Attached files

file filename
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R16.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R1.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R15.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R7.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R12.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R13.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R2.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R5.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R14.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R3.htm
EXCEL - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.Financial_Report.xls
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R9.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R11.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R8.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R6.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R18.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R10.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R4.htm
XML - IDEA: XBRL DOCUMENT - BLACKSANDS PETROLEUM, INC.R17.htm
EX-32.01 - CERTIFICATION - BLACKSANDS PETROLEUM, INC.bspe_ex3201.htm
EX-31.02 - CERTIFICATION - BLACKSANDS PETROLEUM, INC.bspe_ex3102.htm
EX-31.01 - CERTIFICATION - BLACKSANDS PETROLEUM, INC.bspe_ex3101.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended July 31, 2013

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from _________ to _________

Commission file number: 000-51427

BLACKSANDS PETROLEUM, INC.
(Exact name of registrant as specified in its charter)

Nevada
 
20-1740044
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)

800 Bering, Suite 250
Houston, Texas 77057
(Address of principal executive offices) (zip code)

(713) 554-4490
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x   No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
 Large accelerated filer
o
 Accelerated filer
o
 Non-accelerated filer
o
 Smaller reporting company
x
(Do not check if a smaller reporting company)
     
                                                                                    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x.

As of September 19, 2013, there were 16,392,692 shares of registrant’s common stock outstanding.
 


 
 

BLACKSANDS PETROLEUM, INC.
FORM 10-Q
For the Quarter Ended July 31, 2013

Table of Contents

PART I  FINANCIAL INFORMATION
 
Page
 
         
Item 1.
Financial Statements
     
 
Consolidated Balance Sheets as of July 31, 2013 and October 31, 2012 (unaudited)
   
3
 
 
Consolidated Statements of Operations for the nine and three months ended July 31, 2013 and 2012 (unaudited)
   
4
 
 
Consolidated Statements of Cash Flows for the nine months ended July 31, 2013 and 2012 (unaudited)
   
5
 
 
Condensed Notes to Consolidated Financial Statements (unaudited)
   
6
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
   
8
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
   
12
 
Item 4.
Controls and Procedures
   
12
 
           
PART II  OTHER INFORMATION
       
         
Item 1.
Legal Proceedings
   
15
 
Item 1A.
Risk Factors
   
15
 
Item 2.
Unregistered Sales of Securities and Use of Proceeds
   
15
 
Item 3.
Defaults Upon Senior Securities
   
15
 
Item 4.
Mine Safety Disclosures
   
15
 
Item 5.
Other Information
   
15
 
Item 6.
Exhibits
   
15
 
SIGNATURES
   
16
 

 
2

 
 

Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)
 
   
July 31,
2013
   
October 31,
2012
 
ASSETS
Current Assets:
           
Cash and cash equivalents
 
$
625,455
   
$
1,160,320
 
Accounts receivable
   
240,977
     
402,162
 
Total Current Assets
   
866,432
     
1,562,482
 
Oil and gas property costs (successful efforts method of accounting)
               
Proved
   
5,300,536
     
5,284,597
 
Unproved
   
1,934,595
     
1,934,595
 
Other assets
   
  50,577
     
220,984
 
TOTAL ASSETS
 
$
8,152,140
   
$
9,002,658
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
               
Note payable
 
$
60,000
   
$
60,000
 
Accounts payable
   
233,808
   
 
158,131
 
Accrued expenses
   
2,656,741
     
2,416,857
 
Total Current Liabilities
   
2,950,549
     
2,634,988
 
Notes payable
   
4,024,898
     
3,591,866
 
Asset retirement obligation
   
640,789
     
609,502
 
     Total Liabilities
   
7,616,236
     
6,836,356
 
Stockholders’ Equity:
               
Preferred stock - $0.01 par value; 10,000,000 shares authorized:
   
--
     
--
 
Series A - $.001 par value, 310,000 shares authorized, 250,000 and nil shares issued and outstanding, respectively
   
250
     
250
 
Common stock - $0.001 par value; 100,000,000 shares authorized; 16,392,693 and 16,386,443 shares issued and outstanding at July 31, 2013 and October 31, 2012, respectively
   
