately 65,000 barrels of oil per day. Whiting expects to have substantially all of its gross operated production in the pipeline by the second quarter of 2011. The Company is currently saving between $1.00 and $2.00 per barrel in transportation costs for each barrel that is being transported through the pipeline rather than being transported by truck. Enbridge Inc. added 30,000 barrels per day of take-away capacity to its pipeline in December 2010 by removing sour crude from its system, bringing the pipeline’s total take-away capacity to 160,000 barrels per day. Enbridge anticipates adding an incremental 25,000 barrels per day in February 2011 for a total of 185,000 barrels per day of take-away capacity. In early 2013, Enbridge is scheduled to add an incremental 145,000 barrels per day for a total off-take of 330,000 barrels per day. Based on all of the pipeline projects that have been announced to date, Whiting estimates that total take-away capacity from the Williston Basin should reach 1 million barrels per day by 2013.
Whiting’s Robinson Lake gas plant is currently processing 35.0 MMcf of gas per day (gross). The Company recently completed Phase II of the gas plant’s expansion, which brought the plant’s inlet capacity to 60 MMcf per day. Whiting expects capacity to be expanded to 90 MMcf per day in the third quarter of 2011. Whiting owns a 50% interest in the plant. The plant receives 25% of the net proceeds from third-party natural gas and NGLs processed at the plant. As of February 15, 2011, sales from the plant were 27.6 MMcf of gas and 4,168 barrels of NGLs per day, from which Whiting was netting 3.5 MMcf of gas and 521 barrels of NGLs per day due to its 50% plant ownership and the plant’s 25% net-of-proceeds contract.
Parshall Field. Immediately east of the Sanish field is the Parshall field, where we own interests in 73,082 gross acres (18,163 net acres). The Company’s net production from its interests in the Parshall field during the fourth quarter of 2010 averaged 4,555 BOE per day, a 32% decrease from the 6,675 BOE per day average in the fourth quarter of 2009. Our net production from the Parshall field averaged 4,360 BOE per day in December 2010, a 12% decrease from 4,960 BOE per day in September 2010. The operator of the Parshall field has drilled almost all of its Bakken locations and is currently pursuing a moderate pace of development of the Three Forks formation with a one rig program. As of February 15, 2011, we had participated in 127 wells at Parshall, all of which are producing.
11
Lewis & Clark Prospect Area. Whiting owns 360,516 gross and 234,938 net acres in the Lewis & Clark area, located in Golden Valley, Billings and Stark Counties, North Dakota. We hold a working interest in 250 1,280-acre spacing units. In 164 of the units, Whiting owns a controlling interest with an average working interest of 64%. We estimate two to four wells per 1,280-acre spacing unit to fully develop this area. We currently have five drilling rigs operating in this project, and five more rigs are scheduled to be added to the program before year-end 2011. Average drilling and completion costs for Lewis & Clark wells are currently at approximately $6.5 million. We believe that we can reduce those costs to between $5.0 million and $5.5 million by implementing our DWOP program in this area. In January 2011, we added a second full-time dedicated frac crew that will focus on the Lewis & Clark area.
Whiting completed six exploratory wells at Lewis & Clark in the second half of 2010. During a 24-hour test of the Three Forks formation at a vertical depth of approximately 10,500 feet on September 19, 2010, the Froehlich 44-9TFH flowed at a daily rate of 1,832 barrels of oil and 1,546 Mcf of gas, or 2,090 BOE per day. The well’s 9,730-foot lateral was fracture stimulated in a total of 28 stages, all using the “plug and perf” method. The Froehlich well produced at an average daily rate of 1,049 BOE during its first 30 days of production, 819 BOE during its first 60 days of production and 698 BOE during its first 90 days of production. Whiting, the operator of the well, holds a 90% working interest and a 73% net revenue interest in the new producer.
The Kubas 11-13TFH, located approximately five miles northeast of the Froehlich well, was tested on September 13, 2010 flowing at a daily rate of 1,780 barrels of oil and 1,035 Mcf of gas, or 1,953 BOE per day from the Three Forks formation. The Kubas well was fracture stimulated in a total of 29 stages, 21 stages using sliding sleeve technology and the remaining eight stages using the “plug and perf” method. The Kubas well produced at an average daily rate of 711 BOE during its first 30 days of production, 530 BOE during its first 60 days of production and 457 BOE during its first 90 days of production. Whiting operates the Kubas 11-13TFH, holding a working interest of 91% and a net revenue interest of 75%.
During a 24-hour test of the Three Forks formation on November 17, 2010, the Teddy 44-30TFH flowed at a daily rate of 1,557 barrels of oil and 1,901 Mcf of gas, or 1,874 BOE per day. The well’s approximate 10,000-foot lateral was fracture stimulated in a total of 30 stages, 22 stages using sliding sleeves and the remaining eight stages using the “plug and perf” method. The Teddy well produced at an average daily rate of 766 BOE during its first 30 days of production and 618 BOE during its first 60 days of production. Whiting, the operator of the well, holds an 88% working interest and a 72% net revenue interest in the new producer.
12
Whiting completed the Ellison Creek 11-1TFH with an initial production rate of 608 BOE per day from the Three Forks on September 28, 2010. This well was drilled approximately three miles east of our Federal 32-4H discovery well, which was completed in November 2009 flowing 1,970 BOE per day. While the Ellison Creek well had a lower initial production rate, its daily production rates have been relatively flat as it continues to produce. The 30-, 60- and 90-day daily production averages for the Ellison Creek well were 343 BOE, 326 BOE and 290 BOE, respectively.
Based on Whiting’s evaluations, we believe there has been partial pressure depletion from Upper Bakken Shale wells drilled in this area in the 1980s and 1990s. We believe that approximately 2% of our acreage at Lewis & Clark could potentially be affected.
