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| VOG > SEC Filings for VOG > Form 10-Q on 8-May-2012 | All Recent SEC Filings |
8-May-2012
Quarterly Report
The following discussion and analysis of our financial condition and results of operations should be read together with our financial statements appearing in this Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties because they are based on current expectations and relate to future events and future financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many important factors, including those set forth in our Annual Report on Form 10-K under the heading "Risk Factors".
Overview
Voyager Oil & Gas, Inc., a Montana corporation ("Voyager," the "Company," "we," "us," or "our"), was formed for the purpose of acquiring acreage and non-operated working interests in existing or planned hydrocarbon production, primarily focusing on acquiring working interests in scalable, repeatable oil and natural gas plays where established oil and natural gas companies have operations.
Our business currently focuses on oil and natural gas properties primarily located in Montana and North Dakota and, to a lesser extent, Colorado and Wyoming. We do not intend to limit our focus to any single geographic area because we want to remain flexible and intend to pursue the best opportunities available to us. Our required capital commitments may grow if the opportunity presents itself and depending upon the results of initial testing of wells and development activities.
Our primary focus is to acquire high value leasehold interests specifically targeting shale resource prospects in the continental United States. Because of our size and maneuverability, we are able to deploy our land acquisition personnel into specific areas based on the latest industry information. We generate revenue by and through the conversion of our leasehold into non-operated working interests in multiple wells primarily located in the Bakken and Three Forks oil shale. We believe our drilling participation, primarily on a heads-up, or pro rata, basis proportionate to our working interest, will allow us to deliver high value with low cost.
We are also currently engaged in a top-leasing program in targeted areas of the Williston Basin. A top-lease is a lease acquired prior to and commencing immediately upon the expiration of the current lease. We believe this approach allows us to access the most prolific areas of the Bakken and Three Forks oilfields. Existing lease terms vary significantly once an area initially becomes productive. We continue to see this approach met with success, as the delineation of the Williston Basin continues to evolve given the rapidly expanding nature of the productive area of the play.
We explore, develop and produce oil and natural gas through a non-operated business model. We participate in the drilling process through the inclusion of our acreage within operators' drilling units. As a non-operator, we rely on our operating partners to propose, permit and engage in the drilling process. Before a well is spud, the operator is required to provide all oil and natural gas interest owners in the designated well unit the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production. It is our policy and goal to engage and participate on a heads-up, or pro rata, basis in substantially all, if not all, proposed wells. This model provides us with diversification across operators and geologic areas. It also allows us to continue to add production at a low marginal cost and maintain general and administrative costs at minimal levels.
Assets and Acreage Holdings
As of March 31, 2012, we controlled approximately 144,000 net acres in the following five primary prospect areas:
• 33,000 net acres targeting the Bakken and Three Forks formations in North Dakota and Montana;
• 2,400 net acres targeting the Niobrara formation in Colorado and Wyoming;
• 800 net acres targeting a Red River prospect in Montana;
• 74,700 net acres in a joint venture in and around the Tiger Ridge natural gas field in Blaine, Hill and Chouteau Counties of Montana; and
• 33,500 net acres in a joint venture targeting the Heath shale formation in Musselshell, Petroleum, Garfield and Fergus Counties of Montana.
Williston Basin - Bakken and Three Forks
We currently control approximately 33,000 net acres in the Williston Basin. During 2011, we acquired approximately 8,354 net acres primarily in Williams and McKenzie Counties, North Dakota and Richland County, Montana. On May 24, 2011, we purchased certain leases consisting of approximately 1,680 net acres in Williams County, North Dakota and Richland County, Montana for a total purchase price of $2,514,863. On May 27, 2011, we purchased certain leases consisting of approximately 1,195 net acres in Richland County, Montana for a total purchase price of $1,792,950. We also completed other acquisitions in the Williston Basin of Montana and North Dakota during the year ended December 31, 2011, and totaling $1,957,246 during the three months ended March 31, 2012.
During the first quarter 2012, we acquired 899 net acres in the Williston Basin at an average lease bonus cost of $2,100 per acre. 100% of the acreage acquired during the quarter either had an authorization for expenditure ("AFE") from a well operator attached to the lease, or we subsequently received an AFE. We have participated in 160 gross (7.05 net) Bakken and Three Forks oil wells, including 118 gross (5.03 net) wells that are producing as of March 31, 2012. The remaining 42 gross (2.02 net) wells are in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of March 31, 2012. We continue to lease prospective acreage targeting non-operated working interests in delineated areas of high quality production.