16,393
     
16,387
 
Additional paid-in capital
   
22,700,021
     
22,463,501
 
Accumulated deficit
   
(22,180,760
)
   
(20,313,836
)
Total Stockholders’ Equity
   
535,904
     
2,166,302
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
 
$
8,152,140
   
$
9,002,658
 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
 
 
3

 
 
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
 
   
Nine Months Ended July 31,
   
Three Months Ended July 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Revenue:
                       
Oil and gas revenue
  $ 1,303,045     $ 1,321,934     $ 467,879     $ 251,184  
                                 
Expenses:
                               
Selling, general and administrative
    1,107,685       1,502,101       336,255       464,865  
Depreciation and depletion
    375,257       641,280       138,211       162,235  
Accretion expense
    31,287       36,323       8,525       12,117  
Lease operating expenses
    507,585       652,378       152,460       193,483  
Oil and gas exploration costs
    220,000       --       220,000       --  
                                 
Total expenses
    2,241,814       2,832,082       855,451       832,700  
                                 
Loss from operations
    (938,769 )     (1,510,148 )     (387,572 )     (581,516 )
                                 
Other income and (expense):
                               
Interest expense
    (955,918 )     (213,599 )     (360,411 )     (94,936 )
Other income
    27,763       --       --       --  
                                 
Total other income (expense)
    (928,155 )     (213,599 )     (360,411 )     (94,936 )
                                 
Loss before provision for income taxes
    (1,866,924 )     (1,723,747 )     (747,983 )     (676,452 )
Provision for income taxes
    --       --       --       --  
Net loss
    (1,866,924 )     (1,723,747 )     (747,983 )     (676,452 )
Preferred stock dividends
    150,000       150,000       50,000       50,000  
Net loss attributable to common shareholders
  $ (2,016,924 )   $ (1,873,747 )   $ (797,983 )   $ (726,452 )
                                 
Loss per share attributable to common shareholders
                               
Basic and diluted
  $ (0.12 )   $ (0.11 )   $ (0.04 )   $ (0.04 )
                                 
Weighted Average Shares Outstanding
                               
Basic  and diluted
    16,388,648       16,381,333       16,389,738       16,383,318  
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
 
 
4

 

Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
For the Nine Months Ended July 31, 2013 and 2012
(Unaudited)

   
 
 
   
2013
   
2012
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net loss
 
$
(1,866,924
)
 
$
(1,723,747
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
               
Equity compensation expense
   
236,526
     
529,816
 
Amortization of debt discount
   
433,032
     
21,656
 
Depreciation, depletion and accretion
   
406,544
     
677,603
 
Changes in operating assets and liabilities:
               
Accounts receivable
   
161,185
     
479,432
 
Prepaid expense and other current assets
   
169,611
     
(26,748
Accounts payable
   
315,562
     
871,749
 
Net cash flows provided by (used in) operating activities
   
(144,464
)
   
829,761
 
                 
CASH FLOWS FROM INVESTING ACTIVITIES
               
Acquisition of fixed assets
   
--
     
(3,252
)
Oil and gas property costs
   
(390,401
)
   
(1,774,715
)
Net cash flows (used in) investing activities
   
(390,401
)
   
(1,777,967
)
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Proceeds from joint venture agreement
   
--
     
2,600,000
 
Proceeds from notes payable
   
--
     
1,000,000
 
Net cash flows provided by financing activities
   
--
     
3,600,000
 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
   
(534,865
)
   
2,651,794
 
CASH AND CASH EQUIVALENTS - Beginning of period
   
1,160,320
     
240,314
 
CASH AND CASH EQUIVALENTS - End of period
 
$
625,455
   
$
2,892,108
 
 
Supplemental Disclosures:
           
             
Cash paid for interest
  $ 167,240     $ --  
                 
Cash paid for income taxes
  $ --     $ --  
                 
Supplemental non-cash activities
               
                 
Discount on notes payable
  $ --     $ 2,079,017  
 
The accompanying notes are an integral part of these unaudited consolidated financial statements
 
 
5

 
 
BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

1.  The Company and Summary of Significant Accounting Policies

Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004.  Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. The Company sells its oil and gas products primarily to domestic pipelines and refineries.  Its operations are presently focused in the States of Texas and New Mexico.