Whiting completed the Teddy 44-13H with an initial production rate of 381 BOE per day from the Three Forks. We believe that this well frac’d into a water-bearing zone. The Company will modify its frac design for future wells drilled in this area.
Also of note, our Federal 32-4H discovery well produced a total of 66,300 BOE during its first six months of production, which ended May 25, 2010. Although this is a Three Forks well, it would rank the well among the top 15% of all Bakken wells drilled in North Dakota in terms of first six months total production based on information from the North Dakota Industrial Commission.
Whiting recently broke ground for the construction of a gas processing plant at Lewis & Clark. The Belfield Gas Plant, located near Belfield, North Dakota, will have an initial inlet capacity of 30 MMcf of gas per day and is expected to be completed in November 2011. To reduce the volume of gas being flared in the Lewis & Clark area, we are in the process of installing equipment to compress the natural gas into vessels that can be trucked to the nearest gas plant. Our Belfield plant will have the capability to accept trucked gas.
13
EOR Projects
Postle Field. The Postle field, located in Texas County, Oklahoma, produces from the Morrow sandstone at a depth of approximately 6,500 feet. In the fourth quarter of 2010, the field produced at an average net rate of 8,905 BOE per day, which was essentially flat with its 8,910 BOE net daily rate in the fourth quarter of 2009. Production in December 2010 averaged 8,805 BOE per day, down 3% from the September 2010 average daily rate of 9,075 BOE.
The Company manages its CO2 flood at Postle on a pattern-by-pattern basis in order to optimize utilization of CO2, production, and ultimate recovery. A pattern typically consists of a producing well surrounded by four water/CO2 injectors. As a pattern matures, increasing volumes of water are alternated with CO2 injection to control gas break through and sweep efficiency. This is referred to as the “WAG” (Water Alternating Gas) process. The process typically results in the highest possible oil recovery; however, the production response can be diminished during periods of high water injection. A number of patterns were cycled to water injection during the third and fourth quarters of 2010, which caused a normal slowing of oil response. The effect of the increased water injection and loss of CO2 injection resulted in the production decreases during the third and fourth quarters of 2010. We estimate that the production volumes at Postle will return to their previous range of 9,100 to 9,400 BOE per day by mid-2011. As of February 15, 2011, there were two drilling rigs and eight workover rigs active in the field.
North Ward Estes Field. Whiting has elected to accelerate its CO2 project at the North Ward Estes field, located in Ward and Winkler Counties, Texas. Previously, our final three phases (Phases 6, 7 and 8) were planned to be implemented in 2020, 2025 and 2027, respectively. We now plan to have all eight phases implemented by 2016. Whiting believes that, in addition to improving the net present value of future production from the field, we will be able to increase production and convert probable and possible reserves to proved reserves at a faster pace. At year-end 2010, a total of 130 MMBOE of probable and possible reserves were assigned to the North Ward Estes field.
Whiting initiated Phase 1 of our CO2 injection project in May 2007, Phase 2 began in March 2009 and Phase 3 began in December 2010. CO2 injection in the field during 2010 has averaged between 200 MMcf and 250 MMcf per day, of which approximately half has been recycled and the other half has been purchased CO2.
Production from our North Ward Estes field averaged 7,570 BOE per day in the fourth quarter of 2010. This average rate represented a 9% increase from the 6,955 net daily rate in the fourth quarter of 2009. Production in December 2010 averaged 7,620 BOE per day, an increase of 5% from the September 2010 average daily rate of 7,285 BOE. As we have previously reported, we temporarily reached our CO2 injection capacity at the North Ward Estes field in March 2010, requiring the installation of two additional compressors. The installation of these two new compressors was completed on October 15, 2010. As a result, Whiting increased CO2 injection into the field from approximately 200 MMcf per day to more than 240 MMcf per day. Consequently, production from the field increased. As of February 15, 2011, there were two drilling rigs and 26 workover rigs active in the field.
14
Natural Gas Project
Flat Rock Field. Whiting holds 22,029 gross acres (11,454 net acres) in the Flat Rock field, located in the Uinta Basin in Uintah County, Utah. Whiting moved a drilling rig to Flat Rock field in September 2009 after signing a fixed-price gas contract for the field’s production. The contract covers daily volumes of 10 MMcf of gas from September 1, 2009 through December 31, 2014 at a wellhead price of $5.50 per Mcf. We have an additional 9 MMcf of daily gas volumes under contract during 2011 at a fixed-price of $5.15 per Mcf at the wellhead. Thus, we are currently selling 19 MMcf of gas per day from the Flat Rock field at an average weighted price of $5.33 per Mcf at the wellhead.
Whiting completed four wells in the Flat Rock field in 2010. In February 2010, we completed the Ute Tribal 11-30-14-20 well in the Dakota formation flowing 6.8 MMcf of gas per day. In November 2010, we completed the Ute Tribal 3-25-14-19 well in the Entrada formation flowing 6.5 MMcf of gas per day. In December 2010, we completed two Entrada wells. The Ute Tribal 5-25-14-19 well flowed at an initial rate of 10.5 MMcf of gas per day, while the Ute Tribal 13-25-14-19 well flowed at an initial rate of 8.0 MMcf of gas per day. The Company holds a working interest of 100% and a net revenue interest of approximately 75% in all four wells.
New Prospect Drilling Areas
Redtail Niobrara Prospect. As of February 15, 2011, Whiting had acquired 102,424 gross (73,115 net) acres in our Redtail Niobrara prospect in the Weld County, Colorado portion of the Denver Julesburg Basin. We are continuing to acquire acreage. Our average acreage cost to date is $468 per net acre, and we have an average working interest of 71% and an average net revenue interest of 59%.
