UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
x | Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended June 30, 2009
o | Transition Report pursuant to 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period to
Commission File Number: 000-53260
Best Energy Services, Inc.
(Exact name of small business issuer as specified in its charter)
Nevada | 02-0789714 |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
10375 Richmond Avenue, Suite 2000, Houston TX 77042
(Address of Principal Executive Offices) (Zip Code)
(713) 933-2600
(Issuer’s Telephone Number, including Area Code)
Securities registered under Section 12(b) of the Exchange Act: None
Securities registered under Section 12(g) of the Exchange Act:
Common Stock, par value $0.001 per share
(Title of Class)
Check whether the issuer (1) 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 issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days x Yes o No
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 ¨ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
Large Accelerated filer o | Accelerated filer o |
Non-Accelerated filer o (Do not check if a smaller reporting company) | Smaller Reporting Company x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
State the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 21,010,109 common shares as of August 19, 2009.
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BEST ENERGY SERVICES, INC.
Table of Contents
Page | |
PART I. FINANCIAL INFORMATION | |
PART II. OTHER INFORMATION | |
Signatures | 25 |
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Item 1. Financial Statements
Consolidated Balance Sheets
(Unaudited)
June 30, 2009 | December 31, 2008 | |||||
Current assets | ||||||
Cash | $ | 107,600 | $ | 249,330 | ||
Accounts receivable, net of allowance for doubtful accounts of $120,518 and $106,237, respectively | 1,461,806 | 3,602,118 | ||||
Pepaid and other current assets | 71,434 | 123,053 | ||||
Total current assets | 1,640,840 | 3,974,501 | ||||
Property and equipment, net | 29,173,537 | 30,877,472 | ||||
Deferred financing costs, net | 556,500 | - | ||||
Goodwill and other intangible assets | 7,616,254 | 7,557,309 | ||||
TOTAL ASSETS | $ | 38,987,131 | $ | 42,409,282 | ||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||||
Current liabilities | ||||||
Accounts payable and accrued liabilities | $ | 488,631 | $ | 678,834 | ||
Bank overdraft | 219,172 | - | ||||
Current portion of accrued officer compensation | 185,000 | 140,000 | ||||
Preferred stock dividends payable | 1,276,268 | 765,761 | ||||
Current portion of loans payable | 1,395,778 | 21,802,193 | ||||
Total current liabilities | 3,564,849 | 23,386,788 | ||||
Accrued officer compensation, net of current portion | 350,000 | 410,000 | ||||
Loans payable, net of current portion | 19,315,525 | 134,836 | ||||
Convertible notes payable, net of discount of $405,492 and $-, respectively | 412,508 | - | ||||
Deferred income taxes | 8,431,507 | 8,708,454 | ||||
TOTAL LIABILITIES | 32,074,389 | 32,640,078 | ||||
STOCKHOLDERS’ EQUITY | ||||||
Series A Preferred Stock, 2,250,000 shares authorized, 1,458,592 shares issued and outstanding, at redemption value of $10 per share | 14,585,920 | 14,585,920 | ||||
Common stock, $0.001 par value per share; 90,000,000 shares authorized; 21,010,109 and 20,891,366 shares issued and outstanding, respectively | 21,010 | 20,891 | ||||
Additional paid-in capital | 2,823,655 | 2,452,350 | ||||
Retained deficit | (10,517,843 | ) | (7,289,957 | ) | ||
Total stockholders’ equity | 6,912,742 | 9,769,204 | ||||
$ | 38,987,131 | $ | 42,409,282 | |||
The accompanying notes are an integral part of these financial statements.
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Best Energy Services, Inc.
For the three and six months ended June 30, 2009 and July 31, 2008
(Unaudited)
Three Months Ended | Six Months ended | |||||||||||||||
June 30, 2009 | July 31, 2008 | June 30,2009 | July 31, 2008 | |||||||||||||
Revenues | ||||||||||||||||
Well service revenue | $ | 839,913 | $ | 4,628,882 | $ | 2,717,302 | $ | 8,502,681 | ||||||||
Drilling service revenue | 690,235 | 1,542,413 | 1,518,794 | 1,843,500 | ||||||||||||
Geological services revenue | 70,614 | 263,035 | 191,025 | 373,877 | ||||||||||||
Total revenue | 1,600,762 | 6,434,330 | 4,427,121 | 10,720,058 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Direct cost of revenue | 612,197 | 2,746,647 | 2,348,137 | 4,690,805 | ||||||||||||
Business unit operating expenses | 1,321,915 | 1,859,108 | 1,862,115 | 4,556,233 | ||||||||||||
Depreciation and amortization | 965,210 | 891,649 | 1,899,227 | 1,611,170 | ||||||||||||
Loss on sale on property and equipment | - | 6,793 | - | 6,793 | ||||||||||||
General and administrative expense | 564,751 | 694,479 | 1,244,057 | 1,187,188 | ||||||||||||
Total operating costs and expenses | 3,464,073 | 6,198,676 | 7,353,536 | 12,052,189 | ||||||||||||
Income (Loss) from operations | (1,863,311 | ) | 235,654 | (2,926,415 | ) | (1,332,131 | ) | |||||||||
Other income (expense): | ||||||||||||||||
Interest income | 122 | 586 | 874 | 19,697 | ||||||||||||
Interest expense | (355,519 | ) | (364,347 | ) | (579,292 | ) | (3,221,834 | ) | ||||||||
Loss before provision for income taxes | $ | (2,218,708 | ) | $ | (128,107 | ) | $ | (3,504,833 | ) | $ | (4,534,268 | ) | ||||
Income tax | - | - | - | - | ||||||||||||
Deferred income tax benefit | 138,000 | - | 276,947 | - | ||||||||||||
Net loss | $ | (2,080,708 | ) | $ | (128,107 | ) | $ | (3,227,886 | ) | $ | (4,534,268 | ) | ||||
Preferred stock dividend | (255,253 | ) | (466,858 | ) | (510,507 | ) | (466,858 | ) | ||||||||
Net loss attributable to common shareholders | (2,335,961 | ) | (594,965 | ) | (3,738,393 | ) | (5,001,126 | ) | ||||||||
Net loss per share – basic and diluted | (0.11 | ) | (0.03 | ) | (0.18 | ) | (0.27 | ) | ||||||||
Weighted average common shares outstanding – basic and diluted | 20,999,713 | 20,216,306 | 20,952,535 | 18,604,444 |
The accompanying notes are an integral part of these financial statements.
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Best Energy Services, Inc.
