Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect Management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. Those statements include statements regarding the intent, belief or current expectations of us and members of its management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.
Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission. Important factors currently known to us could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that its assumptions are based upon reasonable data derived from and known about our business and operations and the business and operations of the Company. No assurances are made that actual results of operations or the results of our future activities will not differ materially from its assumptions. Factors that could cause differences include, but are not limited to, expected market demand for the Company’s services, fluctuations in pricing for materials, and competition.
We currently focus our oil and natural gas exploration, exploitation and development operations on projects located in Colorado, New Mexico and Texas. The higher potential impact projects (“Core Focus Areas”) are concentrated on (i) Spraberry, Wolfberry, Strawn and Mississippian formations in the Permian Basin in W. Texas, (ii) conventional reef structures in the Pedregosa Basin in S.W. New Mexico and (iii) conventional structure and stratigraphic formations and unconventional resource formations in Southern Colorado. In addition to the Core Focus Areas, our management team is pursuing producing conventional and unconventional properties (“Non-Core Properties”), which we anticipate will provide us with immediate cash flow and additional upside through recompletion potential and new drilling opportunities.
As of April 30, 2012, we owned interests in (i) approximately 8,900 gross (5,050 net) acres in the Midland Basin, (ii) approximately 108,715 gross (54,357 net) acres in the Pedregosa Basin and (iii) approximately 3,300 gross (1,650 net) acres in Colorado and 3,148 gross acres in Non-Core Properties. In August 2011, leases on approximately 1,240 gross acres in Colorado expired and were not renewed.
We have approximately, 117,776 (59,716 net acres) held by production. This includes approximately 4,000 gross acres (1,000 net acres) in Midland Basin, 108,715 gross acres (54,357 net acres) in the Pedregosa Basin, and approximately 5,061 gross acres (4,358 net acres) in the Non-Core Properties.
We began oil and gas operations in the United States on November 1, 2009, with the purchase of a producing conventional oil and gas field, located in the Gulf Coast region of Texas, from Pioneer Natural Resources. Additionally, we acquired interests in two properties located in the Gulf Coast region of Texas and one property in our Core Focus Area located in West Texas.
During the six months ended April 30, 2012, we (i) completed and began production from our BVR Well No. 6-1, (ii) drilled and set casing for the Livestock Well 7-1, (iii) commenced drilling operations on the Livestock Well 18-1.
The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties. Our other properties currently provide cash flow for overhead and administrative costs, while we develop our Core Focus Areas.
We continue to pursue avenues to reduce or eliminate our financial exposure on a case by case basis for each project. Joint venture arrangements may be considered for others to participate for a disproportionate share of the initial leasing and/or drilling costs, further reducing our exposure.
Projects in the next 12 months, subject to raising the capital requirements:
Subject to obtaining additional financing, the following drilling, recompletion/work-over and leasing activity may be pursued. The projects and our share of the estimated costs are listed below:
Estimated cost based on expected participating working interest.
| Project | | Current WI% | | | No. Wells | | Procedure | | Est. Cost | |
| Midland Basin | | | 62.5-85 | % | | | 6 | | New Drill | | $ | 7.0MM | |
| Pedregosa Basin | | | 50 | % | | | 1 | | New Drill | | $ | 0.0 MM | |
| Colorado | | | 50 | % | | | 1 | | New Drill | | $ | 0.9 MM | |
| Other producing properties | | | 100 | % | | | 3 | | Recompletions | | $ | 0.4 MM | |
| Other producing properties | | | 30 | % | | | 1 | | New Drill | | $ | 0.5 MM | |
| All Properties | | various | | | | | | New Leases | | $ | 1.3MM | |
| Total | | | | | | | | | | | $ | 10.10 MM | |
While our base case drilling, recompletion/workover and leasing activity would result in estimated costs of $10.1 million, we may expand drilling, recompletion/workover and leasing activity to as much as $22 million, if project economics and general economic conditions support the more aggressive drilling program. If we elect to expand drilling activities, we will need to access additional capital.
We have not entered into any commodity derivative arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.
In order to retain a strong balance sheet, we have sold equity and used joint venture agreements with other industry companies to limit or eliminate our financial exposure in early drilling.