In late 2010, we initiated a seven well exploratory drilling program that will continue through June of 2011 and will consist of two vertical pilot wells and five horizontal production wells. Based on our current acreage position and a successful exploratory program, we could operate up to 220 wells and participate in an additional 131 non-operated wells assuming 320-acre spacing. Drilling depths in this area range from 5,500 feet to 6,500 feet with completed well costs for a 5,000-foot horizontal Niobrara well estimated at between $4 million and $5 million. Initial flow rates from the Niobrara formation in the Basin recently announced by other operators are ranging from 600 to 1,600 barrels of oil per day from multi-stage fracture stimulated horizontal wells.
15
Whiting has drilled four wells to date. The following table summarizes our plans and results to date:
|
Well Name
|
WI / NRI
|
Well Type
|
Well Status/Plan
|
|
Terrace 36-32M
|
100% / 80%
|
Core / Monitor
|
SI - WO Frac of Terrace 36-11H
|
|
Pawnee 16-13H
|
100% / 80%
|
Horizontal
|
WO Frac Late February
|
|
Chalk Bluffs 36-13H
|
100% / 80%
|
Core / Horizontal
|
Cored - WO Horizontal in March
|
|
Wild Horse 16-13H
|
100% / 80%
|
Core / Horizontal
|
Cored - WO Horizontal in March
|
|
Terrace 36-11H
|
100% / 80%
|
Horizontal
|
Drlg. - Multi-stage Frac in April
|
|
Two Mile Creek 22-13H
|
96% / 77%
|
Horizontal
|
Spud in March
|
|
Two Mile Creek 22-33M
|
96% / 77%
|
Core / Monitor
|
Spud in May
|
We consider this play to be in an early stage. Further drilling is subject to evaluation of our drilling and completion results.
Big Tex Prospect. As of February 15, 2011, Whiting had accumulated 84,304 gross (71,736 net) acres in our Big Tex prospect area in Pecos, Reeves and Ward Counties, Texas in the Delaware Basin. We are also continuing to acquire acreage in this area. Our average acreage cost to date is $491 per net acre, and we have an average working interest of 85% and an average net revenue interest of 64%. We have completed five re-entry vertical wells over the past seven months in the southern portion of the Delaware basin. Prospective formations include the Wolfcamp and Bone Spring horizons.
Our first vertical well in this area, the Trainer Trust 16-2, had a peak flow rate of 816 BOE per day and continued to flow for six months, producing over 45,000 barrels of oil during its first six months of production. The well produced at a restricted rate for 45 days during that period. Subsequently, four vertical wells have been completed with average initial production rates of 258 BOE per day. We currently plan to begin a four-well horizontal drilling program in the second quarter of 2011. We consider this play to be in an early stage. Further drilling is subject to evaluation of our drilling and completion results.
16
Operated Drilling and Workover Rig Count
As of February 15, 2011, 22 operated drilling rigs and 58 operated workover rigs were active on our properties. We were also participating in the drilling of three non-operated wells. The breakdown of our operated rigs is as follows:
|
Region
|
Drilling
|
Workover
|
||||||
|
Northern Rockies
|
||||||||
|
Sanish Field
|
9 | 9 | ||||||
|
Lewis & Clark
|
5 | 3 | ||||||
|
Other
|
1 | 1 | ||||||
|
Central Rockies
|
||||||||
|
Flat Rock Field
|
0 | 1 | ||||||
|
Redtail Prospect
|
1 | 0 | ||||||
|
Other
|
1 | 0 | ||||||
|
CO2 Projects
|
||||||||
|
Postle
|
2 | 8 | ||||||
|
North Ward Estes
|
2 | 26 | ||||||
|
Permian
|
||||||||
|
Big Tex
|
1 | 2 | ||||||
|
Other
|
0 | 4 | ||||||
|
Mid-Continent
|
0 | 4 | ||||||
|
Totals
|
22 | 58 | ||||||
We expect our operated drilling rig count to average approximately 20 and our operated workover rig count to average between 55 and 65 in 2011.
Notable 2010 Financial Events
On September 8, 2010, Whiting completed the redemption of all its $150 million aggregate principal amount of 7¼% Senior Subordinated Notes due 2012 at a redemption price equal to 100.00% of the principal amount and all its $220 million aggregate principal amount of 7¼% Senior Subordinated Notes due 2013 at a redemption price equal to 101.8125% of the principal amount. The total cash paid was approximately $383.5 million, which included accrued and unpaid interest.
Whiting financed the redemption of the Notes with borrowings under its credit agreement. As a result of the redemption of the Notes, Whiting incurred in the third quarter of 2010 a cash charge of approximately $4.0 million related to the redemption premium for the 2013 Notes and a non-cash charge of approximately $2.2 million related to the acceleration of debt discounts and unamortized debt issuance costs.
17
On September 17, 2010, Whiting closed the exchange offer for its 6.25% Convertible Perpetual Preferred Stock. Approximately 3.3 million shares of the preferred stock were exchanged for the issuance of approximately 15.1 million shares of common stock and a cash premium payment of $47.5 million. The induced conversion of preferred stock brought Whiting’s outstanding common shares to 117,098,506 at December 31, 2010. A total of 172,500 shares, or 5%, of Preferred Stock remains outstanding following the exchange.
On September 21, 2010, Moody’s Investors Service upgraded Whiting’s corporate credit rating to “Ba2” from “Ba3.” Whiting’s rating from Standard & Poor’s remains at “BB.”
On September 24, 2010, Whiting completed a public offering of $350 million aggregate principal amount of 6½% Senior Subordinated Notes due 2018. Whiting received net proceeds of approximately $342.6 million from the offering, after deducting the underwriter discounts and expenses of the offering. Whiting used these net proceeds to repay a portion of the debt under its credit agreement that was incurred to redeem its Notes due 2012 and 2013.
On October 15, 2010, Whiting announced that it entered into a Fifth Amended and Restated Credit Agreement with its bank syndicate that replaced the existing credit facility. This amended credit agreement maintained the borrowing base of $1.1 billion and extended the principal repayment date to October 2015. As of December 31, 2010, $200.0 million was drawn on the facility and $0.4 million in letters of credit were outstanding, resulting in $899.6 million of availability. The Whiting bank syndicate is comprised of 19 commercial banks, each holding between 1.4% and 11.4% of the total facility. The next regular borrowing base redetermination date is May 1, 2011.
