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OAS > SEC Filings for OAS > Form 10-Q on 8-Nov-2012All Recent SEC Filings

Show all filings for OASIS PETROLEUM INC.

Form 10-Q for OASIS PETROLEUM INC.


8-Nov-2012

Quarterly Report


Item 2. - Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2011 ("2011 Annual Report"), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under Item 1A. "Risk Factors" in our 2011 Annual Report and in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

our business strategy;

estimated future net reserves and present value thereof;

technology;

cash flows and liquidity;

our financial strategy, budget, projections, execution of business plan and operating results;

oil and natural gas realized prices;

timing and amount of future production of oil and natural gas;

availability of drilling, completion and production equipment and materials;

availability of qualified personnel;

owning and operating a services company;

the amount, nature and timing of capital expenditures;

availability and terms of capital;

property acquisitions;

costs of exploiting and developing our properties and conducting other operations;

drilling and completion of wells;

infrastructure for salt water disposal;

gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and domestically;

general economic conditions;

operating environment, including inclement weather conditions;

competition in the oil and natural gas industry;

effectiveness of risk management activities;

environmental liabilities;

counterparty credit risk;

governmental regulation and the taxation of the oil and natural gas industry;


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developments in oil-producing and natural gas-producing countries;

uncertainty regarding future operating results; and

plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Montana and North Dakota regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. We also operate businesses that are complementary to our primary development and production activities, including a marketing business, Oasis Petroleum Marketing LLC ("OPM"), and a well services business, Oasis Well Services LLC ("OWS"). The revenues and expenses related to work performed by OPM and OWS for Oasis Petroleum North America LLC's working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:

Commodity prices for oil and natural gas;

Transportation capacity;

Availability and cost of services; and

Availability of qualified personnel.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments to manage our commodity price risk, and enter into physical delivery contracts to manage our price differentials. In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, during the first three quarters of 2012, we began to actively increase the number of operated wells that we have connected to a third-party oil gathering system in our West Williston project area. At the end of September 2012, the Company had 108 operated wells connected, up from only three operated wells that were connected at the beginning of 2012. We currently flow approximately 60% of our gross operated oil production on the third-party oil gathering system. This same third-party has also agreed to extend the system into our East Nesson project area in 2013, which we expect will increase the gross operated oil production that will flow on the system to over 80% by mid-year 2013.


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Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. Oil prices have increased significantly since 2009. As a result of higher commodity prices and continued successes in the application of completion technologies in the Bakken formation, there were approximately 220 active drilling rigs in the Williston Basin at September 30, 2012. Both takeaway capacity and production have rapidly grown in the Williston Basin throughout 2012. In the first half of 2012, price differentials were at or above the historical average discount range of 10% to 15% to the price quoted for NYMEX West Texas Intermediate ("WTI") crude oil due to production growth in the Williston Basin combined with refinery and transportation constraints. In the third quarter of 2012, differentials began to narrow, primarily due to transportation capacity additions outpacing production growth.

Our large concentrated acreage position potentially provides us with a multi-year inventory of drilling projects and requires some forward planning visibility for obtaining services. Our ability to develop and hold our existing undeveloped leasehold acreage is primarily dependent upon having access to drilling rigs and completion services. The utilization of existing drilling rigs and of existing completion service equipment in the Williston Basin is at an all-time high. This has resulted in drilling rigs, completion equipment and crews being imported from Canada and other parts of the United States. To ensure access to drilling rigs, we have entered into fixed-term drilling rig contracts for periods of up to three years and currently have nine drilling rigs under contract. In order to ensure the availability of completion services and the timely fracture stimulation of newly drilled wells, we formed OWS in June 2011 to provide well services on our operated wells, in addition to entering into fracturing service contracts with third party companies.

Third Quarter 2012 Highlights:

On July 2, 2012, we issued $400 million of 6.875% senior unsecured notes due January 15, 2023, resulting in net proceeds to us of approximately $392 million;

We completed and placed on production 34 gross operated wells in the Williston Basin during the three months ended September 30, 2012;

We had 25 gross operated wells awaiting completion and 11 gross operated wells in the process of being drilled in the Bakken and Three Forks formations at September 30, 2012;

Average daily production was 24,257 Boe per day during the three months ended September 30, 2012;

Exploration and production ("E&P") capital expenditures were $311.4 million, consisting primarily of $275.9 million in drilling expenditures during the three months ended September 30, 2012; and

At September 30, 2012, we had $406.5 million of cash and cash equivalents and short-term investments and had no borrowings or outstanding letters of credit under our revolving credit facility.