Consolidated Results of Operations for the Three Months Ended April 30, 2012 Compared to the Three Months Ended April 30, 2011
Revenues for the three months ended April 30, 2012 totaled $602,450 as compared to $498,577 for the three months ended April 30, 2011. The increase totaling $103,873 resulted from the change in the price of oil (approximately $25,000) and the completion and production from the BVR Well No. 6-1, which began production during the first quarter of fiscal 2012 as well as from production from wells drilled and acquired in 2011.
Selling general and administrative expenses decreased $96,042 from $694,019 during the three months ended April 30, 2011 to $597,977 during the three months ended April 30, 2012. This decrease is primarily the result of a decrease of approximately $75,000 in the stock based compensation recorded as the result of the full vesting of stock option grants.
Depreciation, depletion and accretion increased by $146,715 to $286,260 during the three months ended April 30, 2012 as compared to $139,545 during the three months ended April 30, 2011. The increase was the result of the production from the BVR Well No. 6-1.
Lease operating expenses increased $120,271 from $162,302 during the three months ended April 30, 2011 to $282,573 during the three months ended April 30, 2012. The increase was primarily the result of the production from the BVR Well No. 6-1 and other wells drilled and acquired during 2011.
We incurred a net loss during the three months ended April 30, 2012 of $624,260, compared to a net loss of $2,341,627 during the three months ended April 30, 2011.
Consolidated Results of Operations for the Six Months Ended April 30, 2012 Compared to the Six Months Ended April 30, 2011
Revenues for the six months ended April 30, 2012 totaled $1,070,750 as compared to $892,763 during the six months ended April 30, 2011. The increase totaling $177,987 resulted from the completion and production from the BVR Well No. 6-1, which began production during the first quarter of fiscal 2012, and the Everett No. 3 well, which began production in May 2011. In December 2011, we saw a drop in production in one of our fields due to equipment issues caused by weather. The field resumed normal production in January 2012.
Selling general and administrative expenses decreased $293,593 from $1,330,829 during the six months ended April 30, 2011 to $1,037,236 during the six months ended April 30, 2012. This decrease is primarily the result of a decrease of approximately $225,000 in the stock based compensation as the result of the vesting of stock option grants.
Depreciation, depletion and accretion increased by $133,609 to $503,251 during the six months April 30, 2012 as compared to $369,642 during the six months ended April 30, 2011. The increase was the result of the production from the BVR Well No. 6-1 and the Everett No. 3 well.
Lease operating expenses increased $106,659 from $352,236 during the six months ended April 30, 2011 to $458,895 during the six months ended April 30, 2012. The increase was primarily the result of the operations from the BVR Well No. 6-1 and Everett 3 well.
During the six months ended April 30, 2011, we incurred exploration expenses of $106,394. These costs related primarily to the 2-D seismic work done on the Pedregosa property. There were no exploration costs during the six months ended April 30, 2012.
We incurred interest expense totaling $1,833,471 during the six months ended April 30, 2011. The interest was incurred on promissory notes totaling $1,560,000 and bridge notes totaling $1,745,300 as well as on the discount and beneficial conversion features on the bridge notes. Interest expense totaling $118,681 during the six months ended April 30, 2012, which was primarily the result of borrowings on the notes due to Silver Bullet.
We incurred a net loss during the six months ended April 30, 2012 of $1,047,295, compared to a net loss of $3,148,402 during the six months ended April 30, 2011.
Liquidity and Capital Resources
As of April 30, 2012, we had cash and cash equivalents on hand of $578,659. We believe this amount, together with production from existing wells, wells to be completed in June 2012 and the well to be drilled in June 2012, are sufficient to fund our general and administrative costs for the next twelve months. We do not have sufficient funds on hand in order to fund any capital expenditures for the drilling of new wells or the recompletion of existing wells. We expect to rely on external sources of capital in order to continue to fund our capital expenditures. We do not have any firm commitments to raise additional capital nor is there any assurance sufficient capital will be available at acceptable terms.