Subsequent to 2010, on January 26, 2011, our Board of Directors approved a two-for-one split of the Company's shares of common stock to be effected in the form of a stock dividend. As a result of the stock split, stockholders of record on February 7, 2011 received one additional share of common stock for each share of common stock held. The additional shares of common stock were distributed on February 22, 2011. All share and per share amounts in this news release have been retroactively adjusted to reflect the stock split for all periods presented.
18
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2010 and 2009:
|
Three Months Ended
|
||||||||||||
|
Production
|
12/31/10
|
12/31/09
|
Change
|
|||||||||
|
Oil and NGLs (MMBbls)
|
5.03 | 4.09 | 23% | |||||||||
|
Natural gas (Bcf)
|
7.32 | 6.76 | 8% | |||||||||
|
Total equivalent (MMBOE)
|
6.25 | 5.22 | 20% | |||||||||
|
Average Sales Price
|
||||||||||||
|
Oil and NGLs (per Bbl):
|
||||||||||||
|
Price received
|
$ | 74.53 | $ | 65.52 | 14% | |||||||
|
Effect of crude oil hedging (1)
|
(1.80 | ) | (1.80 | ) | ||||||||
|
Realized price
|
$ | 72.73 | $ | 63.72 | 14% | |||||||
|
Natural gas (per Mcf):
|
||||||||||||
|
Price received
|
$ | 4.34 | $ | 4.88 | (11%) | |||||||
|
Effect of natural gas hedging (1)
|
0.05 | 0.05 | ||||||||||
|
Realized price
|
$ | 4.39 | $ | 4.93 | (11%) | |||||||
(1) Whiting realized pre-tax cash settlement losses of $9.1 million on its crude oil hedges and gains of $0.4 million on its natural gas hedges during the fourth quarter of 2010. A summary of Whiting’s outstanding hedges is included later in this news release.
Fourth Quarter and Full-Year 2010 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
|
Per BOE, Except Production
|
||||||||||||||||
|
Three Months
|
Twelve Months
|
|||||||||||||||
|
Ended December 31,
|
Ended December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Production (MMBOE)
|
6.25 | 5.22 | 23.60 | 20.27 | ||||||||||||
|
Sales price, net of hedging
|
$ | 63.66 | $ | 56.35 | $ | 61.48 | $ | 45.01 | ||||||||
|
Lease operating expense
|
11.33 | 11.49 | 11.37 | 11.71 | ||||||||||||
|
Production tax
|
4.25 | 4.11 | 4.40 | 3.19 | ||||||||||||
|
General & administrative
|
2.59 | 2.26 | 2.74 | 2.09 | ||||||||||||
|
Exploration
|
1.12 | 4.23 | 1.39 | 2.31 | ||||||||||||
|
Cash interest expense
|
1.78 | 2.44 | 2.05 | 2.64 | ||||||||||||
|
Cash income tax expense (benefit)
|
(0.24 | ) | 0.25 | 0.21 | 0.01 | |||||||||||
| $ | 42.83 | $ | 31.57 | $ | 39.32 | $ | 23.06 | |||||||||
19
The following table compares the Company’s fourth quarter 2010 guidance with actual fourth quarter 2010 results:
|
Actual
|
Guidance
|
Difference
|
||||
|
Production - MBOE
|
6,246
|
6,050 to 6,350
|
within
|
|||
|
Production taxes - % of sales
|
6.53%
|
7.0% to 7.4%
|
under 6.7%
|
|||
|
LOE per BOE
|
$11.33
|
$11.30 to $11.70
|
within
|
|||
|
D,D&A per BOE
|
$16.66
|
$16.20 to $16.50
|
over <1%
|
|||
|
G&A per BOE
|
$2.59
|
$2.55 to $2.75
|
within
|
|||
|
Interest expense per BOE
|
$2.11
|
$2.10 to $2.30
|
within
|
|||
|
Oil differential to NYMEX
|
$10.59
|
$8.75 to $9.75
|
over 8.6%
|
|||
|
Gas premium to NYMEX
|
$0.53
|
$0.30 to $0.70
|
within
|
During the fourth quarter, the company-wide basis differential for crude oil compared to NYMEX was $10.59 per barrel, which compared to $9.19 per barrel in the third quarter of 2010. We expect our company-wide oil price differential to average between $10.00 and $11.00 during the first quarter of 2011. Within the Bakken, Whiting’s operated production had a differential of approximately $13.00 per barrel in February 2011. We expect this to drop to approximately $11.00 per barrel in March 2011 as the Mandan refinery comes back to full production after maintenance and repairs.
The company-wide basis differential for natural gas compared to NYMEX in the fourth quarter was at a premium of $0.53 per Mcf, which compared to a premium of $0.61 per Mcf in the third quarter of 2010. We expect our natural gas to sell at a premium price of between $0.40 and $0.70 during the first quarter of 2011.
Fourth Quarter 2010 Drilling Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and exploration and development costs incurred for the three and 12 months ended December 31, 2010:
|
Gross/Net Wells Completed
|
Expl. & Dev.
|
||||
|
Total New
|
% Success
|
Cost
|
|||
|
Producing
|
Non-Producing
|
Drilling
|
Rate
|
(in MM)(1)
|
|
|
Q4 10
|
63 / 30.5
|
4 / 2.6
|
67 / 33.1
|
94% / 92%
|
$ 282.5
|
|
12M 10
|
183 / 84.3
|
6 / 3.7
|
189 / 88.0
|
97% / 96%
|
$ 822.9
|
(1) Excludes $155.5 million of 2010 acreage acquisition costs.