For the six months ended June 30, 2009 and July 31, 2008
(Unaudited)
Six months ended | ||||||||
June 30, 2009 | July 31, 2008 | |||||||
Cash flow from operating activities: | ||||||||
Net loss | $ | (3,227,886 | ) | $ | (4,534,268 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Deferred income tax benefit | (276,947 | ) | - | |||||
Depreciation and amortization | 1,899,227 | 1,611,170 | ||||||
Stock-based compensation | 462,888 | 202,106 | ||||||
Non-cash interest expense | 568,817 | 2,587,752 | ||||||
Loss on sale of property and equipment | - | 6,793 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | 2,140,312 | (392,729 | ) | |||||
Prepaid expenses and other current assets | 51,619 | (254,423 | ) | |||||
Accounts payable, accrued liabilities and other | (190,203 | ) | 254,730 | |||||
Accrued officer compensation | (15,000 | ) | 925,000 | |||||
Bank overdraft | 219,172 | - | ||||||
Net cash provided by operating activities | 1,631,999 | 406,131 | ||||||
Cash flows from investing activities: | ||||||||
Acquisition of businesses, net of cash acquired | (58,945 | ) | (31,385,943 | ) | ||||
Capital expenditures, net | (195,292 | ) | (267,662 | ) | ||||
Proceeds from disposal of property | - | 17,412 | ||||||
Net cash used in investing activities | (254,237 | (31,636,193 | ) | |||||
Cash flows from financing activities: | ||||||||
Proceeds from issuance of Term Loan | - | 5,850,000 | ||||||
Repayments of Term Loan | (585,000 | ) | (487,500 | ) | ||||
Net borrowings (repayments) under Revolving Advances | (1,023,448 | ) | 15,863,055 | |||||
Net repayments of other notes payable | (120,128 | ) | (38,109 | ) | ||||
Proceeds from issuance of Units in private placement | 818,000 | 11,848,080 | ||||||
Payments of deferred financing costs | (608,916 | ) | (921,066 | ) | ||||
Net cash (used in) provided by financing activities | (1,519,492 | ) | 32,114,460 | |||||
Net change in cash and cash equivalents | (141,730 | ) | 884,398 | |||||
Cash and cash equivalents, beginning of period | 249,330 | 5 | ||||||
Cash and cash equivalents, end of period | $ | 107,600 | $ | 884,403 | ||||
Supplemental disclosures of cash flow information: | ||||||||
Cash paid for interest | $ | 6,321 | $ | 616,704 | ||||
Cash paid for income taxes | $ | - | $ | 150,000 | ||||
Noncash investing and financing activities: | ||||||||
Units issued in exchange for collateral agreements | $ | - | $ | 2,500,000 | ||||
Retirement of common shares | - | 6,080 | ||||||
Shares issued for purchase of BWS and DSS and ARH Assets | - | 2,421,500 | ||||||
Stock options exercised | 76 | - | ||||||
Preferred stock issued in payment of preferred stock dividends | - | 126,520 | ||||||
Accrued dividends on preferred stock | 510,507 | 340,338 | ||||||
Warrants issued for debt modification | 15,885 | - | ||||||
Warrants issued for deferred financing costs | 28,616 | - | ||||||
Discount on convertible notes payable | 408,666 | - | ||||||
The accompanying notes are an integral part of these financial statements.
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Best Energy Services, Inc.
Note 1 - Basis of Presentation
The accompanying unaudited interim consolidated financial statements have been prepared pursuant to accounting principles generally accepted in the United States of America and the rules and regulations of the Securities and Exchange Commission and should be read in conjunction with the audited financial statements and notes thereto contained in Best Energy’s Annual Report filed with the SEC on Form 10-K. 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 financial statements which substantially duplicate the disclosure contained in the audited financial statements for fiscal 2008 as reported in the Form 10-K have been omitted. These consolidated financial statements include the accounts of Best Energy and its wholly-owned subsidiaries Best Well Service, Inc. (“BWS”) and Bob Beeman Drilling, Inc. (“BBD”). All significant inter-company balances and transactions have been eliminated.
Change in year end
In February 2008, Best Energy acquired two companies and certain assets from three other companies, all of which are engaged in well servicing, drilling and related complementary services for the oil and gas, water and minerals industries. Concurrent with these acquisitions we abandoned our prior business plan and changed our name to Best Energy Services, Inc. In addition, as a result of these acquisitions, our Board of Directors elected to change our fiscal year-end to December 31, effective December 31, 2008, to match the calendar year-ends of the acquired companies.
Prior to the acquisitions, our fiscal year end was January 31. As a result of the acquisitions, on February 14, 2008, our board of directors elected to change our year end to December 31 effective in the fourth calendar quarter of 2008, to match the year end of the acquired companies. Accordingly, we filed an annual report on Form 10-K for the year ended January 31, 2008 and subsequently filed quarterly reports in 2008 on Form 10-Q for the quarters ended April 30, July 31, and October 31. In addition, we filed a Transition Report on Form 10-K for the eleven months ended December 31, 2008. We have determined that revising our prior year interim financial statements to conform to the current year quarterly presentation would be unduly cumbersome and costly. Consequently, this report includes statements of operations and cash flow for the three and six month periods ended June 30, 2009 and July 31, 2008. We believe that these periods are generally comparable other than the seasonal effects of drilling operations. Our operations in Utah are subject to Bureau of Land Management restrictions on land usage for drilling activity during the winter months. In addition, weather conditions in Kansas in the first four months of the year are generally unpredictable due to potentially heavy snow falls and tornadoes.
Note 2-Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation.
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Cash and Cash Equivalents
We consider all highly liquid investments with maturities from date of purchase of three months or less to be cash equivalents. Cash and cash equivalents consist of cash on deposit with domestic banks and, at times, may exceed federally insured limits. As of June 30, 2009, we had no cash balances in excess of federally insured limits.
Credit Risk
We are subject to credit risk relative to our trade receivables. However, credit risk with respect to trade receivables is minimized due to the nature of our customer base.
Goodwill
Goodwill represents the excess of purchase price and related costs over the value assigned to the net tangible assets of businesses acquired. These business acquisitions include BWS, BBD, BB Drilling and DSS in February 2008. We evaluate goodwill for impairment utilizing undiscounted projected cash flows in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” As of June 30, 2009, we believe that no such impairment has occurred. Goodwill has been adjusted for purchase price adjustments recognized during the current fiscal year.
Income Taxes
We recognize deferred tax assets and liabilities for the future tax consequences attributed to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If it is more likely than not that some portion of a deferred tax asset will not be realized, a valuation allowance is recognized.
Segment Reporting
SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for reporting information about operating segments on a basis consistent with the Company’s internal organization structure as well as information about geographical areas, business segments and major customers in financial statements. In January 2009, the Company combined division Mud Logging and Rig Housing as Geological Service Division. The Company continues to have business operations in the drilling and well services segments. Accordingly, the Company operates in three business segments.
Recently Issued Accounting Standards and Developments.
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. In accordance with SFAS 165, an entity should apply the requirements to interim or annual financial periods ending after June 15, 2009. We adopted SFAS 165 effective June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements. The date through which subsequent events have been evaluated is August 19, 2009, the date on which the financial statements were issued. See Note 9, Subsequent Events, for further discussion.