D-J Basin - Niobrara
We announced the Niobrara development program with Slawson Exploration Company, Inc. on June 28, 2010. We participated on a heads-up, or pro rata, basis for a 50% working interest in six exploratory wells in Weld County, Colorado targeting the Niobrara formation. Following the results of the initial three test wells, we allowed approximately 7,500 acres of our initial 17,000 acres of state leases in Weld County, Colorado to expire on November 15, 2010. Three additional wells were drilled during the first quarter of 2011 and in production as of December 31, 2011. We allowed approximately 7,100 additional acres to expire on November 15, 2011. We currently hold approximately 2,400 net acres in Weld County, Colorado and Laramie County, Wyoming. We currently have no plans for drilling any additional development wells in the DJ Basin in 2012.
Major Joint Venture - Tiger Ridge Natural Gas
We control approximately 74,700 net acres in and around the Tiger Ridge natural gas field in Montana. We participated in the drilling of two wells with Devon Energy Corporation, both of which were drilled and shut-in in 2010. We conducted 3-D seismic testing throughout 2010 and drilled and completed six exploratory wells in the fourth quarter of 2011 with our joint venture partners, Hancock Enterprises and MCR, LLC, as operators. We have an average working interest of 70% in these initial wells. These wells are currently awaiting pipeline hook-up.
Big Snowy Joint Venture - Heath Oil Shale
We own approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath oil shale. We have begun to see substantial permitting activity and drilling in the area. We believe the Heath shale has similar characteristics to the Bakken and Three Forks formations, and several of the same development partners are operating in the area.
Productive Wells
The following table summarizes gross and net productive oil wells by state at March 31, 2012 and 2011. A net well represents our fractional working ownership interest of a gross well. The following table also does not include 42 gross (2.02 net) Bakken and Three Forks wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation as of March 31, 2012 and 35 gross (1.24 net) Bakken and Three Forks wells as of March 31, 2011.
March 31,
2012 2011
Gross Net Gross Net
North Dakota Bakken and Three Forks 108 4.06 11 0.48
Montana Bakken and Three Forks 10 0.97 - -
Colorado Niobrara 5 2.50 1 0.50
Total: 123 7.53 12 0.98
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Exploratory Wells
In 2010, we participated in the drilling of the Bushwhacker #1-24H well, which was the first well drilled in our Niobrara development program. The well was abandoned after experiencing geosteering issues during the drilling process and completion was suspended indefinitely. The dry hole costs associated with this well were $1,521,853. In 2012, we participated in the drilling of the Johnson 31-17 SWH well in an undeveloped area of Mountrail County, North Dakota with a 3.13% working interest. The well was abandoned after experiencing poor oil shows during the drilling process. The dry hole costs associated this well were $149,714. The costs associated with each of these wells were included in the full cost pool and subject to the depletion base. Of the 123 gross productive wells that we have participated in, these have been the only wells that we have participated in that were dry holes.
Results of Operations
Comparison of the Three Months Ended March 31, 2012 with the Three Months Ended
March 31, 2011.
Three Months Three Months
Ended Ended
March 31, March 31,
2012 2011
REVENUES
Oil Sales $ 5,024,099 $ 830,123
Natural Gas Sales 74,234 2,498
Total Oil and Natural Gas Sales 5,098,333 832,621
Realized Loss on Commodity Derivatives (27,543 ) -
Unrealized Loss on Commodity Derivatives (884,892 ) -
Revenues 4,185,898 832,621
OPERATING EXPENSES
Production Expenses 466,630 49,978
Production Taxes 506,021 79,964
General and Administrative Expenses 942,131 694,314
Depletion of Oil and Natural Gas Properties 1,998,059 407,984
Depreciation and Amortization 11,070 787
Accretion of Discount on Asset Retirement Obligation 2,567 261
Total Operating Expenses 3,926,478 1,233,288
INCOME (LOSS) FROM OPERATIONS 259,420 (400,667 )
OTHER INCOME (EXPENSE)
Interest Expense (515,790 ) (495,479 )
Other Income (Expense), Net - 6,372
Total Other Expense, Net (515,790 ) (489,107 )
LOSS BEFORE INCOME TAXES (256,370 ) (889,774 )
INCOME TAX EXPENSE - -
NET LOSS $ (256,370 ) $ (889,774 )
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Revenues
The following table presents information about our revenues and produced oil and natural gas volumes during the three months ended March 31, 2012, compared to the three months ended March 31, 2011. As of March 31, 2012, we were selling oil and natural gas from a total of 123 gross wells (approximately 7.53 net wells), compared to 12 gross wells (0.98 net wells) at March 31, 2011. Revenues from sales of oil and natural gas were $5,098,333 during the three months ended March 31, 2012 compared to $832,621 during the three months ended March 31, 2011. Our production volumes increased 454% in the three months ended March 31, 2012, as compared to the three months ended March 31, 2011. The production primarily increased due to the addition of 4.55 net productive Bakken and Three Forks wells from April 1, 2011 to March 31, 2012. During the three months ended March 31, 2012, we realized a $91.79 average price per barrel of oil before the effect of settled oil derivatives compared to $81.66 average price per barrel of oil during the three months ended March 31, 2011. For the three months ended March 31, 2012, crude oil represented 99% of revenues and 96% of production.
