UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 3
| x | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended March 31, 2007
or
| o | | 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: 000-51425
RANCHER ENERGY CORP.
(Exact name of registrant as specified in its charter)
| Nevada | | 98-0422451 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification Number) |
999-18th Street, Suite 3400 Denver, Colorado 80202 |
| (Address of principal executive offices, including zip code) |
| (303) 629-1125 |
| (Telephone number, including area code) |
Securities registered pursuant to Section 12(b) of the Act: None.
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock, par value $0.00001 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No x
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 £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £
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 and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer x | Non-accelerated filer o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter ended September 30, 2006 was $83,142,808.
The number of shares outstanding of the registrant’s common stock as of June 28, 2007 was 105,528,852.
DOCUMENTS INCORPORATED BY REFERENCE
Not Applicable.
EXPLANATORY NOTE
This Amendment No. 3 on Form 10-K/A (this “Amendment”) amends our Annual Report on Form 10-K for the fiscal year ended March 31, 2007, originally filed on June 29, 2007 (the “Original Annual Report”). This Amendment does not amend our Amendment No. 1 on Form 10-K/A for the fiscal year ended March 31, 2007 that was originally filed on July 27, 2007 to include the information required by Part III, and our Amendment No. 2 on Form 10-K/A for the fiscal year ended March 31, 2007 that was originally filed on September 7, 2007 to address matters that were raised by the Securities and Exchange Commission in their letter of August 17, 2007.
We are filing this Amendment to address matters that were raised by the Securities and Exchange Commission in its comment letter of September 26, 2007 as follows:
Item 6 – Selected Financial Data has been revised to provide the correct Pre-Predecessor revenues, production taxes, lease operating expenses and excess of revenues over expenses; and
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations has been revised to provide a more detailed explanation of the variations in revenues, production taxes and lease operating expenses for the year ended March 31, 2007 compared to the year ended March 31, 2006, and the year ended March 31, 2006 compared to the year ended March 31, 2005. In addition, disclosures have been revised to address trends in the types of bridge financing reasonably likely to be available to fund planned operations, including capital expenditures for pipeline and field development, and the nature, terms and other features of such potential financing.
In addition, in connection with the filing of this Amendment, and pursuant to Rule 12b-15 and 13a-14 under the Exchange Act, we are including with this Amendment currently dated certifications. As a result of the departure of Daniel P. Foley as our Chief Financial Officer, John Works, our Chief Executive Officer, has been appointed our interim Chief Financial Officer and thus has executed such certificates. Except as described above, no other changes have been made to the Original Annual Report, as amended. The Original Annual Report, as amended, continues to speak as of the date of the Original Annual Report, and we have not updated the disclosures contained therein to reflect any events which occurred at a date subsequent to the filing of the Original Annual Report. The Original Annual Report also included a Cautionary Statement concerning forward-looking statements, which is also applicable to this Amendment.
TABLE OF CONTENTS
| | | PAGE NO. |
| PART II | 1 |
| | |
| Item 6. | Selected Financial Data. | 1 |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. | 3 |
| | | |
| PART IV | 22 |
| | |
| Item 15. | Exhibits, Financial Statement Schedules. | 22 |
As used in this document, references to “Rancher Energy”, “our company”, “the Company”, “we”, “us”, and “our” refer to Rancher Energy Corp. and its wholly-owned subsidiary. In this Amendment, the “Cole Creek South Field” also is referred to as the “South Cole Creek Field”.
PART II
ITEM 6. SELECTED FINANCIAL DATA.
In addition to the GAAP presentation of Rancher Energy Corp.’s historical results for the years ended March 31, 2007, 2006, 2005, and 2004, we have provided the following results for its Predecessor (the Cole Creek South Field and the South Glenrock B Field) and its Predecessor’s Predecessor (Pre-Predecessor) because we believe such financial information may be useful in gaining an understanding of the impact of the acquisitions on Rancher Energy Corp.’s underlying historical performance and future financial results. The information is not presented on a GAAP basis and is not necessarily comparable between periods.
The following selected financial data reflects the following:
| · | Rancher Energy Corp. revenues, production taxes, lease operating expenses, loss from continuing operations, and loss from continuing operations per share for the years ended March 31, 2007, 2006, 2005, and 2004; |
| · | Rancher Energy Corp. total assets as of March 31, 2007, 2006, 2005, and 2004; |
| · | Predecessor revenues, production taxes, lease operating expenses, and income (loss) from continuing operations for the period from January 1, 2006 through December 21, 2006 (the date of acquisition of the Predecessor by Rancher Energy Corp.), the year ended December 31, 2005, and for the period from September 1, 2004 (the date that the Predecessor was acquired from the Pre-Predecessor) through December 31, 2004; |
| · | Predecessor total assets as of December 21, 2006 and December 31, 2005; and |
| · | Our Pre-Predecessor’s revenues, production taxes, lease operating expenses, and excess of revenues over expenses for the period from January 1, 2004 through August 31, 2004. |
| | | Year Ended March 31, | |
| | | 2007 | | 2006 | | 2005 | | 2004 | |
| | | (1)(2) | | | | | | | |
Rancher Energy Corp.: | | | | | | | | | | | | | |
| Revenues | | $ | 1,161,819 | | $ | - | | $ | - | | $ | - | |
| Production taxes | | | 136,305 | | | - | | | - | | | - | |
| Lease operating expenses | | | 700,623 | | | - | | | - | | | - | |
| Loss from continuing operations | | | (8,702,255 | ) | | (124,453 | ) | | (27,154 | ) | | (375,000 | ) |
| Loss from continuing operations per share | | | (0.16 | ) | | (0.00 | ) | | (0.00 | ) | | (0.01 | ) |
| Weighted average shares outstanding | | | 53,782,291 | | | 32,819,623 | | | 70,000,000 | | | 70,000,000 | |
| | | | | | | | | | | | | | |
| Total assets (as of period end) | | | 81,478,031 | | | 46,557 | | | 4,749 | | | - | |
| | | | | | | | | | | | | | |
| | | For the Period from January 1, 2006 through December 21, 2006 | | Year Ended December 31, 2005 | | For the Period from September 1, 2004 through December 31, 2004 | |
Predecessor: | | | | | | | | | | |
| Revenues | | $ | 4,488,315 | | $ | 3,713,973 | | $ | 772,449 | |
| Production taxes | | | 493,956 | | | 428,905 | | | 81,868 | |
| Lease operating expenses | | | 2,944,287 | | | 1,537,992 | | | 360,207 | |
| Income (loss) from continuing operations | | | (577,740 | ) | | 26,886 | | | (78,415 | ) |
| | | | | | | | | | | |
| Total assets (as of period end) | | | 14,597,618 | | | 13,058,437 | | | | |
| | | | | | | | | | | |
| | | For the Period from January 1, 2004 through August 31, 2004 | |
Pre-Predecessor: | | | | |
| Revenues | | $ | 1,275,214 | |
| Production taxes | | | 138,087 | |
| Lease operating expenses | | | 583,942 | |
| Excess of revenues over expenses | | | 553,185 | |
We do not have long-term obligations or redeemable preferred stock, and we have not declared any cash dividends.
| (1) | We completed our acquisition of the Cole Creek South and the South Glenrock B fields (Predecessor) on December 22, 2006. |
| (2) | We completed our acquisition of the Big Muddy Field on January 4, 2007. |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
Organization
We are an independent energy company which explores for and develops, produces, and markets oil & gas in North America. Prior to April 2006, Rancher Energy Corp., formerly known as Metalex Resources, Inc. (Metalex), was engaged in the exploration of a gold prospect in British Columbia, Canada. Metalex found no commercially exploitable deposits or reserves of gold. During April 2006, stockholders voted to change the name to Rancher Energy Corp. Since April 2006, we have employed a new Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, and Senior Vice President, Engineering, and are actively pursuing oil & gas prospects in the Rocky Mountain region.