In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”). The FASB Accounting Standards Codification TM, (“Codification”) will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will adopt the requirements of SFAS 168 in the third quarter of fiscal year 2009.
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Note 3 – Loans payable
On April 15, 2009, we entered into an amendment to our existing credit agreement with PNC Bank N.A. (“Amended Credit Agreement”). The Amended Credit Agreement provides for a term loan and a revolving credit portion. Under the terms of the Amended Credit Agreement, the term loan portion increased from approximately $5.0 million to $19.2 million, as a result of a portion of the revolving portion of the debt being transferred to the term loan portion. The maturity date of the term loan was changed to March 31, 2011. The term loan requires monthly principal payments beginning May 1, 2009 and on the first day of each month thereafter as follows:
· | From May 1, 2009 to December 31, 2009 - $98,500; |
· | From January 1, 2010 to December 31, 2010 - $125,000; and |
· | $150,000 thereafter until March 31, 2011. |
The term loan bears interest at a rate equal to an alternate base rate (which is generally the greater of the federal funds open rate plus ½%, PNC’s base commercial lending rate and the daily LIBOR rate) plus 2.5% or the greater of the Eurodollar Rate or 2% plus 3.75%, as those terms are defined in the Amended Credit Agreement. The term loan also requires an annual 25% recapture of Excess Cash Flow applied to the principal balance. Excess Cash Flow is defined as EBIDTA less cash tax payments, non-financed capital expenditures and payments of principal on the term loan and interest on indebtedness for borrowed money.
The revolving credit portion of the debt, $1,427,880 on June 30, 2009, may be borrowed and re-borrowed until maturity on March 31, 2011 and bears interest at the same rate as the term loan. The amount available is the lesser of $4.0 million and an amount equal to 85% of eligible receivables plus 100% of the balance in the cash collateral account plus the undrawn amount of letters of credit minus such reserves as PNC deems appropriate. At June 30 2009, there was no additional availability under the Credit Agreement.
Borrowings under the Amended Credit Agreement are secured by all of our assets and equipment and by all of the assets and equipment of BWS and BBD, and the assets acquired from BB Drilling, DSS, and ARH. Any equipment and assets purchased in the future will, once acquired, also be subject to the security interest in favor of PNC Bank, N.A.
Under our Amended Credit Agreement, we are subject to customary covenants, including certain financial covenants and reporting requirements. Beginning on March 31, 2010, we are required to maintain a fixed charge coverage ratio, (defined as the ratio of EBITDA minus capital expenditures (except capital expenditures financed by lenders other than under the Amended Credit Agreement) made during such period minus cash taxes paid during such period minus all dividends and distributions paid during such period (including, without limitation, all payments to the holders of the Series A Preferred Stock), to all senior debt payments as follows:
Fiscal Quarter Ending: | Fixed Coverage Ratio: |
March 31, 2010 | 1.05 to 1.0 |
June 30, 2010 | 1.10 to 1.0 |
September 30, 2010 | 1.15 to 1.0 |
December 31, 2010 | 1.20 to 1.0 |
March 31, 2011 | 1.25 to 1.0 |
We also are required to maintain a minimum EBITDA as follows:
Fiscal Quarter Ending: | Minimum EBITDA: |
Three months ended March 31, 2009 | $ 216,000 |
Six months ended June 30, 2009 | 902,000 |
Nine months ended September 30, 2009 | 1,744,000 |
Twelve months ended December 31, 2009 | 2,385,000 |
We did not meet the EBITDA requirement for the six months ended June 30, 2009. We received a waiver from PNC for the EBITDA covenant default existing as of June 30, 2009 and an amended loan agreement dated August 19, 2009 for the minimum EBITDA covenant going forward.
Under the terms of our Amended Credit Agreement, we may not pay cash dividends on our common stock or our preferred stock or redeem any shares of our common stock or preferred stock.
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Our amended credit agreement has set forth minimum rig utilization requirements for the three-month period then ending for Best Well Service of not less than the percentage set forth in the table below:
Fiscal Quarter Ending | Minimum Rig Utilization |
March 31, 2009 | 25% |
June 30, 2009 | 30% |
September 30,2009 | 34% |
December 31, 2009 | 34% |
March 31, 2010 | 48% |
June 30, 2010 | 54% |
September 30, 2010 | 58% |
December 31, 2010 | 58% |
March 31, 2011 | 58% |
Our Rig Utilization rate was 27% for the three months ended June 30, 2009.
In addition to the foregoing and other customary covenants, our Amended Credit Agreement contains a number of covenants that, among other things, will restrict our ability to:
· | incur or guarantee additional indebtedness; |
· | transfer or sell assets; |
· | create liens on assets; |
· | engage in transactions with affiliates other than on an “arm’s-length” basis; and |
· | make any change in the principal nature of our business. |
Our Amended Credit Agreement also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy, a change of control and material judgments and liabilities.
In connection with refinancing the credit facility, we incurred cash costs associated with the transaction of $303,071. In addition we were required to pay PNC a loan modification fee of $125,000 and to issue PNC warrants to purchase 250,000 shares of common stock at a strike price of $0.50 for a period of 5 years. The warrants were valued using the Black-Scholes option pricing model at $15,885. The above costs have been capitalized as deferred financing costs and will be amortized over the life of the Amended Credit Agreement using the straight line method which approximates the interest method. A portion of the loan modification fee in the amount of $33,333 remains unpaid as of June 30, 2009.
The following table presents the assumptions used in the Black-Scholes option pricing model for the warrants granted in connection with the loan modification. Our expected volatility is based on the historical volatility of comparable companies for a period approximating the expected life, due to the limited trading history of our common stock. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on the fact that we do not anticipate paying any dividends on common stock in the near term.
Expected life (years) 5.00
Risk-free interest rate 2.34%
Volatility 120.00%
Dividend yield 0.00%
Future minimum payments under all notes payable and convertible notes payable are as follows:
For the twelve months ending June 30, | Amount | |
2010 | $ 1,395,778 | |
2011 | 20,120,948 | |
2012 | 12,577 |
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Note 4 – Convertible notes payable
During June 2009, we had several preliminary closings of a private placement for a total of 818 Units and received gross proceeds of $818,000 (net proceeds of $711,660 after cash commission of $106,340). Each Unit consists of a subordinated convertible note payable of $1,000 and warrants to purchase 4,000 shares of common stock at an exercise price of $0.25 at any time until expiration on July 1, 2014. The notes bear interest at a rate of 10% per annum, which is payable either in cash semi-annually in arrears on July 1 and January 2 each year, commencing on January 2, 2010 or in shares of common stock at a price of $0.25 per share. Under the terms of our credit facility, we may not pay cash interest on the notes. The notes are convertible at the option of the note holder into common stock at the rate of $0.25 (the “Conversion Price”) per share and mature on July 1, 2011. If we achieve certain earnings hurdles, we may force the noteholders to convert all or part of the then outstanding notes at the Conversion Price. The notes are unsecured obligations and are subordinate in right of payment to all of our existing and future senior indebtedness.
