Exhibit 99.1
Voyager Oil & Gas, Inc. Reports Record Quarterly Production Volumes and Adjusted EBITDA for its Second Quarter Ended June 30, 2012
BILLINGS, MONTANA – August 6, 2012 --- Voyager Oil & Gas, Inc. (NYSE MKT: VOG) (“Voyager”, the “Company” or “we”), announces Company record oil production, revenue and Adjusted EBITDA* for the second quarter ended June 30, 2012. The final unaudited Quarterly Report will be released and filed on or about August 6, 2012.
Second Quarter 2012 Highlights
| · | Record quarterly oil production of 85,363 barrels of oil equivalent (BOE), or an average of 938 barrels of oil equivalent per day (BOEPD). Second quarter production was up 50% from 56,865 BOE (625 BOEPD) in the previous quarter ended March 31, 2012; |
| · | Record oil and natural gas sales of $6,763,429 (99% of which is attributable to the sale of crude oil), up 33% from $5,098,333 in the first quarter ending March 31, 2012; |
| · | Adjusted EBITDA* of $4,811,883 up 38% from $3,483,733 in the quarter ended March 31, 2012; and |
| · | Adjusted income* of $1,067,351 or $0.02 per share (basic and diluted) for the three months ended June 30, 2012. |
* Non-GAAP financial measure. Please see Adjusted EBITDA and Adjusted Income tables later in this earnings release for a reconciliation of these measures to their nearest comparable GAAP measure.
Second Quarter 2012 Financial Results
During the quarter ended June 30, 2012, Voyager reports oil and natural gas sales of $6,763,429, which represents an increase of 33% from $5,098,333 during the first quarter ending March 31, 2012 and an increase of 306% from $1,666,535 in the year ago quarter ended June 30, 2011. This increase in revenue is due primarily to production from 150 gross (6.56 net) wells producing in the Bakken and Three Forks formations as of June 30, 2012, compared to 118 gross (5.03 net) wells and 24 gross (1.13 net) wells producing in the same formations as of March 31, 2012 and June 30, 2011, respectively. Production accelerated throughout the quarter with 35% of the quarterly production (29,721 BOE or about 991 BOEPD) during the month of June. Crude oil represented 99% of revenue and 95% of production during the second quarter 2012.
| June 30, 2012 | June 30, 2011 | |||||||||||||||
| Williston Basin Wells | Gross | Net | Gross | Net | ||||||||||||
| Wells at Beginning of Quarter | 118 | 5.03 | 11 | 0.48 | ||||||||||||
| Wells Added to Production | ||||||||||||||||
| During the Quarter | 32 | 1.53 | 13 | 0.65 | ||||||||||||
| Producing Wells at Quarter End | 150 | 6.56 | 24 | 1.13 | ||||||||||||
| Drilling, Awaiting Completion, | ||||||||||||||||
| or Completing at Quarter End | 30 | 1.10 | 39 | 1.20 | ||||||||||||
| Participating Wells at Quarter End | 180 | 7.66 | 63 | 2.33 | ||||||||||||
Exhibit 99.1
As of June 30, 2012, Voyager had interests in a total of 180 gross (7.66 net) wells in the Bakken and Three Forks formations, of which 150 gross (6.56 net) wells were producing and 30 gross (1.10 net) wells were in the process of being drilled or completed. Permits continue to be issued for drilling units in which Voyager has acreage interests within North Dakota and Montana, and activity in the Williston Basin remains strong.
Adjusted EBITDA for the second quarter 2012 was a record $4,811,883, up 38% from $3,483,733 during the first quarter ended March 31, 2012 and up 530% from $763,866 during the second quarter ended June 30, 2011. The increase in adjusted EBITDA was driven by increased production and improved operating leverage as production scale increased. Adjusted EBITDA per BOE for the quarter ended June 30, 2012 was $56.37, compared to $61.26 during the first quarter ended March 31, 2012 and $42.76 during the year ago quarter ended June 30, 2011. Adjusted EBITDA per BOE during the second quarter 2012 was lower than first quarter 2012 due mostly to a nearly $8 decrease in realized crude oil prices during the quarter as the average crude oil price of NYMEX West Texas Intermediate (NYMEX) was about $103 per barrel during first quarter 2012 and about $93 per barrel during second quarter 2012.