20
Outlook for First Quarter and Full-Year 2011
The following table provides guidance for the first quarter and full-year 2011 based on current forecasts, including Whiting’s full-year 2011 capital budget of $1,350.0 million.
Guidance for the first quarter and full-year 2011 is as follows:
|
Guidance
|
||
|
First Quarter
|
Full-Year
|
|
|
2011
|
2011
|
|
|
Production (MMBOE)
|
5.70 - 5.90
|
25.80 - 26.20
|
|
Lease operating expense per BOE
|
$12.20 - $12.40
|
$11.20 - $11.40
|
|
General and admin. expense per BOE
|
$2.65 - $2.85
|
$2.70 - $2.90
|
|
Interest expense per BOE
|
$2.25 - $2.45
|
$2.05 - $2.25
|
|
Depr., depletion and amort. per BOE
|
$17.30 - $17.50
|
$17.80 - $18.00
|
|
Prod. taxes (% of production revenue)
|
7.2% - 7.5%
|
7.3% - 7.6%
|
|
Oil price differentials to NYMEX per Bbl
|
$10.00 - $11.00
|
$10.00 - $11.00
|
|
Gas price premium to NYMEX per Mcf (1)
|
$0.40 - $0.70
|
$0.40 - $0.70
|
(1) Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
Our 2011 guidance includes a lower production level in the first quarter of 2011 compared to the fourth quarter of 2010 due primarily to inclement weather in North Dakota that has caused well completion delays. Also contributing to the lower production guidance were weather issues at our Postle field EOR project in Oklahoma and our North Ward Estes EOR project in the Permian Basin of Texas. Both EOR projects experienced temporary downtime due to cold weather.
21
Oil Hedges
The following summarizes Whiting’s crude oil hedges as of February 22, 2011:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
NYMEX Price Collar Range
|
December 2010
|
|||
|
Period
|
(Bbls per Month)
|
(per Bbl)
|
Oil Production
|
|||
|
2011
|
||||||
|
Q1
|
904,917
|
$61.01 - $97.12
|
54.9%
|
|||
|
Q2
|
904,696
|
$61.01 - $98.32
|
54.9%
|
|||
|
Q3
|
904,479
|
$61.01 - $98.31
|
54.9%
|
|||
|
Q4
|
904,255
|
$61.00 - $98.31
|
54.9%
|
|||
|
2012
|
||||||
|
Q1
|
559,054
|
$55.33 - $99.71
|
33.9%
|
|||
|
Q2
|
558,850
|
$55.33 - $99.70
|
33.9%
|
|||
|
Q3
|
558,650
|
$55.32 - $99.69
|
33.9%
|
|||
|
Q4
|
558,477
|
$55.31 - $99.68
|
33.9%
|
|||
|
2013
|
||||||
|
Q1
|
290,000
|
$47.67 - $90.21
|
17.6%
|
|||
|
Q2
|
290,000
|
$47.67 - $90.21
|
17.6%
|
|||
|
Q3
|
290,000
|
$47.67 - $90.21
|
17.6%
|
|||
|
Oct
|
290,000
|
$47.67 - $90.21
|
17.6%
|
|||
|
Nov
|
190,000
|
$47.22 - $85.06
|
11.5%
|
22
The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of February 22, 2011:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
NYMEX Price Collar Range
|
December 2010
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2011
|
||||||
|
Q1
|
38,139
|
$7.00 - $17.40
|
1.5%
|
|||
|
Q2
|
36,954
|
$6.00 - $13.05
|
1.5%
|
|||
|
Q3
|
35,855
|
$6.00 - $13.65
|
1.4%
|
|||
|
Q4
|
34,554
|
$7.00 - $14.25
|
1.4%
|
|||
|
2012
|
||||||
|
Q1
|
33,381
|
$7.00 - $15.55
|
1.3%
|
|||
|
Q2
|
32,477
|
$6.00 - $13.60
|
1.3%
|
|||
|
Q3
|
31,502
|
$6.00 - $14.45
|
1.3%
|
|||
|
Q4
|
30,640
|
$7.00 – $13.40
|
1.2%
|
23
Whiting also has the following fixed-price natural gas contracts in place as of February 22, 2011:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
December 2010
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2011
|
||||||
|
Q1
|
777,960
|
$5.30
|
31.4%
|
|||
|
Q2
|
778,914
|
$5.31
|
31.4%
|
|||
|
Q3
|
772,460
|
$5.30
|
31.2%
|
|||
|
Q4
|
772,460
|
$5.30
|
31.2%
|
|||
|
2012
|
||||||
|
Q1
|
577,127
|
$5.30
|
23.3%
|
|||
|
Q2
|
461,460
|
$5.41
|
18.6%
|
|||
|
Q3
|
465,794
|
$5.41
|
18.8%
|
|||
|
Q4
|
398,667
|
$5.46
|
16.1%
|
|||
|
2013
|
||||||
|
Q1
|
360,000
|
$5.47
|
14.5%
|
|||
|
Q2
|
364,000
|
$5.47
|
14.7%
|
|||
|
Q3
|
368,000
|
$5.47
|
14.8%
|
|||
|
Q4
|
368,000
|
$5.47
|
14.8%
|
|||
|
2014
|
||||||
|
Q1
|
330,000
|
$5.49
|
13.3%
|
|||
|
Q2
|
333,667
|
$5.49
|
13.5%
|
|||
|
Q3
|
337,333
|
$5.49
|
13.6%
|
|||
|
Q4
|
337,333
|
$5.49
|
13.6%
|
24
Selected Operating and Financial Statistics
|
Three Months Ended
December 31,
|
Twelve Months Ended
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Selected operating statistics
|
||||||||||||||||
|
Production
|
||||||||||||||||
|
Oil and NGLs, MBbl
|
5,026 | 4,091 | 19,030 | 15,381 | ||||||||||||
|
Natural gas, MMcf
|
7,323 | 6,759 | 27,392 | 29,333 | ||||||||||||
|
Oil equivalents, MBOE
|
6,246 | 5,218 | 23,596 | 20,269 | ||||||||||||
|
Average Prices
|
||||||||||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 74.53 | $ | 65.52 | $ | 70.53 | $ | 52.51 | ||||||||
|
Natural gas per Mcf (excludes hedging)
|
$ | 4.34 | $ | 4.88 | $ | 4.86 | $ | 3.75 | ||||||||
|
Per BOE Data
|
||||||||||||||||
|
Sales price (including hedging)
|
$ | 63.66 | $ | 56.35 | $ | 61.48 | $ | 45.01 | ||||||||
|
Lease operating
|
$ | 11.33 | $ | 11.49 | $ | 11.37 | $ | 11.71 | ||||||||
|
Production taxes
|
$ | 4.25 | $ | 4.11 | $ | 4.40 | $ | 3.19 | ||||||||
|
Depreciation, depletion and amortization
|
$ | 16.66 | $ | 17.86 | $ | 16.69 | $ | 19.48 | ||||||||
|
General and administrative
|
$ | 2.59 | $ | 2.26 | $ | 2.74 | $ | 2.09 | ||||||||
|
Selected Financial Data
|
||||||||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||
|
Total revenues and other income
|
$ | 413,469 | $ | 316,035 | $ | 1,516,099 | $ | 979,360 | ||||||||
|
Total costs and expenses
|
$ | 308,429 | $ | 325,972 | $ | 974,656 | $ | 1,142,195 | ||||||||
|
Net income (loss) available to common shareholders
|
$ | 65,925 | $ | (11,206 | ) | $ | 272,683 | $ | (117,184 | ) | ||||||
|
Earnings (loss) per common share, basic (1)
|
$ | 0.56 | $ | (0.12 | ) | $ | 2.57 | $ | (1.18 | ) | ||||||
|
Earnings (loss) per common share, diluted (1)
|