Results of Operations

Revenues

Our revenues are derived from the sale of oil and natural gas production and do not include the effects of derivative instruments. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.


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The following table summarizes our revenues and production data for the periods indicated.

                                         Three Months Ended September 30,               Nine Months Ended September 30,
                                         2012             2011         Change          2012            2011         Change
Operating results (in thousands):
Revenues
Oil                                  $    173,752       $  85,870     $ 87,882      $   443,686      $ 208,442     $ 235,244
Natural gas                                 4,996           1,726        3,270           18,171          5,104        13,067
Well services                               5,963              -         5,963           10,484             -         10,484

Total revenues                            184,711          87,596       97,115          472,341        213,546       258,795

Production data:
Oil (MBbls)                                 2,076           1,028        1,048            5,232          2,407         2,825
Natural gas (MMcf)                            937             225          712            2,740            627         2,113
Oil equivalents (MBoe)                      2,232           1,066        1,166            5,688          2,512         3,176
Average daily production (Boe/d)           24,257          11,583       12,674           20,761          9,201        11,560
Average sales prices:
Oil, without realized derivatives
(per Bbl) (1)                        $      83.71       $   83.52     $   0.19      $     84.52      $   86.58     $   (2.06 )
Oil, with realized derivatives
(per Bbl) (1) (2)                           86.24           83.35         2.89            85.05          84.58          0.47
Natural gas (per Mcf) (3)                    5.33            7.66        (2.33 )           6.63           8.14         (1.51 )

(1) For the nine months ended September 30, 2012, average sales prices for oil are calculated using total oil revenues, excluding bulk purchase sales of $1.5 million, divided by oil production.

(2) Realized prices include realized gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.

(3) Natural gas prices include the value for natural gas and natural gas liquids.

Three months ended September 30, 2012 as compared to three months ended September 30, 2011

Total revenues. Our total revenues increased $97.1 million, or 111%, to $184.7 million during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 12,674 Boe per day, or 109%, to 24,257 Boe per day during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last quarter of 2011 and the first three quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 9,038 Boe per day, 3,116 Boe per day and 605 Boe per day, respectively, during the third quarter of 2012 as compared to the third quarter of 2011. Average oil sales prices, without realized derivatives, increased by $0.19/Bbl to an average of $83.71/Bbl for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The higher production amounts sold increased revenues by $91.4 million, while lower natural gas sales prices, offset by a slight increase in oil prices, decreased revenues by $0.3 million during the three months ended September 30, 2012. The remaining $6.0 million increase in total revenues was attributable to well services revenues during the three months ended September 30, 2012. There were no well services revenues during the third quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Nine months ended September 30, 2012 as compared to nine months ended September 30, 2011

Total revenues. Our total revenues increased $258.8 million, or 121%, to $472.3 million during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 11,560 Boe per day, or 126%, to 20,761 Boe per day during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last quarter of 2011 and the first three quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 8,692 Boe per day, 2,379 Boe per day and 587 Boe per day, respectively, during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. Average oil sales prices, without realized derivatives, decreased by $2.06/Bbl, or 2%, to an average of $84.52/Bbl for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. The higher production amounts sold increased revenues by $252.7 million, while lower oil and natural gas sales prices decreased revenues by $5.9 million during the nine months ended September 30, 2012. Well services revenues were $10.5 million for the nine months ended September 30, 2012 compared to no well services revenues during the nine months ended September 30, 2011 because OWS did not commence fracturing activity until the first quarter of 2012. The remaining $1.5 million increase in total revenues was attributable to oil bulk purchase revenues related to marketing activities included in oil and gas revenues during the nine months ended September 30, 2012.


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Expenses

The following table summarizes our operating expenses for the periods indicated.



                                        Three Months Ended September 30,               Nine Months Ended September 30,
                                       2012           2011          $ Change          2012           2011         $ Change
                                                         (In thousands, except per Boe of production)
Expenses:
Lease operating expenses            $   16,134      $   9,597      $    6,537      $   37,979      $  21,178      $  16,801
Well services operating expenses         5,420             -            5,420           7,104             -           7,104
Marketing, transportation and
gathering expenses                       2,744            238           2,506           7,283            797          6,486
Production taxes                        16,433          8,873           7,560          43,419         22,041         21,378
Depreciation, depletion and
amortization                            57,684         20,859          36,825         140,783         47,771         93,012
Exploration expenses                       336             54             282           3,171            345          2,826
Impairment of oil and gas
properties                                  36            396            (360 )         2,607          3,313           (706 )
General and administrative
expenses                                13,886          7,306           6,580          39,622         19,870         19,752