Oil & Gas Property Acquisitions
The following is a summary of the property acquisitions we have recently completed:
Cole Creek South Field and South Glenrock B Field Acquisitions
On December 22, 2006, we purchased certain oil & gas properties for $46,750,000, before adjustments for the period from the effective date to the closing date, plus closing costs of $323,657. The oil & gas properties consisted of (i) a 100% working interest (79.3% net revenue interest) in the Cole Creek South Field, which is located in Wyoming’s Powder River Basin; and (ii) a 93.6% working interest (74.5% net revenue interest) in the South Glenrock B Field, which also is located in Wyoming’s Powder River Basin. In partial consideration for an extension of the closing date, we issued the seller of the oil & gas properties warrants to acquire 250,000 shares of our common stock for $1.50 per share for a period of five years. The estimated fair value of the warrants to purchase common stock of $616,140 was estimated as of the grant date using the Black-Scholes option pricing model, and is included in the acquisition cost.
The total adjusted purchase price was allocated as follows:
| Acquisition costs: | | | | |
| Cash consideration | | $ | 46,750,000 | |
| Direct acquisition costs | | | 323,657 | |
| Estimated fair value of warrants to purchase common stock | | | 616,140 | |
| Total | | $ | 47,689,797 | |
| | | | | |
| Allocation of acquisition costs: | | | | |
| Oil & gas properties: | | | | |
| Unproved | | $ | 31,569,778 | |
| Proved | | | 16,682,101 | |
| Other assets – long-term accounts receivable | | | 53,341 | |
| Other assets – inventory | | | 227,220 | |
| Asset retirement obligation | | | (842,643 | ) |
| Total | | $ | 47,689,797 | |
The Cole Creek South Field is located in Converse County, Wyoming approximately six miles northwest of the town of Glenrock. The field was discovered in 1948 by the Phillips Petroleum Company. In March 2007, production from the Cole Creek South Field was approximately 84 BOPD gross, and 66 BOPD net to our interests, of primarily 34 degree API sweet crude oil.
The South Glenrock B Field is also located in Converse County, Wyoming. The field was discovered in 1950 by Conoco, Inc. Bisected by Interstate 25, the field produces from the Dakota and Muddy sandstone reservoirs that are draped over a structural nose with 2,000 feet of relief. Production is maintained by secondary recovery efforts that were initiated in 1961. In March 2007, production from the South Glenrock B Field was approximately 199 BOPD gross, and 152 BOPD net to our interests, of primarily 35 degree API sweet crude oil.
Big Muddy Field Acquisition
On January 4, 2007, we acquired the Big Muddy Field, which is located in the Powder River Basin east of Casper, Wyoming. The total purchase price was $25,000,000, and closing costs were $672,638. While the Big Muddy Field was discovered in 1916, future profitable operations are dependent on the application of tertiary recovery techniques requiring significant amounts of CO2.
The total adjusted purchase price was allocated as follows:
| Acquisition costs: | | | | |
| Cash consideration | | $ | 25,000,000 | |
| Direct acquisition costs | | | 672,638 | |
| Total | | $ | 25,672,638 | |
| | | | | |
| Allocation of acquisition costs: | | | | |
| Oil & gas properties: | | | | |
| Unproved | | $ | 24,151,745 | |
| Proved | | | 1,870,086 | |
| Asset retirement obligation | | | (349,193 | ) |
| Total | | $ | 25,672,638 | |
Water flooding was initiated in the Frontier formation in 1957 and later expanded to the Dakota and Lakota formations. Over 800 completions have occurred in the field. At the current time, only a few wells are active. Production in March 2007 was approximately 18 BOPD gross, and 14 BOPD net to our interests, of primarily 36 degree API sweet crude oil.
Outlook for the Coming Year
The following summarizes our goals and objectives for the next twelve months:
| · | Borrow funds on a short-term basis to enhance production in two of our fields, to initiate waterflood operations on one of our fields, to continue permitting for our CO2 pipeline project and to provide cash reserves; |
| · | Borrow additional funds on a long-term fixed rate basis to conduct 3-D seismic surveys on our fields and to complete our waterflood plan on our Big Muddy Field; |
| · | Continue to seek long-term financing for our CO2 pipeline and EOR development plan for all our fields. |
| · | Pursue additional asset and project opportunities that are expected to be accretive to stockholder value. |
Since late 2006 we have added operating staff and have engaged consultants to conduct field studies of tertiary development of the three Powder River Basin fields. To date, work has focused on field and engineering studies to prepare for secondary and tertiary development operations. We have also engaged an engineering firm to evaluate routes and undertake the required front end engineering and design for the required CO2 pipeline, as well as another engineering firm to evaluate and design surface facilities appropriate for CO2 injection.
Oil & Gas Properties Development Plans
Our plans for production enhancement, waterflood and CO2 EOR development of our oil fields are dependent on our obtaining substantial additional funding. The raising of that funding is dependent on many factors, some of which are outside our control, and is not assured. One major factor is the level of and projected trends in oil prices, which we cannot protect against by hedging at this time.
Short term production enhancement plan - commencing late 2007
By the end of October 2007, we plan to raise approximately $12 million in a short-term debt financing to enhance production and provide cash reserves. The term of this loan is expected to be one year. Specifically, we plan utilize these funds to:
| · | Install downhole pumps in six wells in our Cole Creek South Field that are currently flowing oil wells, at an estimated cost of approximately $1.7 million; |
| · | Drill two wells in our Big Muddy Field as part of the waterflood plan and evaluation to be conducted later in the year, at a cost of approximately $2.1 million; |
| · | Drill one well in our South Glenrock B Field to access oil reserves that are currently classified as proved undeveloped, at a cost of approximately $1 million; |
| · | Continue permit process for CO2 pipeline project at a cost of approximately $0.5 million; and |
| · | Allocate the remainder of the funds to offering costs, working capital and cash reserves. |
Waterflood development plan - Big Muddy Field -commencing 1st or 2nd quarter of 2008
In late 2007 or early 2008, we plan to raise between approximately $50 million in a long-term fixed rate debt financing to complete the Big Muddy Field waterflood. Specifically, we plan utilize these funds to:
| · | Conduct up to 100 square miles of 3-D seismic surveys and processing to better determine injection pattern locations and alignment of the waterflood and CO2 EOR project, at a cost of approximately $3.5 million; |
| · | Drill, complete and equip 70 wells as water injectors or oil producers at a cost of approximately $46 million; and |
| · | Acquire and construct waterflood surface facilities, at a cost of approximately $11.5 million. |
CO2 EOR development plan - commencing 2009 to 2010
Following the raising of additional funds, we plan to begin CO2 development operations in the Big Muddy Field followed by the South Glenrock B Field and then the Cole Creek South Field. Capital expenditures to implement our CO2 EOR plans include:
| · | Construct a pipeline to transport CO2 from the source to our Big Muddy Field at a cost of approximately $50 to $100 million; |
| · | Acquire and construct surface and compression facilities at our Big Muddy Field to compress, inject and recycle CO2 at a cost of approximately $20 to $30 million; |
| · | Acquire and construct surface facilities at our South Glenrock B Field to inject and recycle CO2 at a cost of approximately $8.5 million; and |
| · | Drill, complete and equip 70-80 wells as CO2 injectors or oil producers on our South Glenrock B Field at a cost of approximately $48 million. |
Since the acquisition of the three fields, other than the agreement with Anadarko for supply of CO2, we have neither made any major capital expenditures nor any firm commitments for major future capital expenditures to date.