| Three Months Ended | ||||||||||||||||||||
| Jun. 30, | Mar. 31, | Dec. 31, | Sep. 30, | Jun. 30, | ||||||||||||||||
| 2012 | 2012 | 2011 | 2011 | 2011 | ||||||||||||||||
| Net Production: | ||||||||||||||||||||
| Crude Oil (Barrels) | 81,323 | 54,735 | 35,569 | 32,088 | 17,695 | |||||||||||||||
| Crude Oil Mix | 95 | % | 96 | % | 97 | % | 96 | % | 99 | % | ||||||||||
| Natural Gas and Other Liquids (Mcf) | 24,237 | 12,777 | 5,971 | 7,387 | 1,027 | |||||||||||||||
| Total Net Production (BOE) | 85,363 | 56,865 | 36,564 | 33,319 | 17,866 | |||||||||||||||
| Quarter-Over-Quarter Increase | 50 | % | 56 | % | 10 | % | 86 | % | 74 | % | ||||||||||
| Average Daily Production (BOEPD) | 938 | 625 | 397 | 362 | 196 | |||||||||||||||
| Quarter-Over-Quarter Increase | 50 | % | 57 | % | 10 | % | 84 | % | 72 | % | ||||||||||
| Average Sales Prices: | ||||||||||||||||||||
| Crude Oil Per Barrel | $ | 82.34 | $ | 91.79 | $ | 83.98 | $ | 87.83 | $ | 93.88 | ||||||||||
| Effect of Settled Oil Derivatives Per Barrel | $ | 1.09 | ($ | 0.50 | ) | -- | -- | -- | ||||||||||||
| Crude Oil Net of Settled Derivatives Per Barrel | $ | 83.43 | $ | 91.29 | $ | 83.98 | $ | 87.83 | $ | 93.88 | ||||||||||
| Natural Gas and Other Liquids Per Mcf | $ | 2.78 | $ | 5.81 | $ | 11.29 | $ | 7.35 | $ | 5.30 | ||||||||||
| Realized Price Per BOE(a) | $ | 80.27 | $ | 89.17 | $ | 83.53 | $ | 86.22 | $ | 93.28 | ||||||||||
| Average Per BOE: | ||||||||||||||||||||
| Production Expenses | $ | 5.68 | $ | 8.21 | $ | 8.40 | $ | 6.65 | $ | 8.30 | ||||||||||
| Production Taxes | $ | 8.54 | $ | 8.90 | $ | 6.25 | $ | 7.25 | $ | 9.37 | ||||||||||
| G&A Expenses, Excl. Shared-Based Comp. | $ | 9.55 | $ | 10.80 | $ | 16.63 | $ | 10.76 | $ | 30.99 | ||||||||||
| Total | $ | 23.77 | $ | 27.91 | $ | 31.28 | $ | 24.66 | $ | 48.66 | ||||||||||
| Adjusted EBITDA per BOE | $ | 56.37 | $ | 61.26 | $ | 52.32 | $ | 61.63 | $ | 42.76 | ||||||||||
| Williston Basin Acreage: | ||||||||||||||||||||
| Total Net Acres at End of Period | 33,031 | 32,823 | 31,957 | 30,821 | 28,027 | |||||||||||||||
| Net Acres Added | 208 | 866 | 1,136 | 2,794 | 28,027 | |||||||||||||||
| Average Cost / Acre Acquired During Period | $ | 2,000 | $ | 2,100 | $ | 2,116 | $ | 1,441 | $ | 1,548 | ||||||||||
| % of Net Acres Held By Production(b) | 34 | % | 29 | % | 24 | % | 20 | % | 10 | % | ||||||||||
(a) Realized Price includes realized gains or losses on cash settlements for commodity derivatives.
(b) Based on a 1,280-acre spacing unit.