Net Cash Used In Operating Activities
Cash provided by operating activities for the six months ended April 30, 2012 was $523,779, compared to $1,002,382 used for the comparative period. The increase in cash provided by operating activities was from the decrease in our net loss, amortization of debt discount reduction in accounts receivable and increase in accounts payable.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the six months ended April 30, 2012 was $685,434 compared to $4,568,804 for the comparative period. The costs for both periods presented relate to our oil and gas acquisitions and development. During the six months ended April 30, 2011, the costs relate primarily to the costs associated with the drilling of the test well on the Pedregosa property, the acquisition of the Copano Bay property, the acquisition of additional leases in the AP Clark Field and costs associated with the drilling of the Everett 3 well. During the six months ended April 30, 2012, the costs relate primarily to the completion of the BVR 6-1 well.
Cash Flows from Financing Activities
Cash provided by financing activities for the period ended April 30, 2012 was $500,000, compared to $4,506,218 for the comparative period. The financing for the period ended April 30, 2012 was provided through a loan from Silver Bullet. The cash flows from investing activities for the period ended April 30, 2011 resulted from borrowings from Silver Bullet ($1.5 million), proceeds from the sale of common stock ($1,338,500) and proceeds from bridge notes ($1,719,018).
On November 19, 2010, we entered into a loan agreement with Silver Bullet Property Holdings SDN BHD (“Silver Bullet”), pursuant to which we issued a promissory note totaling $1,500,000 (the “Note”) in exchange for $1,500,000. The Note bears interest at the rate of 10% per annum and was due on the earlier of the date we closed on an offering with gross proceeds of at least $5 million or November 19, 2011. On September 27, 2011, we entered into an amendment to the Note, whereby the maturity date of the Note was amended from November 19, 2011 to February 1, 2013. In addition, Silver Bullet loaned us an additional $1 million, with $500,000 loaned prior to October 31, 2011 and the remaining $500,000 received in two installments in November and December 2011. Pursuant to a security agreement, dated September 27, 2011, as security for the repayment of the Note, we granted Silver Bullet a first priority lien on our oil and gas mineral leases in the Apclark Field. In April 2012, we entered into another amendment with Silver Bullet, whereby the maturity date of the Note was amended February 1, 2013 to May 1, 2014 and Silver Bullet agreed to lend us an additional $500,000. We also granted Silver Bullet a net proceeds interest of 9% in the AP Clark properties included in the security agreement, which would be reduced to 4.5% if the Note is repaid prior to May 1, 2013. The Company received the additional $500,000 in June 2012.
Critical Accounting Policies
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization.
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineers have policies and procedures in place consistent with these authoritative guidelines.
Proved reserve estimates are adjusted annually and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. The estimation of proved developed reserves also is important to the statement of operations because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and plug wells at the end of operations at operational sites. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Not required under Regulation S-K for “smaller reporting companies.”
Item 4. Controls and Procedures.
(a) Evaluation of disclosure controls and procedures.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this Quarterly Report on Form 10-Q. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Based on our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
(b) Changes in internal control over financial reporting.
There were no changes in our internal control over financial reporting that occurred during the quarter ended April 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
We are currently not a party to any material legal proceedings or claims.
Item 1A. Risk Factors.
Not required under Regulation S-K for “smaller reporting companies.”
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information.
On June 8, 2012, Eric Urban resigned for personal reasons, effective immediately, as a director of the Company. In submitting his resignation, Mr. Urban did not express any disagreement with the Company on any matter relating to the registrant’s operations, policies or practices.
Item 6. Exhibits.
| 31.01 | Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.02 | Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 32.01 | Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| 99.01 | Letter of Resignation from Eric Urban. |
| 101.INS | XBRL Instance Document* |
| 101.SCH | XBRL Schema Document* |
| 101.CAL | XBRL Calculation Linkbase Document* |
| 101.LAB | XBRL Label Linkbase Document* |
| 101.PRE | XBRL Presentation Linkbase Document* |
| 101.DEF | XBRL Definition Linkbase Document* |
* The XBRL related information in Exhibit 101 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability of that section and shall not be incorporated by reference into any filing or other document pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing or document.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | BLACKSANDS PETROLEUM, INC. | |
| | | | |
| Date: June 19, 2012 | By: | /s/ DAVID DEMARCO | |
| | | David DeMarco | |
| | | Chief Executive Officer | |
| | | | |
| | | | |
| Date: June 19, 2012 | By: | /s/ DONALD GIANNATTASIO | |
| | | Donald Giannattasio | |
| | | Chief Financial Officer | |
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