Commitments
As part of our CO2 tertiary recovery strategy, on December 15, 2006, we entered into a Product Sale and Purchase Contract with Anadarko for the purchase of CO2 (meeting certain quality specifications) from Anadarko. We intend to use the CO2 for our EOR projects.
The primary term of the Purchase Contract commences upon the later of January 1, 2008, or the date of the first CO2 delivery, and terminates upon the earlier of the day on which we have taken and paid for the Total Contract Quantity, as defined, or 10 years from the commencement date. We have the right to terminate the Purchase Contract at any time with notice to Anadarko, subject to a termination payment as specified in the Purchase Contract.
During the primary term the “Daily Contract Quantity” is 40 MMcf per day for a total of 146 Bcf. CO2 deliveries are subject to a 25 MMcf per day take-or-pay provision. Anadarko has the right to satisfy its own needs before sales to us, which reduces our take-or-pay obligation. In the event the CO2 does not meet certain quality specifications, we have the right to refuse delivery of such CO2.
For CO2 deliveries, we have agreed to pay $1.50 per thousand cubic feet, to be adjusted by a factor that is indexed to the price of Wyoming Sweet oil. From oil that is produced by CO2 injection, we also agreed to convey to Anadarko an overriding royalty interest that increases over time, not to exceed 5%.
Results of Operations, Including Combined Results
In addition to the GAAP presentation of Rancher Energy Corp.’s historical results for the years ended March 31, 2007. 2006 and 2005, we have provided combined revenues, production taxes and lease operating expenses for Rancher Energy Corp., its Predecessor (the Cole Creek South Field and the South Glenrock B Field) and its Predecessor’s Predecessor (Pre-Predecessor) because we believe such financial information may be useful in gaining an understanding of the impact of the acquisitions on Rancher Energy Corp.’s underlying historical performance and future financial results. The combined information is not presented on a GAAP basis and is not necessarily comparable between periods.
The following data includes:
| · | Our results of operations for the years ended March 31, 2007, 2006, and 2005; |
| · | Our Predecessor’s results of operations for the period from January 1, 2006 through December 21, 2006 (the date of acquisition of the Predecessor by Rancher Energy Corp.), the year ended December 31, 2005, and for the period from September 1, 2004 (the date that the Predecessor was acquired from the Pre-Predecessor) through December 31, 2004; |
| · | Our Pre-Predecessor’s revenues, production taxes, and lease operating expenses for the period from January 1, 2004 through August 31, 2004; |
| · | Adjustments to eliminate the Predecessor’s revenues, production taxes and lease operating expenses for the three months ended March 31, 2006 from the Predecessor revenues, production taxes and lease operating expenses for the year ended December 31, 2006, so that the combined information reflects the revenues, production taxes and lease operating expenses for the fiscal year ended March 31, 2007; and |
| · | Combined revenues, production taxes and lease operating expenses for the years ended March 31, 2007, 2006 and 2005. |
| | | Year Ended March 31, 2007 (Unaudited) | |
| | | Rancher Energy Corp. | | Predecessor | | Adjustments | | Combined | |
| Revenue: | | | | | | | | | | | | | |
| Oil production (in barrels) | | | 23,838 | | | 73,076 | | | (18,631 | ) | | 78,283 | |
| Oil price (per barrel) | | | 48.74 | | | 61.42 | | | 61.66 | | | 57.50 | |
| Oil & gas sales | | $ | 1,161,819 | | $ | 4,488,315 | | $ | (1,148,825 | ) | $ | 4,501,309 | |
| | | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | | |
| Production taxes | | | 136,305 | | | 493,956 | | | (120,313 | ) | | 509,948 | |
| Lease operating expenses | | | 700,623 | | | 2,944,287 | | | (574,756 | ) | | 3,070,154 | |
| Depreciation, depletion, and amortization | | | 375,701 | | | 952,784 | | | | | | | |
| Impairment of unproved properties | | | 734,383 | | | - | | | | | | | |
| Accretion expense | | | 29,730 | | | 107,504 | | | | | | | |
| Exploration expense | | | 333,919 | | | - | | | | | | | |
| General and administrative | | | 4,501,737 | | | 567,524 | | | | | | | |
| Total operating expenses | | | 6,812,398 | | | 5,066,055 | | | | | | | |
| | | | | | | | | | | | | | |
| | | | (5,650,579 | ) | | (577,740 | ) | | | | | | |
| | | | | | | | | | | | | | |
| Other income (expense): | | | | | | | | | | | | | |
| Liquidated damages pursuant to registration rights agreement | | | (2,705,531 | ) | | - | | | | | | | |
| Interest expense | | | (37,654 | ) | | - | | | | | | | |
| Amortization of deferred financing costs | | | (537,822 | ) | | - | | | | | | | |
| Interest and other income | | | 229,331 | | | - | | | | | | | |
| Total other income (expense) | | | (3,051,676 | ) | | - | | | | | | | |
| | | | | | | | | | | | | | |
| | | $ | (8,702,255 | ) | $ | (577,740 | ) | | | | | | |
Adjustments:
| · | Revenue, production taxes, and lease operating expenses - represents oil production volumes, oil sales, production taxes, and lease operating expenses for the three months ended March 31, 2006 to derive combined oil production volumes, oil sales, production taxes, and lease operating expenses for the year ended March 31, 2007. |
| | | Year Ended March 31, 2006 (Unaudited) | |
| | | Rancher Energy Corp. | | Predecessor | | Combined | |
| Revenue: | | | | | | | | | | |
| Oil production (in barrels) | | | - | | | 67,321 | | | 67,321 | |
| Oil price (per barrel) | | | - | | | 55.17 | | | 55.17 | |
| Oil & gas sales | | $ | - | | $ | 3,713,973 | | $ | 3,713,973 | |
| | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | |
| Production taxes | | | - | | | 428,905 | | | 428,905 | |
| Lease operating expenses | | | - | | | 1,537,992 | | | 1,537,992 | |
| Depreciation, depletion and amortization | | | 213 | | | 567,345 | | | | |
| Accretion expense | | | - | | | 107,712 | | | | |
| General and administrative | | | 74,240 | | | 1,045,133 | | | | |
| Exploration expense - mining | | | 50,000 | | | - | | | | |
| Total operating expenses | | | 124,453 | | | 3,687,087 | | | | |
| | | | | | | | | | | |
| | | $ | (124,453 | ) | $ | 26,886 | | | | |
| | | | | | | | | | | |
| | | Year Ended March 31, 2005 (Unaudited) | |
| | | Rancher Energy Corp. | | Predecessor | | Pre- Predecessor | | Combined | |
| Revenue: | | | | | | | | | | | | | |
| Oil production (in barrels) | | | - | | | 16,234 | | | 35,882 | | | 52,116 | |
| Oil price (per barrel) | | | - | | | 44.50 | | | 35.54 | | | 38.33 | |
| Oil & gas sales | | $ | - | | $ | 722,449 | | $ | 1,275,214 | | $ | 1,997,663 | |
| | | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | | |
| Production taxes | | | - | | | 81,868 | | | 138,087 | | | 219,955 | |
| Lease operating expenses | | | - | | | 360,207 | | | 583,942 | | | 944,149 | |
| Depreciation, depletion and amortization | | | 201 | | | 62,542 | | | | | | | |
| Accretion expense | | | - | | | 12,990 | | | | | | | |
| General and administrative | | | 26,953 | | | 283,257 | | | | | | | |
Total operating expenses | | | 27,154 | | | 800,864 | | | | | | | |
| | | | | | | | | | | | | | |
| | | $ | (27,154 | ) | $ | (78,415 | ) | | | | | | |
The following provides explanations of changes in revenues, production taxes and lease operating expenses on a combined basis.