We evaluated the terms of the notes in accordance with SFAS No. 133. “Accounting for Derivative Instruments and Hedging Activities,” and EITF Issue 00-19,. “Accounting for Derivative Financial Instruments Indexed to and Potentially Settled in a Company’s Own Stock”. Best Energy determined that the conversion feature did not meet the definition of a liability and therefore did not bifurcate the conversion feature and account for it as a separate derivative liability. We evaluated the conversion feature under EITF 98-5 and EITF 00-27 for a beneficial conversion feature. The effective conversion price was compared to the market price on the date of the notes and was deemed to be less than the market value of our common stock at the inception of the note. A beneficial conversion feature was recognized and gave rise to a debt discount of $408,666.
In connection with the private placement, we issued warrants to the placement agent to purchase 327,200 shares of common stock at an exercise price of $0.25 at any time until expiration on July 1, 2014. These warrants were valued at $42,083.
On August 11, 2009, we completed the final closing of the private placement offering. During the period between July 1, 2009 and the final closing, we sold an additional 270 Units and received additional gross proceeds of $270,000.
Note 5 - Stock Options
Stock Options
Incentive and non-qualified stock options issued to directors, officers, employees and consultants are issued at an exercise price equal to or greater than the fair market value of the stock at the date of grant. The stock options vest over a period from zero to one year, and expire five years from the date of grant. Upon exercise of stock options, new shares of common stock are issued. Compensation cost related to stock options is recognized on a straight-line basis over the vesting or service period and is net of expected forfeitures.
The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the assumptions used in the option pricing model for options granted during the six months ended June 30, 2009. The expected life of the options represents the period of time the options are expected to be outstanding. The expected term of options granted was derived based on a weighting between the average midpoint between vesting and the contractual term. Our expected volatility is based on the historical volatility of comparable companies for a period approximating the expected life, due to the limited trading history of our common stock. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on the fact that we do not anticipate paying any dividends on common stock in the near term.
Expected life (years) | 2.50 | years |
Risk-free interest rate | 0.93 – 1.35 | % |
Volatility | 120.00 - 169.30 | % |
Dividend yield | 0.00 | % |
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A summary of our stock option activity and related information is presented below:
Weighted | ||||||||
Average | ||||||||
Number of | Exercise Price | |||||||
Options | Per Option | |||||||
Options outstanding at December 31, 2008 | 2,845,000 | $ | 0.30 | |||||
Granted | 1,570,000 | 0.25 | ||||||
Exercised | (150,000 | ) | 0.50 | |||||
Forfeited | - | - | ||||||
Options outstanding at June 30, 2009 | 4,265,000 | $ | 0.28 | |||||
Options vested and exercisable at June 30, 2008 | 4,265,000 | $ | 0.28 |
During the six months ended June 30, 2009, 1,570,000 options were granted with a weighted average grant date fair value of $0.22. During the six months ended June 30, 2009, 150,000 options were exercised in a cashless exercise which resulted in 75,743 shares being issued. No options were forfeited or expired. As of June 30, 2009, there was no unrecognized compensation cost related to non-vested stock options. We recognized $462,888 of stock-based compensation expense during the six months ended June 30, 2009. As of June 30, 2009, the weighted-average remaining life of the outstanding stock options is 4.40 years.
The aggregate intrinsic value of stock options outstanding at December 31, 2008 was $40,500. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of our common stock as of June 30, 2009 exceeds the exercise price of the option.
Note 6 - Stockholders’ Equity
Dividends
As of June 30, 2009 there was $1,276,268 of accrued and unpaid dividends on the Series A Preferred Stock.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to redeem the Series A Preferred Stock (to the extent permissible under the Amended Credit Agreement) and to fund our working capital needs and growth opportunities. Any future dividends on common stock will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Nevada and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends in kind, on our preferred stock.
Common stock
During the six months ended June 30, 2009, 75,743 shares of common stock were issued as a result of a cashless exercise of options to purchase 150,000 shares of common stock.
During the six months ended June 30, 2009, 43,000 shares of common stock were issued to employees as compensation.
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Note 7 - Related Party Transactions
On February 14, 2008, we leased certain real property from Mr. Tony Bruce, our director, Chief Operating Officer and President, for a period of three years for $3,500 per month in base rent.
On February 22, 2008, we leased real property necessary to run our rig housing operations from Mr. Larry Hargrave, our former CEO and a former director of the Company, for a period of three years for $6,000 per month in base rent.
In January 2009, as part of a settlement agreement for his termination in October, 2008 from the position of CEO of our Company, we entered into a consultancy agreement with Larry Hargrave, the Company’s former Chief Executive Officer, covering the period January 15, 2009 to June 15, 2009 at $10,000 per month.
Note 8 – Segment information
Our operations have been organized and aligned within the following three reportable segments:
· | Well Services (Best Well Service, Inc.); |
· | Drilling Services (Bob Beeman Drilling Company); |
· | Geological Services |
Our operations are both product and services based, and the reportable operating segments presented below include our well services operations, drilling services operations, mud logging and construction of portable rig housing for rig sites.