$ | 0.56 | $ | (0.12 | ) | $ | 2.55 | $ | (1.18 | ) | ||||||
|
Average shares outstanding, basic (1)
|
117,098 | 101,691 | 106,338 | 100,088 | ||||||||||||
|
Average shares outstanding, diluted (1)
|
118,564 | 101,691 | 107,846 | 100,088 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 277,022 | $ | 163,004 | $ | 997,289 | $ | 453,824 | ||||||||
|
Net cash used in investing activities
|
$ | (346,496 | ) | $ | (168,809 | ) | $ | (914,574 | ) | $ | (523,547 | ) | ||||
|
Net cash provided by (used in) financing activities
|
$ | 85,215 | $ | 1,905 | $ | (75,723 | ) | $ | 72,059 | |||||||
(1) All share and per share amounts have been retroactively restated for all periods presented to reflect the Company’s two-for-one stock split described earlier in this news release.
25
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 24, 2011 at 11:00 a.m. EST (10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting’s fourth quarter and full-year 2010 financial and operating results. Please call (866) 770-7129 (U.S./Canada) or (617) 213-8067 (International) and enter the pass code 13909358 to be connected to the call. Access to a live Internet broadcast will be available at www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EDT) on February 24, 2011.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 24, 2011 and continuing through Thursday, March 3, 2011. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 59727925. You may also access a web archive at http://www.whiting.com beginning approximately one hour after the conference call.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that acquires, exploits, develops and explores for crude oil, natural gas and natural gas liquids primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit www.whiting.com.
Forward-Looking Statements
This news release contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
26
These risks and uncertainties include, but are not limited to: declines in oil or natural gas prices; impacts of the global recession and tight credit markets; our level of success in exploitation, exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO2; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; federal and state initiatives relating to hydraulic fracturing; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2010. 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.
27
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.
28
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, 2010, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
December 31,
2010
|
December 31,
2009
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 18,952 | $ | 11,960 | ||||
|
Accounts receivable trade, net
|
199,713 | 152,082 | ||||||
|
Prepaid expenses and other
|
14,878 | 11,983 | ||||||
|
Total current assets
|
233,543 | 176,025 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method:
|
||||||||
|
Proved properties
|
5,661,619 | 4,870,688 | ||||||
|
Unproved properties
|
226,336 | 100,706 | ||||||
|
Other property and equipment
|
98,092 | 100,833 | ||||||
|
Total property and equipment
|
5,986,047 | 5,072,227 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(1,630,824 | ) | (1,274,121 | ) | ||||
|
Total property and equipment, net
|
4,355,223 | 3,798,106 | ||||||
|
Debt issuance costs
|
34,226 | 24,672 | ||||||
|
Other long term assets
|
25,785 | 30,739 | ||||||
|
TOTAL ASSETS
|
$ | 4,648,777 | $ | 4,029,542 | ||||
29
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
December 31,
2010
|
December 31,
2009
|
|||||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable trade
|
$ | 35,016 | $ | 14,023 | ||||
|
Accrued capital expenditures
|
84,789 | 29,998 | ||||||
|
Accrued liabilities and other
|
153,062 | 110,320 | ||||||
|
Revenues and royalties payable
|
82,124 | 46,327 | ||||||
|
Taxes payable
|
30,291 | 21,188 | ||||||
|
Derivative liabilities
|
69,375 | 49,551 | ||||||
|
Deferred income taxes
|
4,548 | 11,325 | ||||||
|
Total current liabilities
|
459,205 | 282,732 | ||||||
|
Long-term debt
|
800,000 | 779,585 | ||||||
|
Deferred income taxes
|
539,071 | 341,037 | ||||||
|
Derivative liabilities
|
95,256 | 137,621 | ||||||
|
Production Participation Plan liability
|
81,524 | 69,433 | ||||||
|
Asset retirement obligations
|
76,994 | 66,846 | ||||||
|
Deferred gain on sale
|
41,460 | 58,462 | ||||||
|
Other long-term liabilities
|
23,952 | 23,741 | ||||||
|
Total liabilities
|
2,117,462 | 1,759,457 | ||||||
|
Commitments and contingencies
|
||||||||
|
Stockholders’ equity:
|
||||||||
|
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,500 issued and outstanding as of December 31, 2010 and 3,450,000 issued and outstanding as of December 31, 2009, aggregate liquidation preference of $17,250,000 at December 31, 2010
|
- | 3 | ||||||
|
Common stock, $0.001 par value, 175,000,000 shares authorized; 117,967,876 issued and 117,098,506 outstanding as of December 31, 2010, 102,727,276 issued and 101,690,748 outstanding as of December 31, 2009 (1)
|
59 | 51 | ||||||
|
Additional paid-in capital
|
1,549,822 | 1,546,635 | ||||||
|
Accumulated other comprehensive income
|
5,768 | 20,413 | ||||||
|
Retained earnings
|
975,666 | 702,983 | ||||||
|
Total stockholders’ equity
|
2,531,315 | 2,270,085 | ||||||
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$ | 4,648,777 | $ | 4,029,542 | ||||
(1) All common share amounts (except par value and par value per share) have been retroactively restated for all periods presented to reflect the Company’s two-for-one stock split described earlier in this news release.