Rancher Energy Corp.
Year Ended March 31, 2007 Compared to Year Ended March 31, 2006
Overview. For the year ended March 31, 2007, we reflected a net loss of $8,702,255, or $(0.16) per basic and fully diluted share, as compared to a loss of $124,453, or $(0.00) per basic and fully diluted share, for the corresponding year ended March 31, 2006. During the year ended March 31, 2007, we completed our December 22, 2006 acquisition of the Cole Creek South Field and South Glenrock B Field, and our January 4, 2007 acquisition of the Big Muddy Field. We did not have any oil & gas properties during fiscal 2006. During fiscal year 2007 we directed our efforts to raising capital to finance the acquisitions, and to increase our operational and administrative infrastructure.
Revenue, production taxes, and lease operating expenses. For the year ended March 31, 2007, we reflected oil & gas sales of $1,161,819 on 23,838 barrels of oil at $48.74 per barrel, production taxes (including ad valorem taxes) of $136,305 and lease operating expenses of $700,623, as compared to $0, $0 and $0, respectively, for the corresponding year ended March 31, 2006. Lease operating expenses per barrel of production were $29.39 and production taxes were $5.72 per barrel for the fiscal year ended March 31, 2007. Results for the year ended March 31, 2007 reflect ownership of the three fields from the acquisition dates in December 2006 and January 2007 through the end of the fiscal year.
Depreciation, depletion, and amortization. For the year ended March 31, 2007, we reflected depreciation, depletion, and amortization of $375,701 as compared to $213 for the corresponding year ended March 31, 2006. Depreciation, depletion, and amortization was $14.59 per barrel of production for the fiscal year ended March 31, 2007.
Impairment of unproved properties. For the year ended March 31, 2007, we reflected impairment of unproved properties of $734,383 as compared to $0 for the corresponding year ended March 31, 2006. We determined we would not develop certain properties, and the carrying value would not be realized.
Exploration expense. For the year ended March 31, 2007, we reflected exploration expense of $333,919 as compared to $0 for the corresponding year ended March 31, 2006. Exploration expenses were for geological and geophysical analysis of certain projects, all of which we elected not to pursue.
General and administrative expense. For the year ended March 31, 2007, we reflected general and administrative expenses of $4,501,737 as compared to $74,240 for the corresponding year ended March 31, 2006. The increase is primarily attributed to focusing our efforts on building our oil & gas infrastructure. Included in general and administrative expenses for fiscal 2007 is stock-based compensation of $1,501,908. Other key elements comprising the increase include corporate promotion, Sarbanes-Oxley compliance, audit fees, legal, and reservoir engineering.
Liquidated damages pursuant to registration rights agreement. In connection with our equity private placement in December 2006 and January 2007, we entered into a registration rights agreement and agreed to file a registration statement to register for resale the shares of common stock. The agreement includes provisions for payment if the registration statement is not declared effective by May 20, 2007, and additional payments are due if there are additional delays in obtaining effectiveness. We have determined that the obligation to pay liquidated damages is both probable and can be estimated. Our estimate of $2,705,531 is equal to three months of damages. One month’s damages were paid on May 18, 2007 by the issuance of 933,458 shares, valued at $1.04 per share, with a present value of $953,431. The damages for the two additional months were estimated to have a present value of $876,050 per month, or a total for those months of $1,752,100. A second month’s damages were paid on June 19, 2007 by the issuance of 946,819 shares, and the present value approximated the previously established obligation.
Amortization of deferred financing costs. For the year ended March 31, 2007, we reflected amortization of deferred financing costs of $537,822 as compared to $0 for the corresponding year ended March 31, 2006. We incurred financing costs of $921,821 in connection with the private placement of convertible notes payable with a term of four months. The amortization of those costs was based on the period from the date of the notes through March 30, 2007, the date the notes automatically converted to shares of common stock. When converted, proceeds from the placement were reflected net of the unamortized deferred financing costs.
Interest income. For the year ended March 31, 2007, we reflected interest income of $229,331 as compared to $0 for the corresponding year ended March 31, 2006. The interest income was derived from earnings on excess cash derived from the private placement of units, consisting of common stock and warrants to acquire shares of common stock.
Year Ended March 31, 2006 Compared to Year Ended March 31, 2005
During the year ended March 31, 2006, we had a net loss of $124,453, which was an increase from a net loss of $27,154 for the year ended March 31, 2005. Legal and accounting fees increased to $47,809 from $8,795 in 2006 due to our increased activity. In addition, our increase in activity resulted in increased auditing and review fees. Mining exploration expenses of $50,000 were recognized in the year ended March 31, 2006 which related to expenditures on a mining project that we abandoned subsequent to year end.
Rancher Energy Corp. Combined With Predecessor and Pre-Predecessor
Year Ended March 31, 2007 Compared to Year Ended March 31, 2006
Revenue, production taxes, and lease operating expenses. For the year ended March 31, 2007 (2007), oil & gas sales were $4,501,309 on 78,283 barrels of oil at $57.50 per barrel, as compared to $3,713,973 on 67,321 barrels of oil at $55.17 per barrel, for the year ended March 31, 2006 (2006). The year to year increase in sales of $787,336 reflects a price variance of $157,016 and a volume variance of $630,320. The increased volumes in 2007 resulted from successful recompletions, workovers, re-stimulations and other remedial operational activities on approximately thirty producing wells, completed by the Predecessor prior to our acquisition of the properties. Production taxes (including ad valorem taxes) were $509,948, or $6.51 per barrel in 2007 compared to $428,905, or $6.37 per barrel in 2006. Production taxes correlate directly with the value of oil sold and remained consistent at approximately 11% of sales. Lease operating expenses increased in 2007 to $3,070,154, or $39.22 per barrel, as compared to $1,537,992, or $22.85 per barrel, in 2006. This year to year increase of $1,532,162, is comprised of $250,434 of volume variance and $1,281,728 of cost variance. The cost variance primarily reflects the costs associated with workovers, restimulation and repairs carried out the by the Predecessor prior to our acquisition of the properties.
Year Ended March 31, 2006 Compared to Year Ended March 31, 2005
Revenue, production taxes, and lease operating expenses. For the year ended March 31, 2006 (2006), oil & gas sales were $3,713,973 on 67,321 barrels of oil at $55.17 per barrel, as compared to $1,997,663 on 52,116 barrels of oil at $38.33 per barrel for the year ended March 31, 2005 (2005). The year to year increase in sales of $1,736,310, reflects a price variance of $897,479 and a volume variance of $838,831. The increased volumes in 2006 reflect successful recompletions, workovers, re-stimulations and other remedial operational activities on approximately thirty producing wells carried out by the Predecessor following their acquisition of the properties from the Pre-Predecessor effective September 1, 2004. Production taxes (including ad valorem taxes) were $428,905, or $6.37 per barrel in 2006 compared to $219,955, or $4.22 per barrel in 2005. Production taxes correlate directly with the value of oil sold and remained consistent at approximately 11 % of sales. Lease operating expenses were $1,537,992, or $22.85 per barrel in 2006, as compared to $944,149, or $18.12 per barrel in 2005. This year to year increase of $593,843, consists of $275,458 of volume variance and $318,385 of cost variance. The cost increase primarily reflects the workovers, re-stimulations and repairs carried out the by the Predecessor after their acquisition of the properties. In addition, the Predecessor utilized third party contractors to conduct operations throughout all of 2006 as compared to only six months of 2005, which third party contractors were significantly more expensive than using company operators.