Our reportable segment information is as follows as of and for the three months ended June 30, 2009:
Segments | ||||||||||||||||
Well Service | Drilling Services | Geological Services | Segments Total | |||||||||||||
Revenue | $ | 839,913 | $ | 690,235 | $ | 70,614 | $ | 1,600,762 | ||||||||
Gross profit | $ | (239,132) | $ | (11,121 | ) | $ | (83,097 | ) | $ | (333,350 | ) |
Our reportable segment information is as follows as of and for the three months ended July 31, 2008:
Segments | ||||||||||||||||
Well Service | Drilling Services | Geological Services | Segments Total | |||||||||||||
Revenue | $ | 4,628,882 | $ | 1,542,413 | $ | 263,035 | $ | 6,434,330 | ||||||||
Gross profit | $ | 1,303,893 | $ | 469,569 | $ | 55,113 | $ | 1,828,575 |
Our reportable segment information is as follows as of and for the six months ended June 30, 2009:
Segments | ||||||||||||||||
Well Service | Drilling Services | Geological Services | Segments Total | |||||||||||||
Revenue | $ | 2,717,302 | $ | 1,518,794 | $ | 191,025 | $ | 4,427,121 | ||||||||
Gross profit (loss) | $ | 310,796 | $ | 355,062 | $ | (448,989 | ) | $ | 216,869 |
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Our reportable segment information is as follows as of and for the six months ended July 31, 2008:
Segments | ||||||||||||||||
Well Service | Drilling Services | Geological Services | Segments Total | |||||||||||||
Revenue | $ | 8,502,681 | $ | 1,843,500 | $ | 373,877 | $ | 10,720,058 | ||||||||
Gross profit | $ | 2,112,732 | $ | (388,805 | ) | $ | (250,907 | ) | $ | 1,473,020 |
The following table reconciles gross profit from reportable segments to our consolidated income from continuing operations before income taxes for the three months ended June 30 2009 and July 31, 2008:
Three months ended | ||||||||
June 30, 2009 | July 31, 2008 | |||||||
Gross profit from reportable segments | $ | (333,350 | ) | $ | 1,828,575 | |||
Depreciation | (965,210 | ) | (891,649 | ) | ||||
Loss on sale of property and equipment | - | (6,793 | ) | |||||
General and administrative expenses | (564,751 | ) | (694,479 | ) | ||||
Loss from operations | (1,863,311 | ) | 235,654 | |||||
Other expense, net | (355,397 | ) | (363,761 | ) | ||||
Net loss from continuing operations before income taxes | $ | (2,218,708 | $ | (128,107 |
The following table reconciles gross profit from reportable segments to our consolidated income from continuing operations before income taxes for the six months ended June 30 2009 and July 31, 2008:
Six months ended | ||||||||
June 30, 2009 | July 31, 2008 | |||||||
Gross profit from reportable segments | $ | 216,869 | $ | 1,473,020 | ||||
DeDep Depreciation | (1,899,227 | ) | (1,611,170 | ) | ||||
Loss Loss on sale of property and equipment | - | (6,793 | ) | |||||
Genera General and administrative expenses | (1,244,057 | ) | (1,187,188 | ) | ||||
Loss from operations | (2,926,415 | ) | (1,332,131 | ) | ||||
Other e Other expense, net | (578,418 | ) | (3,202,137 | ) | ||||
Net los Net loss from continuing operations before income taxes | $ | (3,504,833 | ) | $ | (4,534,268 | ) |
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Assets by reportable segment as of June 30, 2009 and December 31, 2008 are as follows:
Segments | ||||||||||||||||
Well Service | Drilling Services | Geological Services | Segments Total | |||||||||||||
June 30, 2009 | $ | 19,417,076 | $ | 8,883,722 | $ | 2,616,259 | $ | 30,917,057 | ||||||||
December 31, 2008 | 20,778,824 | 9,423,511 | 2,613,967 | 32,816,302 |
The following table reconciles assets from reportable segments to our consolidated assets as of June30, 2009 and December 31, 2008:
June 30, 2009 | December 31, 2008 | |||||||
Assets from reportable segments | $ | 30,917,057 | $ | 32,816,302 | ||||
Goodwill | 7,616,254 | 7,557,309 | ||||||
Other corporate assets | 453,820 | 2,035,671 | ||||||
Total consolidated assets | $ | 38,987,131 | $ | 42,409,282 |
Subsequent events through August 19, 2009 are as follows:
In 2008, Acer Capital Group sued Best Energy, American Rig Housing, and Larry Hargrave for breach of contract and fraud. Best Energy bought assets from Larry Hargrave in 2008 which were previously a part of American Rig Housing. The contract claims arise from an agreement entered into between American Rig Housing and Acer Capital (the "Acer Agreement") concerning a going public transaction and certain alleged agreements concerning bridge financing for the going public transaction between American Rig Housing and Pipeline Capital (the "Pipeline Agreements), which subsequently assigned those alleged contracts to Acer Capital. Under the Acer Agreement, Acer was to assist with taking American Rig Housing public in return for certain equity considerations in the new company. The agreement also purports to contemplate a fee (the "Break-up Fee") to be paid to Acer in the event the going public transaction was not consummated. Acer claims it is owed this fee. The defendants in the case dispute that Acer performed its obligations under the agreement and that the Break-up Fee is owed. Acer subsequently amended its petition to add Andrew Garrett, Inc. and Mark Harrington as defendants and to assert new claims for tortuous interference with contract and prospective business relations and conspiracy.
All parties to the lawsuit captioned Acer Capital Group, Inc. and Acer Capital Group, LLC, v. Best Energy Services, Inc. et al., pending in the 61st Judicial District Court of Harris County, Texas, went to court-ordered mediation in Houston on July 22, 2009. All legal claims brought in the suit were settled at the July 22 mediation where the parties signed a valid and enforceable mediation agreement containing all key provisions of the negotiated settlement. Final settlement documents are pending. Pursuant to the terms of the mediation agreement, the Company is not required to make any payments in connection with the settlement and will receive a full release by Acer of any claims that Acer had, now has, or may have in the future against the Company based on or related to the subject matter of the lawsuit.
In addition, pursuant to the terms of the mediation agreement, ARH, Inc. and Larry Hargrave are required to pay a total of $275,000 in cash over a three-year term, 1,125,000 shares of Company common stock, 300,000 options to purchase Company stock at 16 cents per share over a five-year term, and 300,000 options to purchase Company stock at 50 cents per share over a five-year term.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling and well service industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, the availability, terms and deployment of capital, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors elsewhere in this report, including under the headings “Disclosure Regarding Forward-Looking Statements” below, in this Item 2. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no duty to update or revise any forward-looking statements. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.
Company Overview
We are an energy production equipment and services company engaged in well service, drilling services and related complementary activities. We own a total of 25 workover rigs and nine operating drilling rigs, and we conduct our well service and drilling services primarily in the Rocky Mountain and Mid-Continent regions of the United States. We also provide housing accommodations to the oil and gas drilling industry principally in Texas and geological mud-logging services to our existing business segments.
We were incorporated on October 31, 2006 as Hybrook Resources Corp. under the laws of the state of Nevada. From inception through our year ended January 31, 2008, Hybrook was a development stage company with an option to purchase an 85% interest in a mineral claim in British Columbia. Hybrook did not exercise its option and no minerals were discovered. As a result of the acquisitions discussed below, all mineral exploration activities were discontinued.
In February 2008, Best Energy acquired two companies and certain assets from three other companies, all of which are engaged in well servicing, drilling and related complementary services for the oil and gas, water and minerals industries. Concurrent with these acquisitions, we abandoned our prior business plan and changed our name to Best Energy Services, Inc. In addition, as a result of these acquisitions, our Board of Directors elected to change our fiscal year-end to December 31, effective December 31, 2008, to match the calendar year-ends of the acquired companies.
The following discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes as of June 30, 2009 and for the three months ended June 30, 2009 and July 31, 2008, included elsewhere herein, and the audited consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the transition period ended December 31, 2008.
In early 2009, we relocated our principal executive offices to 10375 Richmond Ave., Suite 2000, Houston, Texas 77042.
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Business Plan
The implementation of our new business plan began with our three acquisitions that now offer us a footprint in:
· | The Well Service sector |
· | The Drilling Services sector |
· | The Geological Services sector |
As a result of these acquisitions, we operate in one industry segment, oilfield services, which includes well service, drilling services, housing accommodations and geological mud-logging sectors.
In the Well Service Division, our acquisition of Best Well Service, Inc., or BWS, brought us a strong footprint in the hydrocarbon rich Hugoton basin. BWS operates 25 well service rigs in the Mid-Continent region of the United States. BWS has distinguished itself over the years in its service to both major oil companies and large independents, as well as an employee retention history that we believe is among the best in the industry. BWS also has complete in-house safety certifications and we rank extremely high within our peer group.