All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.
Three Months Ended
March 31,
2012 2011
Oil and Natural Gas Revenues:
Oil $ 5,024,099 $ 830,123
Natural Gas 74,234 2,498
Total Oil and Natural Gas Sales 5,098,333 832,621
Production:
Oil (Bbl) 54,735 10,165
Natural Gas (Mcf) 12,777 577
Barrel of Oil Equivalent (Boe) 56,865 10,262
Average Sales Prices:
Oil (per Bbl) $ 91.79 $ 81.66
Effect of settled oil derivatives on average price (per Bbl) (0.50 ) -
Oil net of settled derivatives (per Bbl) 91.29 81.66
Natural Gas and Other Liquids (per Mcf) 5.81 4.33
Barrel of Oil Equivalent (per Boe net of settled derivatives) 89.17 81.13
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Three Months Ended
March 31,
2012 2011
Revenues:
Total Oil and Natural Gas Sales $ 5,098,333 $ 832,621
Realized Loss on Commodity Derivatives (27,543 ) -
Unrealized Loss on Commodity Derivatives (884,892 ) -
Revenues $ 4,185,898 $ 832,621
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Loss on Commodity Derivatives
Realized and unrealized commodity derivative losses were $27,543 and $884,892, respectively, for the three months ended March 31, 2012. There were no commodity derivates losses were during the three months ended March 31, 2011. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives will be offset by lower wellhead revenues in the future or any losses will be offset by higher future wellhead revenues based on the value at the settlement date. At March 31, 2012, all of our derivative contracts are recorded at their fair value, which was a net liability of $884,892. There was no net liability prior to March 31, 2012.
Expenses
Three Months Ended
March 31,
2012 2011
Costs and Expenses Per Boe of Production:
Production Expenses $ 8.21 $ 4.87
Production Taxes 8.90 7.79
G&A Expenses (Excluding Share-Based Compensation) 10.80 42.64
Shared-Based Compensation 5.76 25.02
Depletion of Oil & Natural Gas Properties 35.14 39.76
Depreciation and Amortization 0.19 0.08
Accretion of Discount on Asset Retirement Obligation 0.05 0.03
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Production Expenses
Production expenses were $466,630 during the three months ended March 31, 2012 compared to $49,978 during the three months ended March 31, 2011. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $4.87 per barrel of oil equivalent, or Boe, sold during the three months ended March 31, 2011 to $8.21 during the three months ended March 31, 2012. These increases are related to higher operating costs primarily in our Williston Basin wells. The largest cost driver in our Williston Basin wells is the disposal of water.
Production Taxes
Production taxes were $506,021 during the three months ended March 31, 2012 compared to $79,964 in the three months ended March 31, 2011. We pay production taxes based on realized crude oil and natural gas sales. Our production taxes were comparable at 9.9% during the three months ended March 31, 2012 compared to 9.6% in the three months ended March 31, 2011. Some well additions qualify for reduced rates/or tax exemptions during 2011 and 2012. Certain portions of our production occurs in Montana and North Dakota jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate.
