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, Upper Wolfcamp, Lower Wolfcamp/Cline Shale, Strawn and Mississippian formations in the Permian Basin (Midland 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. We also have interest in the Beech Creek Field located in Hardin County, Texas and the Cabeza Creek Field located in Goliad County Texas, which we anticipate will provide us with immediate cash flow and additional upside through recompletion potential and new drilling opportunities (“Non-core Properties”).
As of April 30, 2013, we owned interests in (i) approximately 8,700 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 (iv) 3,800 gross acres in Non-Core Properties.
We have approximately 116,515 gross acres (59,900 net acres) held by production and continuous drilling operations. This includes approximately 4,000 gross acres (1,843 net acres) in Midland Basin, 108,715 gross acres (54,357 net acres) in the Pedregosa Basin, and approximately 3,800 gross acres (3,722 net acres) in the Non-Core Properties. We have no production in Colorado or New Mexico.
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 Goliad County 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 the Midland Basin in West Texas.
During the fiscal year ended October 31, 2012, we (i) drilled, set casing, perforated and fracture stimulated the Livestock 7-1 well and the Livestock 18-1 well, which are currently producing, and (ii) obtained financing for the two Livestock wells, which also provides us with the opportunity to drill additional wells in the Midland Basin.
The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties. The Core Focus Area we are currently focused primarily on developing is the APClark Field in the Midland Basin. 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 and recompletion/work-over may be pursued. The projects and our share of the estimated costs are listed below:
Estimated cost based on expected participating working interest.
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Project
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Current WI%
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No. Wells
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Procedure
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Est. Cost
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Midland Basin
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62.5-85
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%
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3
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New Drill
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$
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3.7MM
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Pedregosa
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50
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%
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1
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New Drill
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$
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2.0MM
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Colorado
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50
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%
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1
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New Drill
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$
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0.9MM
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Other producing properties
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100
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%
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2
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Recompletions
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$
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0.4 MM
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Total
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7
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$
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7.0MM
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We are currently exploring financing options relating to the drilling of new wells in Pedregosa and Colorado in which we would retain a 16.67% interest in each Project and could reduce our total estimated cost from $7 million to approximately $4.1 million. If we elect to expand drilling activities, we will need to access additional capital. During the fiscal year ended October 31, 2012, we entered into a joint venture agreement which provided us with $2.6 million and provides our joint venture partner the option to provide an additional $5 million in financing for future wells. We utilized the $2.6 million in order to perforate, fracture stimulate and acquire surface facilities required to complete the two Livestock wells.
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, 2013 Compared to the Three Months Ended April 30, 2012
Revenues for the three months ended April 30, 2013 totaled $473,180 as compared to $602,450 for the three months ended April 30, 2012. The decrease totaling $129,270 resulted from the drop in production in the Cabeza Creek and Beech Creek fields. The loss in production from the Copano Bay field sold in July 2012 was offset by the production for the two Livestock wells, which began producing oil in November and December 2012.
Selling general and administrative expenses decreased $173,814 from $597,977 in the three months ended April 30, 2012 to $424,163 in the three months ended April 30, 2013. This decrease is primarily the result of a decrease of approximately $128,037 in the stock based compensation recorded in the quarter ended April 30, 2013 as the result of the vesting of previously granted stock options. There were no options granted during the quarter ended April 30, 2013. In addition, there was a decrease in legal and professional fees totaling $38,229.
Depreciation, depletion and accretion decreased $199,675 from $277,069 in the three months ended April 30, 2012 as compared to $86,585 for the three months ended April 30, 2013. The decrease is primarily a result in the lower depletion expense from the decreased production.
Lease operating expenses decreased $93,274 from $282,573 in the three months ended April 30, 2012 to $189,299 in the three months ended April 30, 2013. The costs in the three months ended April 30, 2012, included approximately $60,000 in lease operating costs for the Copano Bay wells, which were disposed of in July 2012. In addition, there were repair/workover costs totaling $25,000 relating to wells on the APClark property.
Interest expenses increased $253,574 from 59,900 in the three months ended April 30, 2012 to $313,474 in the three months ended April 30, 2013. The increase was the result of amortization of discounts totaling $603,464 relating to the joint venture agreement with KP-RAHR Ventures III LLC.
We incurred a net loss for the three months ended April 30, 2013 of $540,293, compared to a net loss of $624,260 for the three months ended April 30, 2012.
Consolidated Results of Operations for the Six Months Ended April 30, 2013 Compared to the Six Months Ended April 30, 2012
Revenues for the six months ended April 30, 2013 totaled $835,166 as compared to $1,070,750 for the six months ended April 30, 2012. The decrease totaling $235,584 resulted from the drop in production in the Cabeza Creek and Beech Creek fields. The loss in production from the Copano Bay field sold in July 2012 was offset by the production for the two Livestock wells, which began producing oil in November and December 2012.
Selling general and administrative expenses decreased $265,806 from $1,037,236 in the six months ended April 30, 2012 to $771,430 in the six months ended April 30, 2013. This decrease is primarily the result of a decrease of approximately $210,141 in the stock based compensation recorded in the six months ended April 30, 2013 as the result of the vesting of previously granted stock options. There were no options granted during the six months ended April 30, 2013.
Depreciation, depletion and accretion decreased $243,443 from $503,251 in the six months ended April 30, 2012 as compared to $259,808 for the six months ended April 30, 2013. The decrease is primarily a result in the lower depletion expense from the decreased production.