The accompanying unaudited interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in annual report on Form 10-K for the year ended October 31, 2012 filed with the SEC on February 13, 2013. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited financial statements as reported in the 2012 annual report on Form 10-K have been omitted.

2.  Asset Retirement Obligation

The following table summarizes the change in the asset retirement obligation (“ARO”) for the nine months ended July 31, 2013

   Beginning balance at November 1, 2012
 
$
609,502
 
   Liabilities settled
   
--
 
   Liabilities incurred through acquisition of assets
   
--
 
Accretion expense
   
31,287
 
Ending balance at July 31, 2013
 
$
640,789
 
 
The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
 
3.  Stockholders’ Equity

Stock Options

A summary of the Company’s stock option activity and related information is as follows:
 
   
Number of
Shares
   
Weighted Average Exercise Price
 
Outstanding at November 1, 2012
   
1,046,333
   
$
3.13
 
Granted
   
--
      --  
Exercised
   
--
     
--
 
Cancelled
   
--
     
--
 
Outstanding at July 31, 2013
   
1,046,333
   
$
3.13
 
Exercisable at July 31, 2013
   
963,667
   
$
3.03
 
 
 
6

 

During the nine months ended July 31, 2013 and 2012, the Company recorded stock-based compensation of $236,526 and $529,816, respectively, as general and administrative expenses.  At July 31, 2013, the weighted average remaining life of the stock options is 6.43 years.  The unamortized amount of stock-based compensation at July 31, 2013 was $101,562. This cost is expected to be recognized over a weighted average period of 0.70 years.

4.  Reclassification

During the quarter ended January 31, 2013, the Company discovered and corrected an error regarding its reporting for certain unvested option costs for a former employee.  The error resulted in an overstatement of its net losses and overstatement of its additional paid in capital during the year ended October 31, 2012 by $145,482. For the periods presented in the Form 10-Q, the correction only impacted the additional paid in capital and retained earnings for the balance sheet ended October 31, 2012.  In accordance with the SEC’s staff Accounting Bulletin Nos. 99 and 108 (SAB 99 and SAB 108), the Company evaluated this error and, based on an analysis of quantitative and qualitative factors determined that the error was immaterial to the prior reporting period affected. Therefore, as permitted by SAB 108, the Company corrected, in the current filing, previously reported results at October 31, 2012.

5.  Contingencies

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of July 31, 2013, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

6.  Silver Bullet Property Holdings

On November 19, 2010, the Company entered into a loan agreement with Silver Bullet Property Holdings SDN BHD for a promissory note totaling $1,500,000 (the “Note”).  The Note bears interest at the rate of 10% per annum and was due on the earlier of the date the Company closes on an offering with gross proceeds of at least $5 million or November 19, 2011.  On September 27, 2011, the Company and the Investor entered into an amendment to the Note (the “Amendment”).  Pursuant to the Amendment, the maturity date of the Note was amended from November 19, 2011 to February 1, 2013.  In addition, the Investor loaned the Company an additional $1 million and the Note was amended to include such additional loan.  Pursuant to a security agreement, dated September 27, 2011 (the “Security Agreement”), as security for the repayment of the Note, the Company granted the Investor a first priority lien on the Company’s oil and gas mineral leases in the ApClark Field.  In April 2012, the parties agreed to further extend the maturity date of the Note to May 1, 2014 and the Investor agreed to an additional loan of $500,000 to the Company, and the Note was amended to include such additional loan.  The Company also granted the Investor a net proceeds interest (9% but reduced to 4.5% if the Note is repaid prior to May 1, 2013) in the AP Clark properties included in the Security Agreement.  The net proceeds interest represents the amount remaining from the proceeds of the sale of the AP Clark properties after deducting the related costs.  In September 2013, the maturity date on the Note was further extended to November 1, 2014.  The amendments were reviewed to determine its accounting treatment as a restructuring, extinguishment or modification and determined to be a modification.

On August 29, 2013, the Company entered into an additional loan agreement with the Investor for a promissory note totaling $220,000 (the “Second Note”).  The Second Note bears interest at the rate of 12% and is due on August 29, 2014.
 