In the Drilling Services Division, our acquisition of BBD, and the assets of its affiliates established us in three separate markets in the Rocky Mountain region:
· | mining and mineral drilling, including potash, precious metals and uranium; |
· | water well drilling with licenses to operate in five states; and |
· | oil and gas contract drilling in conventional and unconventional target areas. |
The acquisition of BBD brought us a surplus of underutilized equipment which we believe can be selectively liquidated.
In the Geologic Services Division, our activities are in two areas: housing accommodations and mud-logging. Our acquisition of certain assets of a housing accommodations company established our presence in the fabrication and/or rental of crew quarters for the drilling sector. Our operations in this division are located near our corporate headquarters in Houston, Texas.
For mud-logging, we have hired an experienced manager, Cody Hembree, to oversee this new division. Mr. Hembree brought several off-the-shelf technologies and merged them as one to create a versatile and robust mud-logging system with capabilities beyond the industry standard. The mud-logging division may from time to time refurbish some of the existing well site trailers to use as on-site mud-logging laboratories.
Significant Developments
New Management
In connection with our acquisition of all the issued and outstanding stock of BWS from its sole shareholder, Tony Bruce, we entered into a one year employment agreement with Mr. Bruce under which he agreed to serve as a Vice President of our Central Division. Since then, Mr. Bruce has joined our board of directors and on October 13, 2008 agreed to serve as our President and Chief Operating Officer. On February 17, 2009, we entered into a new one-year employment agreement with Mr. Bruce.
On October 20, 2008, Mark Harrington was named our interim Chief Executive Officer. On December 19, 2008, Mr. Harrington was appointed as our permanent Chief Executive Officer.
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Credit Facility
On April 15, 2009, we entered into an amendment to our existing credit agreement with PNC Bank N.A. (“Amended Credit Agreement”). The Amended Credit Agreement provides for a term loan and a revolving credit portion. Under the terms of the Amended Credit Agreement, the term loan portion increased from approximately $5.0 million to $19.2 million, as a result of a portion of the revolving portion of the debt being transferred to the term loan portion. The maturity date of the term loan was changed to March 31, 2011. The term loan requires monthly principal payments beginning May 1, 2009 and on the first day of each month thereafter as follows:
· | From May 1, 2009 to December 31, 2009 - $98,500; |
· | From January 1, 2010 to December 31, 2010 - $125,000; and |
· | $150,000 thereafter until March 31, 2011. |
The term loan bears interest at a rate equal to an alternate base rate (which is generally the greater of the federal funds open rate plus ½%, PNC’s base commercial lending rate and the daily LIBOR rate) plus 2.5% or the greater of the Eurodollar Rate or 2% plus 3.75%, as those terms are defined in the Amended Credit Agreement. The term loan also requires an annual 25% recapture of Excess Cash Flow applied to the principal balance. Excess Cash Flow is defined as EBIDTA less cash tax payments, non-financed capital expenditures and payments of principal on the term loan and interest on indebtedness for borrowed money.
The revolving credit portion of the debt, $928,000 on April 15, 2009, may be borrowed and re-borrowed until maturity on March 31, 2011 and bears interest at the same rate as the term loan. The amount available is the lesser of $4.0 million and an amount equal to 85% of eligible receivables plus 100% of the balance in the cash collateral account plus the undrawn amount of letters of credit minus such reserves as PNC deems appropriate.
Borrowings under the Credit Agreement are secured by all of our assets and equipment and by all of the assets and equipment of BWS and BBD, and the assets acquired from BB Drilling, DSS, and ARH. Any equipment and assets purchased in the future will, once acquired, also be subject to the security interest in favor of PNC Bank, N.A.
Under our Amended Credit Agreement, we are subject to customary covenants, including certain financial covenants and reporting requirements. Beginning on March 31, 2010, we are required to maintain a fixed charge coverage ratio, (defined as the ratio of EBITDA minus capital expenditures (except capital expenditures financed by lenders other than under the Amended Credit Agreement) made during such period minus cash taxes paid during such period minus all dividends and distributions paid during such period (including, without limitation, all payments to the holders of the Series A Preferred Stock), to all senior debt payments as follows:
Fiscal Quarter Ending: | Fixed Coverage Ratio: |
March 31, 2010 | 1.05 to 1.0 |
June 30, 2010 | 1.10 to 1.0 |
September 30, 2010 | 1.15 to 1.0 |
December 31, 2010 | 1.20 to 1.0 |
March 31, 2011 | 1.25 to 1.0 |
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We also are required to maintain a minimum EBITDA as follows:
Fiscal Quarter Ending: | Minimum EBITDA: |
Three months ended March 31, 2009 | $ 216,000 |
Six months ended June 30, 2009 | 902,000 |
Nine months ended September 30, 2009 | 1,744,000 |
Twelve months ended December 31, 2009 | 2,385,000 |
We did not meet the EBITDA requirement for the six months ended June 30, 2009. We received a waiver from PNC for the existing minimum EBITDA default and a loan amendment for the minimum EBITDA covenant going forward.
Under the terms of our Amended Credit Agreement, we may not pay cash dividends on our common stock or our preferred stock or redeem any shares of our common stock or preferred stock.
Our amended credit agreement has set forth minimum rig utilization requirements for the three-month period then ending for Best Well Service of not less than the percentage set forth in the table below:
Fiscal Quarter Ending | Minimum Rig Utilization |
March 31, 2009 | 25% |
June 30, 2009 | 30% |
September 30,2009 | 34% |
December 31, 2009 | 34% |
March 31, 2010 | 48% |
June 30, 2010 | 54% |
September 30, 2010 | 58% |
December 31, 2010 | 58% |
March 31, 2011 | 58% |
Our Rig Utilization rate was 27% for quarter ended June 30, 2009.
In addition to the foregoing and other customary covenants, our Amended Credit Agreement contains a number of covenants that, among other things, will restrict our ability to:
· | incur or guarantee additional indebtedness; |
· | transfer or sell assets; |
· | create liens on assets; |
· | engage in transactions with affiliates other than on an “arm’s-length” basis; and |
· | make any change in the principal nature of our business. |
Our Amended Credit Agreement also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy, a change of control and material judgments and liabilities.
The amounts owed under the credit facility had been classified as current in the December 31, 2008 balance sheet. As a result of the loan modification subsequent to the end of the period, these amounts have been reclassified to long term debt based on management’s intent and ability to refinance these amounts into long-term debt.
In connection with refinancing the credit facility, we incurred cash costs associated with the transaction of $428,071 and issued warrants to purchase common stock with a value of $15,885. These costs have been capitalized as deferred financing costs and will be amortized over the life of the Amended Credit Agreement using the interest method.