30
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended
December 31,
|
Twelve Months Ended
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
REVENUES AND OTHER INCOME:
|
||||||||||||||||
|
Oil and natural gas sales
|
$ | 406,327 | $ | 300,989 | $ | 1,475,288 | $ | 917,541 | ||||||||
|
Gain hedging activities
|
3,558 | 10,703 | 23,198 | 38,776 | ||||||||||||
|
Amortization of deferred gain on sale
|
4,000 | 4,001 | 15,613 | 16,596 | ||||||||||||
|
Gain (loss) on sale of properties
|
(530 | ) | 238 | 1,388 | 5,947 | |||||||||||
|
Interest income and other
|
114 | 104 | 612 | 500 | ||||||||||||
|
Total revenues and other income
|
413,469 | 316,035 | 1,516,099 | 979,360 | ||||||||||||
|
COSTS AND EXPENSES:
|
||||||||||||||||
|
Lease operating
|
70,762 | 59,927 | 268,348 | 237,270 | ||||||||||||
|
Production taxes
|
26,539 | 21,447 | 103,880 | 64,672 | ||||||||||||
|
Depreciation, depletion and amortization
|
104,061 | 93,170 | 393,897 | 394,792 | ||||||||||||
|
Exploration and impairment
|
21,456 | 33,486 | 59,371 | 73,014 | ||||||||||||
|
General and administrative
|
16,178 | 11,781 | 64,694 | 42,357 | ||||||||||||
|
Interest expense
|
13,175 | 15,588 | 59,078 | 64,608 | ||||||||||||
|
Loss on early extinguishment of debt
|
- | - | 6,235 | - | ||||||||||||
|
Change in Production Participation Plan liability
|
2,541 | 265 | 12,091 | 3,267 | ||||||||||||
|
Commodity derivative (gain) loss, net
|
53,717 | 90,308 | 7,062 | 262,215 | ||||||||||||
|
Total costs and expenses
|
308,429 | 325,972 | 974,656 | 1,142,195 | ||||||||||||
|
INCOME (LOSS) BEFORE INCOME TAXES
|
105,040 | (9,937 | ) | 541,443 | (162,835 | ) | ||||||||||
|
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
|
Current
|
(1,489 | ) | 1,282 | 4,979 | 236 | |||||||||||
|
Deferred
|
40,335 | (5,404 | ) | 199,811 | (56,189 | ) | ||||||||||
|
Total income tax expense (benefit)
|
38,846 | (4,122 | ) | 204,790 | (55,953 | ) | ||||||||||
|
NET INCOME (LOSS)
|
66,194 | (5,815 | ) | 336,653 | (106,882 | ) | ||||||||||
|
Preferred stock dividends and inducement premium
|
(269 | ) | (5,391 | ) | (63,970 | ) | (10,302 | ) | ||||||||
|
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 65,925 | $ | (11,206 | ) | $ | 272,683 | $ | (117,184 | ) | ||||||
|
EARNINGS (LOSS) PER COMMON SHARE (1):
|
||||||||||||||||
|
Basic
|
$ | 0.56 | $ | (0.12 | ) | $ | 2.57 | $ | (1.18 | ) | ||||||
|
Diluted
|
$ | 0.56 | $ | (0.12 | ) | $ | 2.55 | $ | (1.18 | ) | ||||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING (1):
|
||||||||||||||||
|
Basic
|
117,098 | 101,691 | 106,338 | 100,088 | ||||||||||||
|
Diluted
|
118,564 | 101,691 | 107,846 | 100,088 | ||||||||||||
(1) All share and per share amounts have been retroactively restated for all periods presented to reflect the Company’s two-for-one stock split described earlier in this news release.
31
WHITING PETROLEUM CORPORATION
Reconciliation of Net Income (Loss) Available to Common Shareholders to
Adjusted Net Income Available to Common Shareholders
(In thousands, except for per share data)
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Net Income (Loss) Available to Common Shareholders
|
$ | 65,925 | $ | (11,206 | ) | $ | 272,683 | $ | (117,184 | ) | ||||||
|
Cash Premium on Induced Conversion
|
-- | -- | 47,529 | -- | ||||||||||||
|
Adjustments Net of Tax:
|
||||||||||||||||
|
Amortization of Deferred Gain on Sale
|
(2,521 | ) | (2,341 | ) | (9,708 | ) | (10,893 | ) | ||||||||
|
(Gain) Loss on Sale of Properties
|
334 | (139 | ) | (863 | ) | (3,903 | ) | |||||||||
|
Impairment Expense
|
9,119 | 6,669 | 16,492 | 17,157 | ||||||||||||
|
Loss on Early Extinguishment of Debt
|
-- | -- | 3,877 | -- | ||||||||||||
|
Unrealized Derivative (Gains) Losses
|
26,137 | 42,488 | (25,329 | ) | 143,259 | |||||||||||
|
Adjusted Net Income (1)
|
$ | 98,994 | $ | 35,471 | $ | 304,681 | $ | 28,436 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Basic (2)
|
$ | 0.85 | $ | 0.35 | $ | 2.99 | $ | 0.27 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Diluted (2)
|
$ | 0.84 | $ | 0.35 | $ | 2.71 | $ | 0.27 | ||||||||
(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 GAAP and may not be comparable to other similarly titled measures of other companies.