Liquidity and Capital Resources
As of March 31, 2007, we had working capital of $889,221. Current liabilities included $2,705,531 for penalty payments pursuant to the Registration Rights Agreement, all of which was paid in stock.
We have revenue from production operations in our three fields. However, we currently have negative cash flow from operating activities. Monthly oil & gas production revenue is adequate to cover monthly field operating costs and production taxes at the current time. Only a portion of the remaining cash costs, which consist primarily of general and administrative expenses, are covered by cash flow.
Our currently available cash sources are not sufficient to fund our planned expenditures for the secondary and tertiary development of our three fields. Essentially all of the necessary funding for their development is expected to come from, and is dependent on, successful completion of a debt financing. As of June 30, 2007, the Company was debt-free.
We are making plans for a short-term debt financing to commence our waterflood plan on our Big Muddy Field and to further enhance production on our Cole Creek South Field and South Glenrock B Field, which we expect to be followed by a larger long-term debt financing in one or more facilities in an amount sufficient to fund the remainder of the Big Muddy Field waterflood project. We then plan to raise additional funds in furtherance of our CO2 EOR plans.
Short-Term Financing
We expect to close a short-term debt financing by the end of October 2007 in the approximate principal amount of $12 million. The interest rate is expected to be approximately 12%, plus 2% in origination fees, and a 2% overriding royalty interest on Rancher Energy’s property interests. The term of the loan is expected to be one year and the loan will be secured by a security interest in our three fields. We intend to use approximately half the funds from this loan to further enhance production in our Cole Creek South Field and South Glenrock B Field and to begin a waterflood project in our Big Muddy Field. We intend to use the other half of the funds from this loan for offering costs, working capital, and general corporate purposes to enhance our cash reserves.
Long-Term Debt Financings
We anticipate raising approximately $50 million in late 2007 or early 2008, in one or more long-term debt financings, to carry out the waterflood program on our Big Muddy Field. There is substantial potential for oil recovery via waterflood at our Big Muddy Field, and the waterflood strategy will stand alone as a project separate and apart from our overall CO2 flood strategy. The waterflood development implemented on the Big Muddy Field also is a precursor to eventual CO2 flooding of the field, as the work necessary to prepare the field for waterflood is similarly needed for the comprehensive CO2 flood. We anticipate that the short-term debt financing will be refinanced or rolled into the long-term debt financing. We also anticipate that the Big Muddy Field will be the first field targeted for our comprehensive CO2 flood, followed by the South Glenrock B field.
Following the financing for the Big Muddy Field waterflood project, we plan to raise additional financing in 2008 to proceed with our CO2 EOR tertiary development plans of our three fields.
Completion of the short-term debt financing and long-term debt financings will be subject to market conditions and Company-specific factors. Without receipt of proceeds from these facilities, the Company’s negative cash flow is projected to be covered by available cash through the third quarter of calendar year 2007. However, in the event we are not successful in raising the the short-term debt financing, we do not plan to allow negative monthly cash flow to remain at current levels. Rather, we plan to address the situation at that time by reducing staffing levels to reduce cash requirements to levels supported by current operations.
Change in Financial Condition
We entered into a number of debt and equity transactions in fiscal year 2007, which dramatically increased our financial capability. The following is a summary of debt and equity transactions completed during fiscal 2007:
Convertible Debt Transactions
Venture Capital First LLC
On June 9, 2006, we borrowed $500,000 from Venture Capital First LLC (Venture Capital). Principal and interest at an annual rate of 6% were due December 9, 2006. The agreement provided that Venture Capital had the option to convert all or a portion of the loan into common stock and warrants to purchase common stock, either (i) at the closing price of our shares on the day preceding notice from Venture Capital of its intent to convert all or a portion of the loan into common stock or, (ii) in the event we conducted an offering of common stock, or units consisting of common stock and warrants to purchase stock, at the price of such shares or units in the offering.
On July 19, 2006, Venture Capital elected to convert its entire loan and accrued interest into 1,006,905 shares of common stock and warrants to purchase 1,006,905 shares of common stock at a price of $0.50 per unit, the price per unit in the offering discussed in Equity Transactions below. The warrants are exercisable over a two-year period, at a price of $0.75 per share for the first year, and $1.00 per share for the second year. On December 21, 2006, the warrant holder agreed not to exercise its right to acquire shares of common stock until we received stockholder approval to increase the number of authorized shares, and the exercise price of $0.75 per share was extended by us through the second year.
Private Placement – Convertible Notes Payable
As part of the December 2006 and January 2007 equity private placement, which is further discussed below, in December 2006 and January 2007, we received $10,494,582 from certain investors, who received convertible notes payable. Upon stockholder approval of an amendment to the Articles of Incorporation increasing the authorized shares of our common stock, which occurred on March 30, 2007, the notes automatically converted into shares of common stock. The number of shares issued upon conversion of the notes was equal to the face amount of the notes divided by $1.50 per share, which is the price that the shares were simultaneously sold in a private placement as discussed below, or 6,996,342 shares. Had the notes not converted, the notes would have accrued interest at an annual rate of 12% beginning 120 days after issuance, which was the maturity date of the notes.
Consistent with the terms and conditions of the Units sold in the private placement (as further discussed below under the heading “Private Placement” and in Note 6 – Sale of Common Stock and Warrants to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2007 in Part IV, Item 15 of the Original Annual Report), the convertible notes payable were issued with warrants to acquire 6,996,322 shares of common stock at $1.50 per share.
Equity Transactions
Units Issued Pursuant to Regulation S
For the period from June 2006 through October 2006, we sold 18,133,500 Units for $0.50 per Unit, totaling gross proceeds of $9,066,750, pursuant to the exemption from registration of securities under the Securities Act of 1933 as provided by Regulation S. Each Unit consisted of one share of common stock and a warrant to purchase one additional share of common stock.
For 8,850,000 Units, we paid no underwriting commissions. For 9,283,500 Units, we paid a cash commission of $232,088, equal to 5% of the proceeds from the units, and a stock-based commission of 464,175 shares of common stock, equal to 5% of the number of Units sold. The sum of the shares sold and the commission shares aggregated 18,597,675. All warrants were originally exercisable for a period of two years from the date of issuance. During the first year, the exercise price was $0.75 per share; during the second year, the exercise price was $1.00 per share. The warrants are redeemable by us for no consideration upon 30 days prior notice. A portion of these warrants were modified as discussed below.
Warrant Modification – Warrants Issued Pursuant to Regulation S
On December 21, 2006, holders of 13,192,000 warrants issued pursuant to Regulation S in a private placement from June through October 2006 agreed not to exercise their right to acquire shares of common stock until we received stockholder approval, which was obtained on March 30, 2007, to increase the number of our authorized shares. Pursuant to this agreement, the exercise price of $0.75 per share was extended by us through the second year. Terms for the remaining 4,941,500 warrants were unchanged.