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Market Conditions in Our Industry
The United States oil field services industry is highly cyclical. Volatility in oil and natural gas prices can produce wide swings in the levels of overall drilling activity in the markets we now serve and affect the demand for our drilling services and the day rates we can charge for our rigs. This volatility also affects the demand for other oil field services we provide, such as portable rig housing and mud logging. The availability of financing sources, past trends in oil and natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells oil and natural gas exploration and production companies decide to drill.
Results of Operations
Three months Ended June 30, 2009 compared with the Three Months Ended July 31, 2008
Revenues were $1.6 million for the three months ended June 30, 2009 compared with revenue of $6.4 million for the three months ended July 31, 2008. The decrease of $4.8 million was primarily the result of a severe downturn in drilling activity caused by low oil and gas prices, as well as unseasonably inclement weather that severely impacted our primary service region in April and May of this year.
Operating Expenses were $3.5 million for the three months ended June 30, 2009 compared with $6.2 million for the three months ended July 31, 2008 resulting in a decrease of $2.7 million. This decrease was primarily a result of decreases in business unit operating expenses consequent to a severe decline in our revenues, coupled with an ongoing cost-cutting program that was first implemented by management in late 2008.
Net loss from operations was $1.9 million for the three months ended June 30, 2009 compared with net income of $0.2 million for the three months ended July 31, 2008 resulting in an increased loss of $2.1 million.
General and administrative expenses for the three month period ended June 30, 2009 were $0.6 million compared with expense of $0.7 million for the three month period ended July 31, 2008. Management has made a concerted effort in 2009 to reduce cash corporate overhead through downsizing office space, reduction in corporate staff and other overhead expenses.
Interest expense was $0.4 million for both the three month period ended June 30, 2009 and the three month period ended July 31, 2008.
Net Loss was $2.1 million or $0.11 per common share after accrued preferred dividends for the three months ended June 30, 2009 compared with a net loss of $0.1 million or $0.03 per common share for the three months ended July 31, 2008 resulting in an increased loss of $2.0 million. The increase in net loss for the period was a result of significant declines in our gross revenues during 2009 offset by decreased operating, general and administrative expenses.
Six months Ended June 30, 2009 compared with the Six Months Ended July 31, 2008
Revenues were $4.4 million for the six months ended June 30, 2009 compared with revenue of $10.7 million for the six months ended July 31, 2008. The decrease of $6.3 million was primarily the result of a significant downturn in drilling activity caused by low oil and gas prices, as well as unseasonably inclement weather that severely impacted our primary service region in April and May of this year.
Operating Expenses were $7.4 million for the six months ended June 30, 2009 compared with $12.1 million for the six months ended July 31, 2008 resulting in a decrease of $4.7 million. This decrease was primarily a result of the decline in business unit operating revenues and associated direct variable costs.
Net loss from operations was $2.9 million for the six months ended June 30, 2009 compared with a net loss of $1.3 million for the six months ended July 31, 2008 resulting in an increased loss of $1.6 million.
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General and administrative expenses were $1.2 million for both the six months ended June 30, 2009 and the six months ended July 31, 2008. Included in those periods is stock-based compensation of $0.5 million and $0.2 million for the periods ended June 30, 2009 and July 31, 2008, respectively.
Interest expense decreased by $2.6 million for the six month period ended June 30, 2009, compared with the six month period ended July 31, 2008. This decrease is primarily due to deferred financing costs during the six months ended July 31, 2008.
Net Loss was $3.2 million or $0.18 per common share after accrued preferred dividends for the six months ended June 30, 2009 compared with a net loss of $4.5 million $0.27 per share for the six months ended July 31, 2008 resulting in an decreased loss of $1.3 million. The improvement in the net loss was primarily caused by the amortization of deferred financing costs in 2008 of $2.6 million and the decrease in operating costs of $4.7 million.
Liquidity and Capital Resources
Historical Cash Flows
The following table summarizes our cash flows for the six months ended June 30, 2009 and July 31, 2008:
Six months ended | ||||||
June 30, 2009 | July 31, 2008 | |||||
Net cash provided by operating activities | $ | 1,631,999 | $ | 406,131 | ||
Net cash used in investing activities: | ||||||
Capital expenditures, net | (195,292) | (267,662) | ||||
Proceeds from sale of property and equipment | - | 17,412 | ||||
Acquisitions , net of cash acquired | (58,945) | (31,385,943) | ||||
Cash provided by (used in) financing activities: | ||||||
Proceeds from issuance of term loan | - | 5,850,000 | ||||
Repayments of term loan | (585,000) | (487,500) | ||||
Net borrowings (repayments) under revolving loan | (1,023,448) | 15,863,055 | ||||
Net repayments of other notes payable | (120,128) | (38,109) | ||||
Proceeds from issuance of Units in private placement | 818,000 | 11,848,080 | ||||
Payment of deferred financing costs | (608,916) | (921,066) | ||||
Net increase (decrease) in cash and cash equivalents | $ | (141,730) | $ | 884,398 |
Operating activities during the six months ended June 30, 2009 provided us $1.6 million of cash compared to providing $0.4 million in the six months ended July 31, 2008. Contributing to the improved cash flow from operations was a decrease in accounts receivable of $2.1 million for the six months ended June 30, 2009 compared with an increase in accounts receivable of $0.4 million for the six months ended July 31, 2008.
Investing activities used $0.3 million for the six months ended June 30, 2009 compared to $31.6 million for the six months ended July 31, 2008. Expenditures for the six months ended July 31, 2008 were primarily for the acquisitions of businesses described above.
Financing activities used cash of $1.5 million for the six months ended June 30, 2009 compared to providing cash of $32.1 million for the six months ended July 31, 2008. Uses of cash during the six months ended June 30, 2009 were primarily related to the repayment of debt. Sources of cash during the six months ended July 31, 2008 included cash received for the term and revolving portions of the credit facility and proceeds received from the private placement of Units.
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Working capital deficit
At June 30, 2009, our current liabilities of $3.6 million exceeded our current assets of $1.6 million resulting in a working capital deficit of $2.0 million. This compares to a working capital deficit of $19.4 million at December 31, 2008. The improvement in the working capital deficit is primarily the result of decrease in current liabilities due to the reclassification of the majority of our loans payable to noncurrent as a result of the Amended Credit Facility. Current liabilities at June 30, 2009, include primarily preferred stock dividends payable of $1.3 million, current portion of loans payable of $1.4 million and accounts payable of $0.5 million. Preferred stock dividends are not expected to be paid in cash. They will be paid in-kind through the issuance of additional shares of preferred stock.
Sources of Liquidity
Our sources of liquidity include our current cash and cash equivalents, availability under the revolving portion of our Amended Credit Agreement, and internally generated cash flows from operations. We continue to explore other sources of financing that are available to us including possible sales of stock or issuance of subordinated debt.
We had no availability under the Amended Credit Agreement as of June 30, 2009.