 
7

 

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.

Overview

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 could provide us with cash flow and additional upside through recompletion potential and new drilling opportunities (“Non-core Properties”).

As of July 31, 2013, we owned interests in approximately (i) 8,700 gross (5,450 net) acres in the Midland Basin, (ii) 108,715 gross (54,357 net) acres in the Pedregosa Basin, (iii) 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.
 
 
8

 
 
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.
 
Project
 
Current WI%
   
No. Wells
 
Procedure
 
Est. Cost
 
Midland Basin
   
62.5-85
%
   
3
 
New Drill
 
$
3.7MM
 
Other producing properties
   
100
%
   
2
 
Recompletions
 
$
0.4 MM
 
Total
           
5
     
$
4.1MM
 
 
We are currently exploring financing options relating to the drilling of new wells in Pedregosa and Colorado, whereby we would retain a 16.67% interest in each Project, thereby reducing our total estimated cost to approximately $4.1 million.  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 July 31, 2013 Compared to the Three Months Ended July 31, 2012
 
Revenues for the three months ended July 31, 2013 totaled $467,879 as compared to $251,184 for the three months ended July 31, 2012.  The increase totaling $216,695 resulted from the production for the two Livestock wells, which began producing oil in November and December 2012 as partially offset by the loss in production from the Copano Bay field which were sold in July 2012.

Selling general and administrative expenses decreased $128,610 from $464,865 in the three months ended July 31, 2012 to $336,255 in the three months ended July 31, 2013.  This decrease is primarily the result of a decrease in the stock based compensation recorded in the quarter ended July 31, 2013 as the result of the vesting of previously granted stock options.  These options were originally granted during 2010 and 2012.  At July 31, 2013, there was $86,461 of unvested options remaining.  We expect the amount of stock based compensation expenses to continue to decrease over the next 12 months.  There were no new options granted during the quarter ended July 31, 2013.

Depreciation, depletion and accretion decreased $27,616 from $174,352 in the three months ended July 31, 2012 to $146,736 for the three months ended July 31, 2013.  The decrease is primarily a result in the lower depletion expense related to the disposal of the Copano Bay field in July 2012.

Lease operating expenses decreased $41,023 from $193,483 in the three months ended July 31, 2012 to $152,460 in the three months ended July 31, 2013.  The lease operating costs in the three months ended July 31, 2012 included $55,628 for the Copano Bay wells, which were disposed of in July 2012.
 
We incurred oil and gas exploration costs totaling $220,000 relating to delay rental payments during the three months ended July 31, 2013. There were no oil and gas exploration costs during the three months ended July 31, 2012.
 
Interest expenses increased $265,475 from 94,936 in the three months ended July 31, 2012 to $360,411 in the three months ended July 31, 2013.  The increase was the result of amortization of discounts and interest due relating to the joint venture agreement with KP-RAHR Ventures III LLC.
 
 
9

 

We incurred a net loss for the three months ended July 31, 2013 of $747,983, compared to a net loss of $676,452 for the three months ended July 31, 2012.
 
 Consolidated Results of Operations for the Nine Months Ended July 31, 2013 Compared to the Nine Months Ended July 31, 2012
 
Revenues for the nine months ended July 31, 2013 totaled $1,303,045 as compared to $1,321,934 for the nine months ended July 31, 2012.  The decrease totaling $18,889 resulted from the loss in production from the Copano Bay field sold in July 2012 partially offset by the production for the two Livestock wells, which began producing oil in November and December 2012.

Selling general and administrative expenses decreased $394,416 from $1,502,101 in the nine months ended July 31, 2012 to $1,107,685 in the nine months ended July 31, 2013.  This decrease is primarily the result of a decrease of professional fees and services along with a decrease of $293,290 in the stock based compensation recorded in the nine months ended July 31, 2013, which resulted from the vesting of previously granted stock options.  These options were originally granted during 2010 and 2012.  At July 31, 2013, there was $86,461 of unvested options remaining.  We expect the amount of stock based compensation expenses to continue to decrease over the next 12 months.  There were no new options granted during the nine months ended July 31, 2013.