Exhibit 99.1
Gain on Commodity Derivatives
Realizedcommodity derivative gains were $88,568 and $61,025, for the three and six months ended June 30, 2012, respectively. Unrealized commodity derivative gains were $2,162,975 and $1,278,083, for the three and six months ended June 30, 2012, respectively. There were no commodity derivatives losses during the three and six months ended June 30, 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. Future derivative gains will be offset by lower future wellhead revenues. Conversely, future derivative losses will be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2012, all of our derivative contracts are recorded at their fair value, which was a net asset of $1,278,083. We did not incur any net asset or liability with respect to derivative contracts prior to January 1,2012.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net Revenues: | ||||||||||||||||
| Total Oil and Natural Gas Sales | $ | 6,763,429 | $ | 1,666,535 | $ | 11,861,762 | $ | 2,499,156 | ||||||||
| Realized Gain on Commodity Derivatives | 88,568 | — | 61,025 | — | ||||||||||||
| Unrealized Gain on Commodity Derivatives | 2,162,975 | — | 1,278,083 | — | ||||||||||||
| Revenues | $ | 9,014,972 | $ | 1,666,535 | $ | 13,200,870 | $ | 2,499,156 | ||||||||
Liquidity
As of June 30, 2012, Voyager had $4,113,794 in cash and total debt outstanding of $18,030,730. Voyager has a credit facility with Macquarie Bank Ltd. (“Macquarie Bank”) that provides up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. As of June 30, 2012, $15,000,000 was outstanding under Voyager’s Tranche A credit facility and $3,030,730 was outstanding under our Tranche B facility. As of June 30, 2012, $7.7 million was undrawn and available pursuant to an approved development plan.
On July 26, 2012, Voyager entered into an amended and restated credit agreement with Macquarie Bank to expand the existing availability and outstanding balance under its existing credit facility. In addition to the $20.2 million of debt obligations related to the July 26, 2012 acquisition of Emerald Oil Inc. (“Emerald Oil”) that remain outstanding through existing agreements, the Company obtained additional availability from its credit facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable London Interbank Borrowing Rate (LIBOR) and has the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities. The new tranche matures on November 15, 2012 while Tranche A and Tranche B maintain the original maturity date of February 10, 2015. Tranche B is uncommitted; however, Macquarie Bank may, in its sole discretion and subject to an approved revised development plan and the satisfaction of certain conditions, commit additional funds under Tranche B.
Exhibit 99.1
Impairment of Oil and Gas Properties
Wefollow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the condensed statements of operations as an impairment charge. We recognized an impairment expense in the three- and six-month periods ended June 30, 2012 in the amount of $10,191,234. Included in the full cost pool at June 30, 2012 were costs incurred in 2010 and 2011 associated with the Company’s interest in the Niobrara development program in the Denver-Julesburg Basin. We incurred approximately $23.6 million in development costs to acquire acreage and develop the program, with insufficient oil and natural gas reserves established as a result of the development in the third-party reserve engineer’s reserve report to offset the costs of the development program. While the costs were incurred in 2010 and 2011, we did not fail the ceiling test until June 30, 2012. The failure was primarily due to a decrease in the 12-month average commodity price and an increase in the local differential to NYMEXWest Texas Intermediateon Williston Basin properties on the June 30, 2012 reserve report compared to March 31, 2012 and December 31, 2011 reserve reports. We did not recognize any impairment expense in the three- and six-month periods ended June 30, 2011.
Recent Well Completions
The following table illustrates certain recent well completions in which Voyager has participated with a working interest during the second quarter of 2012, listing all wells added to production with a working interest of at least 1.5%:
| Well Name | Operator | County, ST | Working Interest(1) | BOPD IP Rate(2) | Note(3) | |||||||||||||
| Berger 156-100-7-6-1H | Liberty | Williams, ND | 21.02 | % | 2,719 | B | ||||||||||||
| Schnitzler 34-24 TFH | Whiting | Roosevelt, MT | 12.50 | % | 200 | B | ||||||||||||
| Moe 29-32-162-100H1CN | Baytex | Divide, ND | 12.50 | % | 78 | A | ||||||||||||
| Sylte Mnrl T 157-101-25B-36-1H | Petro-Hunt | Williams, ND | 12.50 | % | 490 | A | ||||||||||||
| Ingerson 2-12-1H | Cornerstone | Burke, ND | 12.50 | %*** | C | |||||||||||||
| Hunter 1-H 17-20 | Continental | Williams, ND | 8.64 | % | 683 | A | ||||||||||||
| Inga 150-99-11-2-2H | Newfield | McKenzie, ND | 8.33 | % | 1,876 | A | ||||||||||||
| Inga 150-99-11-2-3H | Newfield | McKenzie, ND | 8.33 | % | 1,654 | A | ||||||||||||
| Inga 150-99-11-2-10H | Newfield | McKenzie, ND | 8.33 | % | 1,023 | A | ||||||||||||
| A & B 1-30-31H | G3 | Williams, ND | 7.43 | % | 626 | A | ||||||||||||
| Johnson 43-27 ENH | Denbury | Dunn, ND | 6.87 | % | 1,105 | A | ||||||||||||
| Chrome 155-99-18-19-1H | Continental | Williams, ND | 6.61 | % | 512 | A | ||||||||||||
| Abercrombie 1-10H | Continental | Richland, MT | 6.25 | % | 630 | B | ||||||||||||
| McClintock 1-1H | Continental | Williams, ND | 3.21 | % | 929 | B | ||||||||||||
| Hoidahl 1-16H | Continental | Divide, ND | 3.13 | % | 537 | B | ||||||||||||
| Larsen 32-29 #1H | Zavanna | McKenzie, ND | 3.13 | % | 682 | A | ||||||||||||
| Johnson 43-27 WNH | Denbury | Dunn, ND | 2.34 | % | 939 | A | ||||||||||||
| Bouchard 34-21H | Fidelity | Richland, MT | 2.24 | % | 133 | B | ||||||||||||
| GO-Kupper ###-##-####H-1 | Hess | Williams, ND | 1.56 | % | 592 | A | ||||||||||||
____________________
| (1) | The working interests are based on Voyager’s internal records and may be subject to change by operators’ third-party legal counsel in preparing final division order title opinions for each well. |
| (2) | The initial production rate (“IP Rate”) for each well expressed in barrels of oil per day (“BOPD”) and does not include associated natural gas production. Initial production is generally the 24-hour “Peak Production Rate” that may be measured following the initial day of production, depending on operator procedure or well profiles, although the calculation may vary from operator to operator. The IP Rate may be estimated based on other third-party estimates or limited data available at the time. |
| (3) | NOTE: A) IP Rate obtained from North Dakota Industrial Commission (“NDIC”). B) IP Rate was not reported by the operator to the NDIC. Voyager estimated an IP Rate based on the highest single day production over the first 30 days if available. This estimate may or may not reflect the IP Rate calculated by the operator. C) IP Rate not provided by operator. Voyager did not receive individual daily production from the operator and was not able to calculate an estimated IP Rate. |
Exhibit 99.1
Current Drilling Activity
The following table illustrates the 30 gross (1.10 net) wells in the Bakken or Three Forks formations drilling, awaiting completion or completing in which Voyager is participating with a working interest as of June 30, 2012:
| Working | ||||||||||||
| Well Name | Operator | County, State | Interest(1) | Status | ||||||||
| Orcas State 5601 13-16H | Oasis | Williams, ND | 9.38 | % | Awaiting Completion | |||||||
| Horse Creek Federal 5004 42-35H | Oasis | McKenzie, ND | 9.37 | % | Awaiting Completion | |||||||
| Longhorn 9-4-158-99H | Samson | Williams, ND | 6.25 | % | Awaiting Completion | |||||||
| Salsbury 24-35-1H | Whiting | Richland, MT | 6.25 | % | Awaiting Completion | |||||||
| Wolverine Federal #1-31-30H | Slawson | McKenzie, ND | 6.10 | % | Awaiting Completion | |||||||
| Randy Olson 8-5-161-98H 1PB | Baytex | Divide, ND | 5.16 | % | Awaiting Completion | |||||||
| Bogner 13-20H | SM Energy | Stark, ND | 4.47 | % | Awaiting Completion | |||||||
| Mott 1-16H | Continental | Richland, MT | 3.25 | % | Awaiting Completion | |||||||
| Bakke 1-17H | Continental | Divide, ND | 3.13 | % | Awaiting Completion | |||||||
| Polar Vance 154-97-2-17-5-5H | Kodiak | Williams, ND | 1.83 | % | Awaiting Completion | |||||||
| Hatchet Federal #1-23-14H | Slawson | McKenzie, ND | 1.30 | % | Awaiting Completion | |||||||