Off-Balance Sheet Arrangements
As of June 30, 2009, we had no transactions, agreements or other contractual arrangements with unconsolidated entities or financial partnerships, often referred to as special purpose entities, which generally are established for the purpose of facilitating off-balance sheet arrangements.
Contractual Obligations
Tabular Disclosure of Contractual Obligations
Over the Next | ||||||||
Five Years | 12 Months | |||||||
Notes Payable | $ | 21,529,303 | $ | 1,395,778 | ||||
Operating Leases | 315,500 | 201,000 | ||||||
Employment/Consultant Contracts | 230,000 | 230,000 | ||||||
Total | $ | 22,074,803 | $ | 1,826,778 |
Subject to the limitations set forth in the Amended Credit Agreement, our Series A Preferred Stock must be redeemed using not less than 25% of our net income after tax each year. For the six months ended June 30, 2009, we did not have positive net income after tax and did not redeem any outstanding shares of Series A Preferred Stock.
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Disclosure Regarding Forward-Looking Statements
We caution that this document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in or incorporated by reference into this Form 10-Q which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” “plans” and similar expressions, or the negative thereof, are also intended to identify forward-looking statements. In particular, statements, expressed or implied, concerning future operating results, the ability to increase utilization or redeploy rigs, or the ability to generate income or cash flows are by nature, forward-looking statements. These statements are based on certain assumptions and analyses made by management in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, forward-looking statements are not guarantees of performance and no assurance can be given that these expectations will be achieved.
Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, but are not limited to any of the following: the timing and extent of changes in commodity prices for crude oil, natural gas and related products, interest rates, inflation, the availability of goods and services, operational risks, availability of capital resources, legislative or regulatory changes, political developments, and acts of war and terrorism. A more detailed discussion on risks relating to the oilfield services industry and to us is included in our Annual Report on Form 10-K for the eleven months ended December 31, 2008.
In light of these risks, uncertainties and assumptions, we caution the reader that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control, which could cause actual events or results to differ materially from those expressed or implied by the statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements. We undertake no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
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Not required for smaller reporting companies.
(a) Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of June 30, 2009 (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. In particular, we found control weaknesses in segregation of duties in the field and home offices. As recently acquired operations are assimilated, we intend to address these weaknesses by centrally locating payables, check writing, and implementing controls regarding segregation of duties related to cash management. We plan to have these controls in place by year end. In the interim, management has been reviewing all disbursements and cash account activity.
Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.
(b) Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting during the quarter ended June 30, 2009.
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We are from time to time subject to litigation arising in the normal course of business. As of the date of this quarterly report on Form 10-Q, there are no pending or threatened proceedings which are currently anticipated to have a material adverse effect on our business, financial condition or results of operations.
In 2008, Acer Capital Group sued Best Energy, American Rig Housing, and Larry Hargrave for breach of contract and fraud. The contract claims arise from an agreement entered into between American Rig Housing and Acer Capital (the "Acer Agreement") concerning a going public transaction and certain alleged agreements concerning bridge financing for the going public transaction between American Rig Housing and Pipeline Capital (the "Pipeline Agreements), which subsequently assigned those alleged contracts to Acer Capital. Under the Acer Agreement, Acer was to assist with taking American Rig Housing public in return for certain equity considerations in the new company. The agreement also purports to contemplate a fee (the "Break-up Fee") to be paid to Acer in the event the going public transaction was not consummated. Acer claims it is owed this fee. The defendants in the case dispute that Acer performed its obligations under the agreement and that the Break-up Fee is owed.
All parties to the lawsuit captioned Acer Capital Group, Inc. and Acer Capital Group, LLC, v. Best Energy Services, Inc. et al., pending in the 61st Judicial District Court of Harris County, Texas, went to court-ordered mediation in Houston on July 22, 2009. All legal claims brought in the suit were settled at the July 22 mediation where the parties signed a valid and enforceable mediation agreement containing all key provisions of the negotiated settlement. Final settlement documents are pending. Pursuant to the terms of the mediation agreement, the Company is not required to make any payments in connection with the settlement and will receive a full release by Acer of any claims that Acer had, now has, or may have in the future against the Company based on or related to the subject matter of the lawsuit.
In addition, pursuant to the terms of the mediation agreement, ARH, Inc. and Larry Hargrave are required to pay a total of $275,000 in cash over a three-year term, 1,125,000 shares of Company common stock, 300,000 options to purchase Company stock at 16 cents per share over a five-year term, and 300,000 options to purchase Company stock at 50 cents per share over a five-year term.
Not required for smaller reporting companies.
During June 2009, we had several preliminary closings of a private placement for a total of 818 Units and received gross proceeds of $818,000 (net proceeds of $711,660 after cash commission of $106,340). Each Unit consists of a subordinated convertible note payable of $1,000 and warrants to purchase 4,000 shares of common stock at an exercise price of $0.25 at any time until expiration on July 1, 2014. The notes bear interest at a rate of 10% per annum, which is payable either in cash semi-annually in arrears on July 1 and January 2 each year, commencing on January 2, 2010 or in shares of common stock at a price of $0.25 per share. Under the terms of our credit facility, we may not pay cash interest on the notes. The notes are convertible at the option of the note holder into common stock at the rate of $0.25 (the “Conversion Price”) per share and mature on July 1, 2011. If we achieve certain earnings hurdles, we may force the noteholders to convert all or part of the then outstanding notes at the Conversion Price. The notes are unsecured obligations and are subordinate in right of payment to all of our existing and future senior indebtedness.
We evaluated the terms of the notes in accordance with SFAS No. 133. “Accounting for Derivative Instruments and Hedging Activities,” and EITF Issue 00-19,. “Accounting for Derivative Financial Instruments Indexed to and Potentially Settled in a Company’s Own Stock”. Best Energy determined that the conversion feature did not meet the definition of a liability and therefore did not bifurcate the conversion feature and account for it as a separate derivative liability. We evaluated the conversion feature under EITF 98-5 and EITF 00-27 for a beneficial conversion feature. The effective conversion price was compared to the market price on the date of the notes and was deemed to be less than the market value of our common stock at the inception of the note. A beneficial conversion feature was recognized and gave rise to a debt discount of $408,666.
In connection with the private placement, we issued warrants to the placement agent to purchase 327,200 shares of common stock at an exercise price of $0.25 at any time until expiration on July 1, 2014. These warrants were valued at $42,083.
On August 11, 2009, we completed the final closing of the private placement offering. During the period between July 1, 2009 and the final closing, we sold an additional 270 Units and received additional gross proceeds of $270,000.
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None.
None.
None.
31.1 | Certification of Chief Executive Officer and Principal Accounting Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. (Filed herewith) |
32.1 | Certification of Chief Executive Officer and Principal Accounting Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith) |
[Missing Graphic Reference]
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.
Date August 19, 2009 | BEST ENERGY SERVICES, INC. |
/s/ Mark Harrington | |
Mark Harrington | |
Chief Executive Officer and Principal Accounting Officer |
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