Private Placement
On December 21, 2006, we entered into a Securities Purchase Agreement, as amended, with institutional and individual accredited investors to effect a $79,500,000 private placement of shares of our common stock and other securities in multiple closings. As part of this private placement, we raised an aggregate of $79,405,418 and issued (i) 45,940,510 shares of common stock, (ii) promissory notes that were convertible into 6,996,342 shares of common stock, and (iii) warrants to purchase 52,936,832 shares of common stock. The warrants issued to investors in the private placement are exercisable during the five year period beginning on the date we amended and restated our Articles of Incorporation to increase our authorized shares of common stock, which was March 30, 2007. The notes issued in the private placement automatically converted into shares of common stock on March 30, 2007. In conjunction with the private placement, we also used the services of placement agents and have issued warrants to purchase 3,633,313 shares of common stock to these agents or their designees. The warrants issued to the placement agents or their designees are exercisable during the two year period (warrants to purchase 2,187,580 shares of common stock) or the five year period (warrants to purchase 1,445,733 shares of common stock) beginning on the date we amended and restated our Articles of Incorporation to increase our authorized shares of common stock, which was March 30, 2007. All of the warrants issued in conjunction with the private placement have an exercise price of $1.50 per share.
In connection with the private placement, we also entered into a Registration Rights Agreement with the investors in which we agreed to register for resale the shares of common stock issued in the private placement as well as the shares underlying the warrants and convertible notes issued in the private placement. There are liquidated damages payable pursuant to the Securities Purchase Agreement and Registration Rights Agreement relating to these registration provisions and other obligations, as described in Note 6 – Sale of Common Stock and Warrants to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2007 in Part IV, Item 15, of the Original Annual Report, which, if triggered, could result in substantial amounts to be due to the investors.
Summary of Warrants
We have 19,140,405 warrants outstanding to acquire our common stock at an exercise price of $0.75 per share, all of which expire by October 18, 2008. The exercise of the full amount of these warrants, which is not assured, would add $14,355,304 to our liquidity. In the longer term, the exercise of the remaining 56,820,165 warrants outstanding to acquire our common stock at an exercise price of $1.50 per share would add $85,230,247 to our liquidity, if all were exercised. These options expire by March 30, 2012.
The following is a summary of warrants as of March 31, 2007.
| | | Warrants | | Exercise Price | | Expiration Date | |
| Warrants issued in connection with the following: | | | | | | | | | | |
| | | | | | | | | | | |
| Sale of common stock pursuant to Regulation S | | | 18,133,500 | | $ | 0.75-1.00 | | | July 5, 2008 to October 18, 2008 | |
| | | | | | | | | | | |
| Conversion of notes payable into common stock | | | 1,006,905 | | $ | 0.75 | | | July 19, 2008 | |
| | | | | | | | | | | |
| Private placement of common stock | | | 45,940,510 | | $ | 1.50 | | | March 30, 2012 | |
| | | | | | | | | | | |
| Private placement of convertible notes payable | | | 6,996,322 | | $ | 1.50 | | | March 30, 2012 | |
| | | | | | | | | | | |
| Private placement agent commissions | | | 2,187,580 | | $ | 1.50 | | | March 30, 2009 | |
| | | | | | | | | | | |
| Private placement agent commissions | | | 1,445,733 | | $ | 1.50 | | | March 30, 2012 | |
| | | | | | | | | | | |
| Acquisition of oil & gas properties | | | 250,000 | | $ | 1.50 | | | December 22, 2011 | |
| | | | | | | | | | | |
| Total warrants outstanding at March 31, 2007 | | | 75,960,550 | | | | | | | |
Cash Flows
The following is a summary of our comparative cash flows:
| | | For the Years Ended March 31, | |
| | | 2007 | | 2006 | | 2005 | |
| Cash flows from: | | | | | | | | | | |
| Operating activities | | $ | (2,285,430 | ) | $ | (124,073 | ) | $ | (25,050 | ) |
| Investing activities | | | (74,357,306 | ) | | - | | | (890 | ) |
| Financing activities | | | 81,726,538 | | | 166,094 | | | 30,000 | |
Analysis of Cash Flow Changes between 2007 and 2006
Cash flows used for operating activities increased primarily as a result of general and administrative expenses incurred in connection with the expansion of our oil & gas operations.
Cash flows used for investing activities increased primarily as a result of expending $47,073,657 in connection with the acquisition of the Cole Creek South and South Glenrock B Fields, and $25,672,638 in connection with the acquisition of the Big Muddy Field. We expended $841,993 for other oil & gas property capital expenditures and $769,018 for other equipment.
Cash flows provided by financing activities increased primarily as a result of certain private placements of equity securities aggregating net proceeds of $71,653,937. In connection with the private placement of equity securities, we also received net proceeds of $10,494,582 from the issuance of convertible notes payable and warrants to acquire shares of our common stock. The notes payable were converted to equity on March 30, 2007.
Capital Expenditures
The following table sets forth certain historical information regarding costs incurred in oil & gas property acquisition, exploration and development activities, whether capitalized or expensed.
| | | For the Year Ended March 31, | |
| | | 2007 | | 2006 | | 2005 | |
| | | | | | | | |
| Exploration | | $ | 333,919 | | $ | - | | $ | - | |
| Development | | | - | | | - | | | - | |
| Acquisitions: | | | | | | | | | | |
Unproved | | | 56,813,516 | | | - | | | - | |
Proved | | | 18,552,188 | | | - | | | - | |
| Total | | | 75,699,623 | | | - | | | - | |
| | | | | | | | | | | |
| Costs associated with asset retirement obligations | | $ | 1,191,837 | | $ | - | | $ | - | |
Schedule of Contractual Obligations
The following table summarizes our future estimated minimum lease payments for our office space for the periods specified.
| | | Total | | Less than 1
year | | 1 – 3 years | | 3 – 5 years | | More than 5
years | |
| | | | | | | | | | | | |
| Operating lease | | $ | 1,907,640 | | $ | 280,859 | | $ | 733,061 | | $ | 765,773 | | $ | 127,947 | |
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing nor do we have any unconsolidated subsidiaries.
Critical Accounting Policies and Estimates
We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil. Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions, which affect the estimates we use, on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changing business conditions or unexpected circumstances. Policies we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies see Note 1—Organization and Summary of Significant Accounting Policies, Note 3—Asset Retirement Obligations, and Note 7—Disclosures About Oil & Gas Producing Activities to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2007, which are contained in the Original Annual Report.
Oil & gas reserve quantities. We recorded our first proved oil and gas reserves in the year ended March 31, 2007. Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Ryder Scott Company L.P. (Ryder Scott), our independent reserve engineer, prepares a reserve and economic evaluation of all of our properties. Assumptions used by the independent reserve engineers in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of:
| Ÿ | the quality and quantity of available data; |
| Ÿ | the interpretation of that data; |
| Ÿ | the accuracy of various mandated economic assumptions; and |
| Ÿ | the judgment of the independent reserve engineer. |
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs will not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves changes. Any change in reserves directly impacts our estimate of future cash flows from the property, the property’s fair value and the depreciation, depletion and amortization (DD&A) rate.
Successful efforts method. We use the successful efforts method of accounting for our oil and natural gas properties under Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether or not the well is economically productive or nonproductive.
If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the Statement of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of the Statement of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well would be classified as development or exploratory based on whether it is in a proved or unproved reservoir for determination of capital or expense. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures would be charged to expense.
DD&A expense is directly affected by our reserve estimates. Any change in reserves directly impacts the amount of DD&A expense that we recognize in a given period. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. DD&A expense associated with lease and well equipment and intangible drilling costs are based upon only proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense. Ryder Scott, our independent petroleum engineers, estimate our reserves once a year at March 31.
Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of total proved developed reserves or proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf to one barrel of oil. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate.
The costs of retired, sold or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.
Valuation of long-lived and intangible assets. In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, must be assessed whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Any impairment charge incurred is expensed and reduces our recorded basis in the asset pool. Management currently aggregates proved property for impairment testing for the Company using only one pool of assets due to the geologic similarity and proximity of the properties. The price assumptions used to calculate undiscounted cash flows are based on judgment. We use prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment while higher prices would have the opposite effect.
Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in our analyses of liquidity and capital resources. We derive our revenue primarily from the sale of produced crude oil. We report revenue as the gross amounts we receive for our net revenue interest before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.
Asset retirement obligations. We are required to estimate our eventual obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of our oil and natural gas wells and related facilities. We recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of our oil and natural gas properties at its discounted fair value. The liability is then accreted up by recording expense each period until it is settled or the well is sold, at which time the liability is reversed.
The fair value of the liability associated with the asset retirement obligation is determined using significant assumptions, including current estimates of the plugging and abandonment costs, annual expected inflation of these costs, the productive life of the asset and our credit-adjusted risk-free interest rate used to discount the expected future cash flows. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the obligation are recorded with an offsetting change to the carrying amount of the related oil and natural gas properties, resulting in prospective changes to DD&A and accretion expense. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas properties, the costs to ultimately retire these assets may vary significantly from our estimates.
Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the financial statements are prepared, therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we used and actual amounts we reported are recorded in the period in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery could have an impact on our results of operations. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. To date, we have not recorded any deferred tax assets because of the historical losses that we have incurred.
Stock-based compensation. As of April 1, 2006, we adopted the provisions of SFAS No. 123(R), Accounting for Stock-Based Compensation, which requires companies to recognize compensation cost for stock-based awards based on the estimated fair value of the award. Compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period, which generally represents the vesting period. The Company uses the Black-Scholes option valuation model to calculate the fair value disclosures under SFAS 123(R). This model requires the Company to estimate a risk free interest rate, the volatility of the Company’s common stock price and anticipated forfeitures of options on a going forward basis. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense. As a result of adoption of SFAS No 123(R), we recorded compensation expense associated with stock options totaling $1,501,908 under the modified-prospective adoption method.
Registration Payment Arrangements. In connection with the sale of certain Units, the Company has entered into agreements that require the transfer of consideration under registration and other payment arrangements, if certain conditions are not met. The following is a description of the conditions and those that have not been met.
Under the terms of the Registration Rights Agreement, the Company must pay the holders of the registrable securities issued in the December 2006 and January 2007 equity private placement, liquidated damages if the registration statement that was filed in conjunction with the private placement has not been declared effective by the U.S. Securities and Exchange Commission (SEC) within 150 days of the closing of the private placement (December 21, 2006). The liquidated damages are due on or before the day of the failure (May 20, 2007) and every 30 days thereafter, or three business days after the failure is cured, if earlier. The amount due is 1% of the aggregate purchase price, or $794,000 per month. If the Company fails to make the payments timely, interest accrues at a rate of 1.5% per month. All payments pursuant to the registration rights agreement and the private placement agreement cannot exceed 24% of the aggregate purchase price, or $19,057,000 in total. The payment may be made in cash, notes, or shares of common stock, at the Company’s option, as long as the Company does not have an equity condition failure. The equity condition failures are described further below. Pursuant to the terms of the registration rights agreement, if the Company opts to pay the liquidated damages in shares of common stock, the number of shares issued is based on the payment amount of $794,000 divided by 90% of the volume weighted average price of the Company’s common stock for the 10 trading days immediately preceding the payment due date.
Once the SEC declares the Company’s registration statement effective, the Company must maintain effectiveness, provide the information necessary for sale of shares to be made, register a sufficient number of shares, and maintain the listing of the shares. Lack of compliance requires the Company to pay the holders of the registrable securities liquidated damages under the same terms discussed above.
It is possible that the SEC will object to and reduce the number of shares being registered. If that happens, the Company is obligated to pay liquidated damages to the holders of the registrable shares under the same terms discussed above.
Failure to maintain the equity conditions, a description of which follows, negates the Company’s ability to settle the liquidated damages in shares of common stock. The Company must ensure that:
| | o | Common stock is designated for quotation on OTC Bulletin Board, the New York Stock Exchange, the NASDAQ Global Select Market, the NASDAQ Global Market, the NASDAQ Capital Market, or the American Stock Exchange; |
| | § | Common stock has not been suspended from trading, other than for two days due to business announcements; and |
| | § | Delisting or suspension has not been threatened, or is not pending. |
| | o | Shares of common stock have been delivered upon conversion of Notes and Warrants on a timely basis; |
| | o | Shares may be issued in full without violating the rules and regulations of the exchange or market upon which they are listed or quoted; |
| | o | Payments have been made within five business days of when due pursuant to the Securities Purchase Agreement, the Convertible Notes, the Registration Rights Agreement, the Transfer Agent Instructions, or the Warrants (Transaction Documents); |
| | o | There has not been a change in control of the company, a merger of the company or an event of default as defined in the Notes; and |
| | o | There is material compliance with the provisions, covenants, representations or warranties of all Transaction Documents. |
There is an equity conditions failure if, on any day during the 10 trading days prior to when a registration-delay payment is due, the equity conditions have not been satisfied or waived.
Under the terms of the Securities Purchase Agreement, liquidated damages are due to the holders of the securities if the Company meets the applicable listing requirements on an approved exchange or market but the registrable shares are not listed by December 21, 2007 on an approved exchange or market. The liquidated damages are equal to 0.25% of the aggregate purchase price, or $198,000, payable in cash. The payments are due on the day of the listing failure.
Currently, there are no equity conditions failures.