| Schmidt 5602 42-10H | Oasis | Williams, ND | 1.25 | % | Awaiting Completion | |||||||
| TAT 13-35-26H | Helis | McKenzie, ND | 0.27 | % | Awaiting Completion | |||||||
| Mae 5603 43-19H | Oasis | Williams, ND | 0.02 | % | Awaiting Completion | |||||||
| Ross-Alger 6-7 #2TFH | Brigham | Mountrail, ND | 7.71 | % | Drilling | |||||||
| Gullikson 152-103-31-30-1H | Liberty | McKenzie, ND | 6.26 | % | Drilling | |||||||
| Wolverine Federal #4-31-30TFH | Slawson | McKenzie, ND | 6.10 | % | Drilling | |||||||
| O Bach 29-32H | Fidelity | Stark, ND | 5.47 | % | Drilling | |||||||
| BW-Erler ###-##-####H-1 | Hess | McKenzie, ND | 4.73 | % | Drilling | |||||||
| Mary Sveet 34-21H | Marathon | Williams, ND | 4.38 | % | Drilling | |||||||
| CPEUSC Clermont 18-19-158N-100W | Crescent Point | Williams, ND | 3.09 | % | Drilling | |||||||
| AV-A And S Trust 162-94-17H-1 | Hess | Burke, ND | 2.92 | % | Drilling | |||||||
| Shepherd 5501 12-5H | Oasis | Williams, ND | 2.59 | % | Drilling | |||||||
| Hardscrabble 3-3328H | EOG | Williams, ND | 2.25 | % | Drilling | |||||||
| Taylor 14-23 #1H | Brigham | McKenzie, ND | 1.88 | % | Drilling | |||||||
| Sherri 2658 43-9H | Oasis | Richland, MT | 1.56 | % | Drilling | |||||||
| Tobacco Garden 31-29 SEH | Denbury | McKenzie, ND | 1.42 | % | Drilling | |||||||
| Davies 1-20H | Continental | Richland, MT | 0.94 | % | Drilling | |||||||
| Pederson #1-18-19H | G3 | Williams, ND | 0.40 | % | Drilling | |||||||
| State 154-102-25-36-1H | Triangle | Williams, ND | 0.16 | % | Drilling | |||||||
____________________
| (1) | The working interests are based on Voyager’s internal records and may be subject to change by operators’ third-party legal counsel in preparing final division order title opinions for each well. |
Exhibit 99.1
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, impairment of oil and natural gas properties, 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 | ||||||||||||||||||||
| Jun. 30, | Mar. 31, | Dec. 31, | Sep. 30, | Jun. 30, | ||||||||||||||||
| 2012 | 2012 | 2011 | 2011 | 2011 | ||||||||||||||||
| Net income (loss) | ($ | 6,960,908 | ) | ($ | 256,370 | ) | ($ | 46,097 | ) | $ | 55,874 | ($ | 465,057 | ) | ||||||
| Impairment of oil and natural gas properties | 10,191,234 | - | - | - | - | |||||||||||||||
| Interest expense | 169,445 | 515,790 | 525,616 | 508,841 | 506,096 | |||||||||||||||
| Accretion of asset retirement obligation | 3,423 | 2,567 | 1,576 | 1,717 | 1,328 | |||||||||||||||
| Depreciation, depletion and amortization | 3,171,512 | 2,009,129 | 1,264,437 | 1,335,620 | 568,469 | |||||||||||||||
| Stock-based compensation expense | 400,152 | 327,725 | 167,434 | 151,343 | 153,030 | |||||||||||||||
| Unrealized (gain) loss on commodity derivatives | (2,162,975 | ) | 884,892 | - | - | - | ||||||||||||||
| Adjusted EBITDA | $ | 4,811,883 | $ | 3,483,733 | $ | 1,912,966 | $ | 2,053,395 | $ | 763,866 | ||||||||||
Exhibit 99.1
Adjusted Income
In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before the impairment of oil and natural gas properties and 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 our 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 June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net loss | $ | (6,960,908 | ) | $ | (465,057 | ) | $ | (7,217,278 | ) | $ | (1,354,831 | ) | ||||
| Impairment of oil and natural gas properties | 10,191,234 | — | 10,191,234 | — | ||||||||||||
| Unrealized gain on commodity derivatives | (2,162,975 | ) | — | (1,278,083 | ) | — | ||||||||||
| Adjusted income (loss) | $ | 1,067,351 | $ | (465,057 | ) | $ | 1,695,873 | $ | (1,354,831 | ) | ||||||
| Adjusted income (loss) per share – basic | $ | 0.02 | $ | (0.01 | ) | $ | 0.03 | $ | (0.02 | ) | ||||||
| Adjusted income (loss) per share – diluted | $ | 0.02 | $ | (0.01 | ) | $ | 0.03 | $ | (0.02 | ) | ||||||
| Weighted average shares outstanding – basic | 57,994,582 | 57,379,515 | 57,927,550 | 54,753,703 | ||||||||||||
| Weighted average shares outstanding – diluted | 58,814,046 | 57,379,515 | 58,856,127 | 54,753,703 | ||||||||||||
Exhibit 99.1
Derivative Instruments and Price Risk Management
The Company utilizes commodity costless collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.