Depreciation, depletion and accretion decreased $271,059 from $677,603 in the nine months ended July 31, 2012 to $406,544 for the nine months ended July 31, 2013.  The decrease is primarily a result in the lower depletion expense from the decreased production and the disposal of the Copano Bay field in July 2012.

Lease operating expenses decreased $144,793 from $652,378 in the nine months ended July 31, 2012 to $507,585 in the nine months ended July 31, 2013.  The lease operating costs in the nine months ended July 31, 2012 included approximately $166,000 for the Copano Bay wells, which were disposed of in July 2012.
 
We incurred oil and gas exploration costs totaling $220,000 relating to delay rental payments during the nine months ended July 31, 2013. There were no oil and gas exploration costs during the nine months ended July 31, 2012.
 
Interest expenses increased $742,319 from $213,599 in the nine months ended July 31, 2012 to $955,918 in the nine months ended July 31, 2013.  The increase was the result of the amortization and interest due relating to the joint venture agreement with KP-RAHR Ventures III LLC.

We incurred a net loss for the nine months ended July 31, 2013 of $1,866,924, compared to a net loss of $1,723,747 for the nine months ended July 31, 2012.
 
Liquidity and Capital Resources
 
As of July 31, 2013, we had cash and cash equivalents on hand of $625,455. We believe this amount, together with production from existing wells and additional wells to be drilled during the fall 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 $4.1 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 drilling program.  We expect to rely on external sources of capital in order to continue to fund our capital expenditures. 
  
Net Cash Flows from Operating Activities

Cash used in operating activities in the nine months ended July 31, 2013 was $144,464, compared to $829,761 provided by operating activities in the nine months ended July 31, 2012.  The sources of cash from operating activities in the nine months ended July 31, 2013 total approximately $1,722,000, comprised of approximately $1,076,000 of net noncash charges, a $161,000 increase in accounts receivable, a $170,000 increase in prepaid expense and other current assets and a $316,000 increase in accounts payable. The use of cash from operating activities was comprised of a net loss of approximately $1,867,000.
 
 
10

 
 
Cash Flows from Investing Activities
 
Net cash used in investing activities for the nine months ended July 31, 2013 was $390,401 compared to $1,777,967 in the nine months ended July 31, 2012.   The costs for both periods presented relate to our oil and gas acquisitions and development.  During the nine months ended July 31, 2012, a substantial portion of the oil and gas expenses related to the drilling costs for the two livestock wells.    
 
Cash Flows from Financing Activities
 
Cash provided by financing activities for the nine months ended July 31, 2012 was $3,600,000.   The financing was provided through a loan from Silver Bullet and as a result of the joint venture agreement with KP Rahr.  There were no financing activities in the nine months ended July 31, 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.

Exploratory Costs

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.
 
 
11

 

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.
 
Proved Reserves

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 July 31, 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.
 
 
12

 
 
Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of July 31, 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: 
 
a)
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 July 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
   
b)
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. Similar adjustments have been proposed during each of the subsequent quarters in the current fiscal year by our independent registered public accounting firm relating to depletion amounts. 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.
 
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.
 
 
13

 
 
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 July 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
 
14

 
 
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
 
During the quarter ended July 31, 2013, 3,126 shares of a restricted stock award granted to Richard Hunter vested and were deemed issued.

Item 3. Defaults Upon Senior Securities
 
None.
 
Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information.
 
None.
 
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.
     
101.INS **
 
XBRL Instance Document
     
101.SCH **
 
XBRL Taxonomy Extension Schema Document
     
101.CAL **
 
XBRL Taxonomy Extension Calculation Linkbase Document
     
101.DEF **
 
XBRL Taxonomy Extension Definition Linkbase Document
     
101.LAB **
 
XBRL Taxonomy Extension Label Linkbase Document
     
101.PRE **
 
XBRL Taxonomy Extension Presentation Linkbase Document

** XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
 
 
15

 
 
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: September 20, 2013
By:
/s/ DAVID DEMARCO
   
Name: David DeMarco
   
Title: Chief Executive Officer
     
Date: September 20, 2013
By:
/s/ DONALD GIANNATTASIO
   
Name: Donald Giannattasio
   
Title: Chief Financial Officer

 
16