Lease operating expenses decreased $103,770 from $458,895 in the six months ended April 30, 2012 to $355,125 in the six months ended April 30, 2013. The costs in the six months ended April 30, 2012, included approximately $100,000 in lease operating costs for the Copano Bay wells, which were disposed of in July 2012. In addition, there were repair/workover costs totaling $25,000 relating to wells on the APClark property.
Interest expenses increased $476,920 from 118,663 in the six months ended April 30, 2012 to $595,583 in the six months ended April 30, 2013. The increase was the result of amortization of discounts totaling $247,602 relating to the joint venture agreement with KP-RAHR Ventures III LLC.
We incurred a net loss for the six months ended April 30, 2013 of $1,118,941, compared to a net loss of $1,047,295 for the six months ended April 30, 2012.
Liquidity and Capital Resources
As of April 30, 2013, we had cash and cash equivalents on hand of $1,075,767. We believe this amount, together with production from existing wells and additional wells to be drilled during the summer of 2013, are sufficient to fund our general and administrative costs for the next twelve months. Depending on the depth and formation drilled to and the frac program utilized, presuming our joint venture partner provides additional funds, we will have sufficient cash in order to fund capital expenditures for the drilling of between two and four new wells. However, if our joint venture partner does not provide additional funds, which it has no obligation to do so, we would need an additional $5 million for the next 12 months in order to fund our planned drilling program. We do not currently have the financing in order to carry out a more robust drilling program. We expect to rely on external sources of capital in order to continue to fund our capital expenditures.
Net Cash Used In Operating Activities
Cash used in operating activities in the six months ended April 30, 2013 was $40,639, compared to $523,779 provided by operating activities in the six months ended April 30, 2012. The decrease in cash provided by operating activities was from the increase in our net loss and reductions in accounts receivable and accounts payable.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the six months ended April 30, 2013 was $43,914 compared to $685,182 in the six months ended April 30, 2012. The costs for both periods presented relate to our oil and gas acquisitions and development.
Cash Flows from Financing Activities
Cash provided by financing activities for the six months ended April 30, 2012 was $500,000. The financing was provided through a loan from Silver Bullet. There were no such financing in the six months ended April 30, 2013.
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 exploration and production 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 April 30, 2013. 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 management’s evaluation, our chief executive officer and chief financial officer concluded that, as of April 30, 2013, our disclosure controls and procedures are not designed at a reasonable assurance level and are ineffective 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. The material weaknesses, which relate to internal control over financial reporting, that were identified are:
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a)
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Due to our small size, we did not have sufficient personnel in our accounting and financial reporting functions nor do we have a proper segregation of duties. During the quarter ended January 31, 2013, we had limited staff that performed nearly all aspects of our financial reporting process, including, but not limited to, access to the underlying accounting records and systems, the ability to post and record journal entries and responsibility for the preparation of the financial statements. This creates certain incompatible duties and a lack of review over the financial reporting process that would likely result in a failure to detect errors in spreadsheets, calculations, or assumptions used to compile the financial statements and related disclosures as filed with the Securities and Exchange Commission. In addition, we have had an overreliance on consultants involved in our financial statement closing process. As a result we were not able to achieve adequate segregation of duties and were not able to provide for adequate reviewing of the financial statements. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis; and
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b)
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We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of U.S. GAAP commensurate with our complexity and our financial accounting and reporting requirements. As a result, our financial statement closing process, which involves the preparation of the financial statements included in this annual report, did not identify all of the adjusting journal entries that were required to be recorded in connection with our closing process. As part of the audit of our most recently concluded fiscal year ended October 31, 2012, which occurred during the quarter ended January 31, 2013, our independent registered public accounting firm proposed a significant number of audit adjustments, including a material adjustment regarding the amount of depletion of our oil and gas reserves, which should have been recorded as part of the normal closing process. Our internal control over financial reporting did not detect such matters and, therefore, was not effective in detecting misstatements in the consolidated financial statements. This control deficiency is pervasive in nature. Further, there is a reasonable possibility that material misstatements of the financial statements including disclosures will not be prevented or detected on a timely basis as a result.
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Management’s Remediation Plans
We are committed to improving our financial organization. We will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum. As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel. We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements and anticipate doing so until we have a sufficient number of internal accounting personnel to achieve compliance. As necessary, we will engage consultants in the future in order to ensure proper accounting for our consolidated financial statements.
Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weakness: insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.
Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our internal accounting staff consists of a Chief Financial Officer and a bookkeeper, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.
(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, 2013 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.
None.
Item 6. Exhibits.
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31.01
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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.
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31.02
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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.
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32.01
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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.
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101.INS
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XBRL Instance Document*
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101.SCH
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XBRL Schema Document*
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101.CAL
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XBRL Calculation Linkbase Document*
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101.LAB
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XBRL Label Linkbase Document*
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101.PRE
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XBRL Presentation Linkbase Document*
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101.DEF
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XBRL Definition Linkbase Document*
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________________
* 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.
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BLACKSANDS PETROLEUM, INC.
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Date: June 13, 2013
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By:
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/s/ DAVID DEMARCO
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Name: David DeMarco
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Title: Chief Executive Officer
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Date: June 13, 2013
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By:
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/s/ DONALD GIANNATTASIO
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Name: Donald Giannattasio
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Title: Chief Financial Officer
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