(2) All per share amounts have been retroactively restated for all periods presented to reflect the Company’s two-for-one stock split described earlier in this news release.
32
WHITING PETROLEUM CORPORATION
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(In thousands)
|
Three Months Ended
|
||||||||
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
Net cash provided by operating activities
|
$ | 277,022 | $ | 163,004 | ||||
|
Exploration
|
6,985 | 22,090 | ||||||
|
Exploratory dry hole costs
|
(1,023 | ) | (15,868 | ) | ||||
|
Changes in working capital
|
(5,555 | ) | 21,637 | |||||
|
Preferred stock dividends paid
|
(269 | ) | (5,391 | ) | ||||
|
Discretionary cash flow (1)
|
$ | 277,160 | $ | 185,472 | ||||
|
Twelve Months Ended
|
||||||||
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
Net cash provided by operating activities
|
$ | 997,289 | $ | 453,824 | ||||
|
Exploration
|
32,846 | 46,875 | ||||||
|
Exploratory dry hole costs
|
(3,819 | ) | (18,212 | ) | ||||
|
Changes in working capital
|
(60,545 | ) | 40,858 | |||||
|
Preferred stock dividends paid
|
(16,441 | ) | (10,302 | ) | ||||
|
Discretionary cash flow (1)
|
$ | 949,330 | $ | 513,043 | ||||
(1) Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, loss on early extinguishment of debt, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-current items less the gain on sale of properties, amortization of deferred gain on sale, non-cash gains on mark-to-market derivatives, and preferred stock dividends paid, not including the preferred stock inducement premium. The non-GAAP measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under GAAP and may not be comparable to other similarly titled measures of other companies.
33
WHITING PETROLEUM CORPORATION
Finding Cost and Reserve Replacement Schedule
12/31/10 (1)
(In thousands)
|
Two Years
|
||||||||||||
| 2009 - 2010 | ||||||||||||
|
2009
|
2010
|
Total/Avg.
|
||||||||||
|
Proved Acquisition
|
$ | 78,800 | $ | 22,763 | $ | 101,563 | ||||||
|
Unproved Acquisition
|
$ | 12,872 | $ | 155,472 | $ | 168,344 | ||||||
|
Development Cost
|
$ | 436,721 | $ | 723,687 | $ | 1,160,408 | ||||||
|
Exploration Cost
|
$ | 50,970 | $ | 114,012 | $ | 164,982 | ||||||
|
Change in Future Development Cost
|
$ | 423,541 | $ | 86,203 | $ | 509,744 | ||||||
|
Total
|
$ | 1,002,904 | $ | 1,102,137 | $ | 2,105,041 | ||||||
|
Acquisition Reserves
|
||||||||||||
|
Acquisition Res. – Oil (MBbl)
|
3,177 | 505 | 3,682 | |||||||||
|
Acquisition Res. – Gas (MMcf)
|
4,155 | 1,526 | 5,681 | |||||||||
|
Total – Aqu. Res. – MBOE
|
3,870 | 759 | 4,629 | |||||||||
|
Development Reserves
|
||||||||||||
|
Development Res. – Oil (MBbl)
|
25,115 | 29,434 | 54,549 | |||||||||
|
Development Res. - Gas (MMcf)
|
41,969 | 23,135 | 65,104 | |||||||||
|
Total – Dev. Res. – MBOE
|
32,109 | 33,290 | 65,399 | |||||||||
|
Revisions
|
||||||||||||
|
Reserve Revisions – Oil (MBbl)
|
33,566 | 19,799 | 53,365 | |||||||||
|
Reserve Revisions - Gas (MMcf)
|
(62,618 | ) | (618 | ) | (63,236 | ) | ||||||
|
Total - Reserve Rev. – MBOE
|
23,130 | 19,695 | 42,825 | |||||||||
|
Cost per BOE to Acquire
|
$ | 20.36 | $ | 29.99 | $ | 21.94 | ||||||
|
Cost per BOE to Develop
|
$ | 16.73 | $ | 20.37 | $ | 18.51 | ||||||
|
All-in finding cost per BOE
|
$ | 16.97 | $ | 20.51 | $ | 18.65 | ||||||
|
Probable and Possible CapEx (1)
|
$ | 3,536,055 | ||||||||||
|
Probable and Possible Reserves – MBOE (1)
|
317,215 | |||||||||||
|
All-In Rate with Future Development Cost and Prob. and Poss. (1)
|
$ | 13.12 | ||||||||||
|
RESERVE REPLACEMENT
|
||||||||||||
|
Acquisition Reserves
|
3,870 | 759 | 4,629 | |||||||||
|
Development Reserves
|
32,109 | 33,290 | 65,399 | |||||||||
|
Reserve Revisions
|
23,130 | 19,695 | 42,825 | |||||||||
|
Total New Reserves – MBOE
|
59,109 | 53,744 | 112,853 | |||||||||
|
Production (MBOE)
|
20,269 | 23,596 | 43,865 | |||||||||
|
Reserve Replacement %
|
292 | % | 228 | % | 257 | % | ||||||
(1) See “Disclosure Regarding Reserves and Resources” earlier in this news release.
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