Uncertainties involved in applying this principle, the variability that may result from its application, measurement methods, and the accuracy of estimates and underlying assumptions follow:
| | · | Uncertainty exists as to when the registration statement filed with the SEC will be declared effective and, consequently, variability exists as to the amount of liquidated damages that may be ultimately required. We have had extensive discussions with the SEC, our Board of Directors, management, legal counsel and our independent registered public accounting firm in an effort to determine when effectiveness might occur. These discussions were the basis for derivation of the amount reflected as liquidated damages pursuant to registration rights arrangement in our financial statements. The amount of the actual expense is subject to the number of shares issued and the fair market value of those shares when issued. |
| | · | Uncertainty exists as to the Company’s ability to maintain effectiveness, provide the information necessary for sale of shares to be made, register a sufficient number of shares, and maintain the listing of the shares once the SEC declares the Company’s registration statement effective. We believe we have the ability to comply with these requirements and, consequently, have not reflected any impact in our financial statements. |
| | · | Uncertainty exists as to whether or not the SEC will object to and reduce the number of shares being registered. We are not aware of any matters that would lead us to believe that that could occur and, consequently, have not reflected any impact in our consolidated financial statements. |
| | · | Uncertainty exists as to whether or not the Company will meet the applicable listing requirements on an approved exchange or market, and that the registrable shares will be listed by December 21, 2007 on an approved exchange or market. We believe we have the ability to comply with these requirements and, consequently, have not reflected any impact in our financial statements. |
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
(a) Documents filed as a part of the report:
| (3) | Exhibits. The exhibits filed as part of this Amendment No. 3 on Form 10-K/A are reflected on the Exhibit Index following the signature page. |
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | RANCHER ENERGY CORP. |
| | | (Registrant) |
| | | |
| Date: October 10, 2007 | By: | /s/ John Works |
| | | John Works |
| | | President, Chief Executive Officer, Principal Executive Officer, Chief Financial Officer, Principal Financial Officer, Director, Secretary, and Treasurer |
Exhibit | | Description |
| 3.1 | | Amended and Restated Articles of Incorporation (17) |
| 3.4 | | Amended and Restated Bylaws (2) |
| 4.1 | | Form of Stock Certificate for Fully Paid, Non-Assessable Common Stock of the Company (1) |
| 4.2 | | Form of Unit Purchase Agreement (2) |
| 4.3 | | Form of Warrant Certificate (2) |
| 4.4 | | Form of Registration Rights Agreement, dated December 21, 2006 (3) |
| 4.5 | | Form of Warrant to Purchase Common Stock (3) |
| 10.1 | | Burke Ranch Unit Purchase and Participation Agreement between Hot Springs Resources Ltd. and PIN Petroleum Partners Ltd., dated February 6, 2006 (4) |
| 10.2 | | Employment Agreement between John Works and Rancher Energy Corp., dated June 1, 2006 (5) |
| 10.3 | | Assignment Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp., dated June 6, 2006 (5) |
| 10.4 | | Loan Agreement between Enerex Capital, Corp. and Rancher Energy Corp., dated June 6, 2006 (5) |
| 10.5 | | Letter Agreement between NITEC LLC and Rancher Energy Corp., dated June 7, 2006 (5) |
| 10.6 | | Loan Agreement between Venture Capital First LLC and Rancher Energy Corp., dated June 9, 2006 (6) |
| 10.7 | | Exploration and Development Agreement between Big Snowy Resources, LP and Rancher Energy Corp., dated June 15, 2006 (5) |
| 10.8 | | Assignment Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp., dated June 21, 2006 (5) |
| 10.9 | | Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp., dated August 10, 2006 (4) |
| 10.10 | | South Glenrock and South Cole Creek Purchase and Sale Agreement by and between Nielson & Associates, Inc. and Rancher Energy Corp., dated October 1, 2006 (7) |
| 10.11 | | Rancher Energy Corp. 2006 Stock Incentive Plan (7) |
| 10.12 | | Rancher Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement (7) |
| 10.13 | | Employment Agreement by and between John Dobitz and Rancher Energy Corp., dated October 2, 2006 (7) |
| 10.14 | | Denver Place Office Lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated October 30, 2006 (8) |
| 10.15 | | Employment Agreement between Andrew Casazza and Rancher Energy Corp., dated October 23, 2006 (9) |
| 10.16 | | Finder’s Fee Agreement between Falcon Capital and Rancher Energy Corp. (10) |
| 10.17 | | Amendment to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp. (11) |
| 10.18 | | Letter Agreement between Certain Unit Holders and Rancher Energy Corp., dated December 8, 2006 (2) |
| 10.19 | | Letter Agreement between Certain Option Holders and Rancher Energy Corp., dated December 13, 2006 (2) |
| 10.20 | | Product Sale and Purchase Contract by and between Rancher Energy Corp. and the Anadarko Petroleum Corporation, dated December 15, 2006 (12) |
| 10.21 | | Amendment to Purchase and Sale Agreement between Nielson & Associates, Inc. and Rancher Energy Corp. (13) |
| 10.22 | | Securities Purchase Agreement by and among Rancher Energy Corp. and the Buyers identified therein, dated December 21, 2006 (3) |
| 10.23 | | Lock-Up Agreement between Rancher Energy Corp. and Stockholders identified therein, dated December 21, 2006 (3) |
| 10.24 | | Voting Agreement between Rancher Energy Corp. and Stockholders identified therein, dated as of December 13, 2006 (3) |
| 10.25 | | Form of Convertible Note (14) |
| 10.26 | | Employment Agreement between Daniel Foley and Rancher Energy Corp., dated January 12, 2007 (15) |
| 10.27 | | First Amendment to Securities Purchase Agreement by and among Rancher Energy Corp. and the Buyers identified therein, dated as of January 18, 2007 (16) |
| 10.28 | | Rancher Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement (20) |
| 10.29 | | First Amendment to Employment Agreement by and between John Works and Rancher Energy Corp., dated March 14, 2007 (20) |
| 10.30 | | Employment Agreement between Richard Kurtenbach and Rancher Energy Corp., dated August 3, 2007(22) |
| 14.1 | | Code of Business Conduct and Ethics (18) |
| 16.1 | | Letter from Williams & Webster, P.S. regarding change in certifying accountant(19) |
| 21.1 | | List of Subsidiaries (21) |
| 23.1 | | Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers(23) |
| 31.1 | | Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer) (23) |
| 31.2 | | Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Financial Officer) (23) |
| 32.1 | | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (23) |
| (1) | Incorporated by reference from our Form SB-2 Registration Statement filed on June 9, 2004 (File No. 333-116307). |
| (2) | Incorporated by reference from our Current Report on Form 8-K filed on December 18, 2006 (File No. 000-51425). |
| (3) | Incorporated by reference from our Current Report on Form 8-K filed on December 27, 2006 (File No. 000-51425). |
| (4) | Incorporated by reference from our Quarterly Report on Form 10-Q/A filed on August 28, 2006 (File No. 000-51425). |
| (5) | Incorporated by reference from our Annual Report on Form 10-K filed on June 30, 2006 (File No. 000-51425). |
| (6) | Incorporated by reference from our Current Report on Form 8-K filed on June 21, 2006 (File No. 000-51425). |
| (7) | Incorporated by reference from our Current Report on Form 8-K filed on October 6, 2006 (File No. 000-51425). |
| (8) | Incorporated by reference from our Current Report on Form 8-K filed on November 9, 2006 (File No. 000-51425). |
| (9) | Incorporated by reference from our Current Report on Form 8-K filed on November 14,2006 (File No. 000-51425). |
| (10) | Incorporated by reference from our Current Report on Form 8-K/A filed on November 14, 2006 (File No. 000-51425). |
| (11) | Incorporated by reference from our Current Report on Form 8-K filed on December 4, 2006 (File No. 000-51425). |
| (12) | Incorporated by reference from our Current Report on Form 8-K filed on December 22, 2006 (File No. 000-51425). |
| (13) | Incorporated by reference from our Current Report on Form 8-K filed on December 27, 2006 (File No. 000-51425). |
| (14) | Incorporated by reference from our Current Report on Form 8-K filed on January 8, 2007 (File No. 000-51425). |
| (15) | Incorporated by reference from our Current Report on Form 8-K filed on January 16, 2007 (File No. 000-51425). |
| (16) | Incorporated by reference from our Current Report on Form 8-K filed on January 25, 2007 (File No. 000-51425). |
| (17) | Incorporated by reference from our Current Report on Form 8-K filed on April 3, 2007 (File No. 000-51425). |
| (18) | Incorporated by reference from our Current Report on Form 8-K filed on June 6, 2007 (File No. 000-51425). |
| (19) | Incorporated by reference from our Current Report on Form 8-K/A filed on August 9, 2006 (File No. 000-51425). |
| (20) | Incorporated by reference from our Current Report on Form 8-K filed on March 20, 2007 (File No. 000-51425). |
| (21) | Incorporated by reference from our Annual Report on Form 10-K filed on June 29, 2007 (File No. 000-51425). |
| (22) | Incorporated by reference from our Current Report on Form 8-K filed on August 7, 2007 (File No. 000-51425). |