All derivative positions are carried at their fair value on the condensed balance sheet and are marked-to-market at the end of each period. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the loss on derivatives line on the condensed statement of operations.
Costless collars are used to establish floor and ceiling prices on anticipated oil and natural gas production. There were no premiums paid to or received by the Company related to the costless collar agreements. The following table reflects open costless collar agreements as of June 30, 2012.
| Term | Oil (Barrels) | Price | Basis | |||||||||
| Costless Collars | ||||||||||||
| April 1, 2012 – February 28, 2015 | 225,542 | $ | 90.00–$103.50 | NYMEX |
OnJuly 26, 2012, in conjunction with the closing of the amended and restated credit agreement with MBL, the Company executed a NYMEX West Texas Intermediate crude oil derivative swap contract. The following table reflects the opened commodity swap contract with the associated volumes and fixedprice.
| Fixed | ||||||||||
| Calendar Year | Volumes (Bbls) | Price | ||||||||
| August - December 2012 | 51,136 | $ | 88.00 | |||||||
| 2013 | 73,370 | $ | 88.00 | |||||||
| 2014 | 48,742 | $ | 88.00 | |||||||
| 2015 | 6,404 | $ | 88.00 | |||||||
About Voyager Oil & Gas
Voyager is an exploration and production company focused primarily on acquiring acreage and developing wells in prospective shale oil plays in the continental United States. The Company’s primary business is focused on properties in North Dakota and Montana targeting the Bakken and Three Forks shale oil formations. Voyager on a combined company basis following the acquisition of Emerald Oil owns an interest in approximately 200,000 net acres in the following areas:
| · | approximately 43,600 core net acres targeting the Bakken and Three Forks shale oil formations in North Dakota and Montana; |
| · | approximately 45,000 net acres in a joint venture in the Sandwash Basin Niobrara shale oil play, located in Mofatt and Routt Counties, Colorado and Carbon County, Wyoming; |
| · | approximately 33,500 net acres in a joint venture targeting the Heath shale oil formation in Musselshell, Petroleum, Garfield and Fergus Counties of Montana; |
| · | approximately 2,400 net acres in the Denver-Julesburg Basin targeting the Niobrara shale oil formation in Colorado and Wyoming; and |
| · | approximately 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. |
For additional information, visit Voyager’s website at: http://www.voyageroil.com/. Sign up for email alerts at: http://www.VYOG-IR.com to be notified when news items are released by Voyager.
Exhibit 99.1
Forward-Looking Statements
Certain statements included in this news release contain "forward-looking statements" within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. We caution you that assumptions, expectations, projections, intentions, plans, beliefs or similar expressions used to identify forward-looking statements about future events may, and often do, vary from actual results and the differences can be material from those expressed or implied in such forward looking statements. Some of the key factors that could cause actual results to vary from those we expect include, without limitation, volatility in commodity prices for crude oil and natural gas, access to capital markets and the condition of the capital markets generally, as well as ability to access them, the timing of planned capital expenditures, unanticipated cash flow restrictions, uncertainties in estimating reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business. We assume no obligation and expressly disclaim any duty to update the information contained herein except as required by law.
Exhibit 99.1
VOYAGER OIL & GAS, INC.