General and Administrative Expense
General and administrative expenses were $942,131 during the three months ended March 31, 2012 compared to $694,314 during the three months ended March 31, 2011. General and administrative expenses excluding share-based compensation were $614,406 during the three months ended March 31, 2012 compared to $437,575 during the three months ended March 31, 2011. The increase is primarily due to increased professional, engineering, audit and legal expenses ($98,004) and the addition of employees and related employment expenses ($82,284). Increases in professional, audit, legal, and employment-related expenses for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 were the result of growth in infrastructure. On a per unit basis, general and administrative expenses per Boe decreased significantly as we were able to leverage our costs over a higher level of production. Share-based compensation expenses totaled $327,725 for the three months ended March 31, 2012 compared to $256,739 for the three months ended March 31, 2011.
Depletion Expense
Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $1,998,059for the three months ended March 31, 2012 compared to $407,984 for the three months ended March 31, 2011. On a per-unit basis, depletion expense was $35.14 per Boe for the three months ended March 31, 2012 compared to $39.76 per Boe for the three months ended March 31, 2011. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by independent petroleum engineers. This increase in depletion expense for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 was due primarily to the addition of 6.55 net productive wells from April 1, 2011 to March 31, 2012.
Other Expense
Other expense was $515,790 for the three months ended March 31, 2012 compared to $489,107 for the three months ended March 31, 2011. Interest expense, the largest component of other expense, was $515,790 for the three months ended March 31, 2012 compared to $495,479 for the three months ended March 31, 2011. The increase in interest expense resulted from the payment in full of the outstanding senior secured notes on February 10, 2012 and the resulting expense of unamortized financing costs associated with the notes, which totaled $217,809 for the three months ended March 31, 2012.
Net loss
We had a net loss of $256,370 for the three months ended March 31, 2012 compared to a net loss of $889,774 for the three months ended March 31, 2011 (representing $(0.00) and $(0.02) per share, respectively). The improvement in our period-over-period results was driven by revenue and production from oil and natural gas properties growing at a faster rate than general and administrative and other expenses, including interest and financing costs.
Non-GAAP Financial Measures
Adjusted EBITDA
In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before interest, income taxes, depreciation, depletion, and amortization, accretion of discount on asset retirement obligations, unrealized gain (loss) from mark-to-market on commodity derivatives and non-cash expenses relating to share based payments recognized under ASC Topic 718 ("adjusted EBITDA"), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings after adjustment for those items described in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss) (its most directly comparable GAAP measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating its fundamental core operating performance. We also believe that adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view adjusted EBITDA in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the periods presented:
Three Months Ended
March 31,
2012 2011
Net loss $ (256,370 ) $ (889,774 )
Interest expense 515,790 495,479
Accretion of asset retirement obligations 2,567 261
Depreciation, depletion and amortization 2,009,129 408,771
Stock-based compensation 327,725 256,739
Unrealized loss on commodity derivatives 884,892 -
Adjusted EBITDA $ 3,483,733 $ 271,476
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Adjusted Income
In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before the effect of unrealized gain (loss) from mark-to-market on commodity derivatives ("adjusted income"), which is a non-GAAP performance measure. Adjusted income consists of net earnings after adjustment for those items described in the table below. Adjusted income does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating its fundamental core operating performance. We also believe that adjusted income is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses adjusted income to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view adjusted income in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss), to adjusted income for the periods presented:
Three Months Ended
March 31,
2012 2011
Net loss $ (256,370 ) $ (889,774 )
Unrealized loss on commodity derivatives 884,892 -
Adjusted income (loss) $ 628,522 $ (889,774 )
Adjusted income (loss) per share - basic $ 0.01 $ (0.02 )
Weighted average shares outstanding - basic 57,860,519 52,567,631
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Liquidity and Capital Resources
Liquidity is a measure of a company's ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of common stock and by short-term borrowings. In the future, we anticipate we will be able to provide the necessary liquidity from the revenues generated from the sales of our oil and natural gas reserves in our existing properties and availability under our credit facility; however, if we do not generate sufficient cash flow from operations or do not have availability under our credit facility we may attempt to continue to finance our operations through equity and/or debt financings.
The following table summarizes total current assets, total current liabilities and working capital at March 31, 2012.
Current assets $ 10,432,140 Current liabilities $ 25,406,565 Working capital (deficit) $ (14,974,425 ) |
Equity Offerings
On February 8, 2011, we completed a private placement to accredited investors of 12,500,000 shares of common stock. The net proceeds from this sale of common stock were approximately $46.6 million after deducting placement agent fees and estimated offering expenses. We also issued 6,250,000 warrants to subscribers of the private placement concurrently with the sale of shares. The warrants have an exercise price of $7.10, and a five-year term from the date of the closing. We . . .
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