Total expenses                         112,673         47,323          65,350         281,968        115,315        166,653

Operating income                        72,038         40,273          31,765         190,373         98,231         92,142
Other income (expense):
Net gain (loss) on derivative
instruments                            (22,441 )       71,224         (93,665 )        33,568         67,105        (33,537 )
Interest expense                       (20,979 )       (6,786 )       (14,193 )       (48,952 )      (18,745 )      (30,207 )
Other income                             1,147            524             623           2,521          1,215          1,306

Total other income (expense)           (42,273 )       64,962        (107,235 )       (12,863 )       49,575        (62,438 )

Income before income taxes              29,765        105,235         (75,470 )       177,510        147,806         29,704
Income tax expense                      11,451         38,946         (27,495 )        66,712         55,015         11,697

Net income                          $   18,314      $  66,289      $  (47,975 )    $  110,798      $  92,791      $  18,007

Cost and expense (per Boe of
production):
Lease operating expenses (1)        $     7.23      $    9.00      $    (1.77 )    $     6.68      $    8.43      $   (1.75 )
Marketing, transportation and
gathering expenses                        1.23           0.23            1.00            1.28           0.32           0.96
Production taxes                          7.36           8.33           (0.97 )          7.63           8.77          (1.14 )
Depreciation, depletion and
amortization                             25.85          19.57            6.28           24.75          19.02           5.73
General and administrative
expenses                                  6.22           6.86           (0.64 )          6.97           7.91          (0.94 )

(1) For the three and nine months ended September 30, 2011, lease operating expenses exclude marketing, transportation and gathering expenses to conform such amounts to current year classifications.

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Lease operating expenses. Lease operating expenses increased $6.5 million to $16.1 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. This increase was primarily due to the costs associated with operating an increased number of producing wells. Lease operating expenses decreased from $9.00 per Boe for the three months ended September 30, 2011 to $7.23 per Boe for the three months ended September 30, 2012, primarily due to decreased costs in salt water disposal ("SWD"), described below. These reductions were partially offset by additional costs related to wells coming on in areas without infrastructure and an increase in non-operated lease operating expenses in the third quarter of 2012.

We have $74 million in our 2012 capital budget primarily allocated to building SWD infrastructure, which is currently being deployed in our key operating areas. This infrastructure is expected to reduce our dependence on trucks for water hauling and simplify operational logistics. As of September 30, 2012, we had approximately 35% of operated water production flowing through our operated pipeline system. We expect to have approximately 50% of operated water production flowing through the pipeline system by year-end 2012. Additionally, we currently dispose of approximately 60% of our operated water production at our operated disposal wells and expect this to increase to 85% by year-end 2012. This continued expansion of our SWD systems is expected to reduce lease operating expenses related to SWD throughout the remainder of 2012.

Well services operating expenses. The $5.4 million in well services operating expenses represents non-affiliated fracturing service costs incurred by OWS for fracturing jobs completed in the third quarter of 2012. There were no well services operating expenses during the third quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Marketing, transportation and gathering expenses. This line item includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $2.5 million increase quarter over quarter, or $1.00 increase per Boe, is mainly attributable to increased oil transportation costs related to OPM, which did not commence operations until late in the third quarter of 2011.


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Production taxes. Our production taxes for the three months ended September 30, 2012 and 2011 were 9.2% and 10.1%, respectively, as a percentage of oil and natural gas sales. The third quarter 2012 production tax rate was lower than the third quarter 2011 production tax rate primarily due to certain new wells in Montana that are subject to lower incentivized production tax rates.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $36.8 million to $57.7 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. This increase in DD&A expense for the three months ended September 30, 2012 was primarily a result of our production increases from our wells completed during the last quarter of 2011 and the first three quarters of 2012. The DD&A rate for the three months ended September 30, 2012 was $25.85 per Boe compared to $19.57 per Boe for the three months ended September 30, 2011. The higher DD&A rate was a result of the increase in well costs in 2012, which outpaced the increase in associated reserves due to increases in service costs in the Williston Basin throughout the year and the addition of infrastructure assets, primarily our SWD systems.

Impairment of oil and gas properties. During the three months ended September 30, 2012 and 2011, we recorded non-cash impairment charges of $36,000 and $0.4 million, respectively, for unproved property leases that expired during the period or have been forecasted to expire under our current drilling plans. No impairment charges of proved oil and gas properties were recorded for the three months ended September 30, 2012 or 2011.

General and administrative expenses. Our general and administrative ("G&A") expenses increased $6.6 million for the three months ended September 30, 2012 from $7.3 million for the three months ended September 30, 2011. Of this . . .

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