CONDENSED BALANCE SHEETS
(UNAUDITED)
| June 30, 2012 | December 31, 2011 | |||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and Cash Equivalents | $ | 4,113,794 | $ | 13,927,267 | ||||
| Trade Receivables | 7,529,588 | 3,247,412 | ||||||
| Fair Value of Commodity Derivatives | 609,147 | — | ||||||
| Prepaid Expenses | 188,151 | 48,330 | ||||||
| Total Current Assets | 12,440,680 | 17,223,009 | ||||||
| PROPERTY AND EQUIPMENT | ||||||||
| Oil and Natural Gas Properties, Full Cost Method | ||||||||
| Proved Oil and Natural Gas Properties | 102,678,532 | 60,425,243 | ||||||
| Unproved Oil and Natural Gas Properties | 31,211,108 | 32,180,217 | ||||||
| Other Property and Equipment | 177,735 | 176,238 | ||||||
| Total Property and Equipment | 134,067,375 | 92,781,698 | ||||||
| Less – Accumulated Depreciation, Depletion and Amortization | (20,877,163 | ) | (5,505,288 | ) | ||||
| Total Property and Equipment, Net | 113,190,212 | 87,276,410 | ||||||
| Prepaid Drilling Costs | 36,742 | 33,163 | ||||||
| Fair Value of Commodity Derivatives | 668,936 | — | ||||||
| Debt Issuance Costs, Net of Amortization | 427,879 | 306,839 | ||||||
| Total Assets | $ | 126,764,449 | $ | 104,839,421 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| CURRENT LIABILITIES | ||||||||
| Accounts Payable | $ | 35,457,693 | $ | 10,375,239 | ||||
| Accrued Expenses | 29,425 | 206,122 | ||||||
| Total Current Liabilities | 35,487,118 | 10,581,361 | ||||||
| LONG-TERM LIABILITIES | ||||||||
| Revolving Credit Facility | 18,030,730 | — | ||||||
| Senior Secured Promissory Notes | — | 15,000,000 | ||||||
| Asset Retirement Obligations | 198,293 | 116,119 | ||||||
| Total Liabilities | 53,716,141 | 25,697,480 | ||||||
| COMMITMENTS AND CONTINGENCIES | — | — | ||||||
| SSTOCKHOLDERS’ EQUITY | ||||||||
| Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized; None Issued or Outstanding | — | — | ||||||
| Common Stock, Par Value $.001; 200,000,000 Shares Authorized, 58,468,428 and 57,848,428 Shares Issued and Outstanding, respectively | 58,468 | 57,848 | ||||||
| Additional Paid-In Capital | 88,081,199 | 86,958,174 | ||||||
| Accumulated Deficit | (15,091,359 | ) | (7,874,081 | ) | ||||
| Total Stockholders’ Equity | 73,048,308 | 79,141,941 | ||||||
| Total Liabilities and Stockholders’ Equity | $ | 126,764,449 | $ | 104,839,421 | ||||
Exhibit 99.1
VOYAGER OIL & GAS, INC.
CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| REVENUES | ||||||||||||||||
| Oil and Natural Gas Sales | $ | 6,763,429 | $ | 1,666,535 | $ | 11,861,762 | $ | 2,499,156 | ||||||||
| Gain on Commodity Derivatives | 2,251,543 | — | 1,339,108 | — | ||||||||||||
| 9,014,972 | 1,666,535 | 13,200,870 | 2,499,156 | |||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Production Expenses | 484,829 | 148,335 | 951,459 | 198,313 | ||||||||||||
| Production Taxes | 728,588 | 167,417 | 1,234,609 | 247,381 | ||||||||||||
| General and Administrative Expenses | 1,215,218 | 706,617 | 2,157,349 | 1,400,931 | ||||||||||||
| Depletion of Oil and Natural Gas Properties | 3,160,368 | 560,344 | 5,158,427 | 968,328 | ||||||||||||
| Impairment of Oil and Natural Gas Properties | 10,191,234 | — | 10,191,234 | — | ||||||||||||
| Depreciation and Amortization | 11,144 | 8,125 | 22,214 | 8,912 | ||||||||||||
| Accretion of Discount on Asset Retirement Obligations | 3,423 | 1,328 | 5,990 | 1,589 | ||||||||||||
| Total Expenses | 15,794,804 | 1,592,166 | 19,721,282 | 2,825,454 | ||||||||||||
| INCOME (LOSS) FROM OPERATIONS | (6,779,832 | ) | 74,369 | (6,520,412 | ) | (326,298 | ) | |||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||
| Interest Expense | (169,445 | ) | (506,096 | ) | (685,235 | ) | (1,001,575 | ) | ||||||||
| Other Income (Expense), Net | (11,631 | ) | (33,330 | ) | (11,631 | ) | (26,958 | ) | ||||||||
| Total Other Expense, Net | (181,076 | ) | (539,426 | ) | (696,866 | ) | (1,028,533 | ) | ||||||||
| LOSS BEFORE INCOME TAXES | (6,960,908 | ) | (465,057 | ) | (7,217,278 | ) | (1,354,831 | ) | ||||||||
| INCOME TAX EXPENSE | — | — | — | — | ||||||||||||
| NET LOSS | $ | (6,960,908 | ) | $ | (465,057 | ) | $ | (7,217,278 | ) | $ | (1,354,831 | ) | ||||
| Net Loss Per Common Share — Basic and Diluted | $ | (0.12 | ) | $ | (0.01 | ) | $ | (0.12 | ) | $ | (0.02 | ) | ||||
| Weighted Average Shares Outstanding — Basic and Diluted | 57,994,582 | 57,379,515 | 57,927,550 | 54,753,703 | ||||||||||||
Exhibit 99.1
VOYAGER OIL & GAS, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| Six Months Ended June 30, | ||||||||
| 2012 | 2011 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net Loss | $ | (7,217,278 | ) | $ | (1,354,831 | ) | ||
| Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities: | ||||||||
| Depletion of Oil and Natural Gas Properties | 5,158,427 | 968,328 | ||||||
| Impairment of Oil and Natural Gas Properties | 10,191,234 | — | ||||||
| Depreciation and Amortization | 22,214 | 8,912 | ||||||
| Amortization of Debt Discount | — | 111,575 | ||||||
| Amortization of Finance Costs | 278,776 | — | ||||||
| Accretion of Discount on Asset Retirement Obligations | 5,990 | 1,589 | ||||||
| Unrealized Gain on Derivative Instruments | (1,278,083 | ) | — | |||||
| Share-Based Compensation Expense | 727,877 | 409,769 | ||||||
| Changes in Assets and Liabilities: | ||||||||
| Increase in Trade Receivables | (4,282,176 | ) | (1,291,411 | ) | ||||
| Increase in Prepaid Expenses | (139,821 | ) | (47,959 | ) | ||||
| Increase (Decrease) in Accounts Payable | 46,454 | (365,434 | ) | |||||
| Decrease in Accrued Expenses | (176,697 | ) | (225,498 | ) | ||||
| Net Cash Provided By (Used For) Operating Activities | 3,336,917 | (1,784,960 | ) | |||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Purchases of Other Property and Equipment | (1,497 | ) | (152,349 | ) | ||||
| Prepaid Drilling Costs | (3,579 | ) | (727,017 | ) | ||||
| Proceeds from Sales of Available for Sale Securities | — | 242,070 | ||||||
| Investment in Oil and Natural Gas Properties | (15,776,228 | ) | (23,959,151 | ) | ||||
| Net Cash Used For Investing Activities | (15,781,304 | ) | (24,596,447 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Proceeds from Issuance of Common Stock – Net of Issuance Costs | — | 46,602,251 | ||||||
| Advances on Revolving Credit Facility and Term Loan | 18,030,730 | — | ||||||
| Payments on Senior Secured Promissory Notes | (15,000,000 | ) | — | |||||
| Cash Paid for Finance Costs | (399,816 | ) | — | |||||
| Proceeds from Exercise of Stock Options and Warrants | — | 16,960 | ||||||
| Net Cash Provided by Financing Activities | 2,630,914 | 46,619,211 | ||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (9,813,473 | ) | 20,237,804 | |||||
| CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD | 13,927,267 | 11,358,520 | ||||||
| CASH AND CASH EQUIVALENTS – END OF PERIOD | $ | 4,113,794 | $ | 31,596,324 | ||||
| Supplemental Disclosure of Cash Flow Information | ||||||||
| Cash Paid During the Period for Interest | $ | 613,814 | $ | 900,000 | ||||
| Cash Paid During the Period for Income Taxes | $ | — | $ | — | ||||
| Non-Cash Financing and Investing Activities: | ||||||||
| Oil and Natural Gas Properties Property Accrual in Accounts Payable | $ | 35,288,407 | $ | 4,079,967 | ||||
| Stock-Based Compensation Capitalized to Oil and Natural Gas Properties | $ | 395,768 | $ | 134,216 | ||||
| Capitalized Asset Retirement Obligations | $ | 76,184 | $ | 50,485 | ||||
Exhibit 99.1
Contact:
Voyager Oil & Gas, Inc.
Marty Beskow
Vice President of Finance / Capital Markets
406-245-4901
marty.beskow@voyageroil.com