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EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE AND CHIEF FINANCIAL OFFICER - RED MOUNTAIN RESOURCES, INC.ex32-1.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - RED MOUNTAIN RESOURCES, INC.ex31-2.htm
EXCEL - IDEA: XBRL DOCUMENT - RED MOUNTAIN RESOURCES, INC.Financial_Report.xls
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER - RED MOUNTAIN RESOURCES, INC.ex31-1.htm
 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 


 

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
  For the quarterly period ended: September 30, 2014
   
OR
   
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
  For the transition period from __________ to __________

 

Commission File Number 000-5444

 


 

RED MOUNTAIN RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

Texas 27-1739487
(State or other jurisdiction of incorporation or
organization)
(I.R.S. Employer Identification No.)
   
2515 McKinney Avenue, Suite 900
Dallas, TX
75201
(Address of principal executive offices) (Zip Code)

 

(214) 871-0400

(Registrant’s telephone number, including area code)

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 is required to submit and post such files).    Yes      No  

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer Accelerated filer
       
Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

 

As of November 14, 2014, the registrant had 14,857,488 shares of common stock outstanding.

 

 
 

 

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION
       
Item 1. Financial Statements    
       
  Condensed Consolidated Balance Sheets as of September 30, 2014 and June 30, 2014   1
       
  Condensed Consolidated Statements of Operations for Each of the Three Months Ended September 30, 2014 and 2013   2
       
  Condensed Consolidated Statements of Cash Flows for Each of the Three Months Ended September 30, 2014 and 2013   3
       
  Condensed Consolidated Statements of Stockholders’ Equity for the Three Months Ended September 30, 2014   4
       
  Notes to Condensed Consolidated Financial Statements   5
       
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations   16
       
Item 3. Quantitative and Qualitative Disclosures About Market Risk   24
       
Item 4. Controls and Procedures   25
     
PART II. OTHER INFORMATION
       
Item 1. Legal Proceedings   26
       
Item 1A. Risk Factors   26
       
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds   27
       
Item 3. Defaults Upon Senior Securities   27
       
Item 4. Mine Safety Disclosures   27
       
Item 5. Other Information   27
       
Item 6. Exhibits   28

 

 
 

 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

Red Mountain Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited) 

 (in thousands)

 

   September 30,  June 30,
   2014  2014
ASSETS          
Current Assets:          
Cash and cash equivalents  $1,000   $1,682 
Accounts receivable - oil and natural gas sales   2,772    3,186 
Accounts receivable – joint interest   764    1,645 
Prepaid expenses and other current assets   551    527 
Commodities derivative asset – current   189    37 
Deferred tax asset – current   277    368 
   Total current assets   5,553    7,445 
Long-Term Investments:          
Debentures – held to maturity   4,820    4,820 
Oil and Natural Gas Properties, Successful Efforts Method:          
Proved properties   85,146    82,362 
Unproved properties   19,043    19,109 
Other property and equipment   

1,139 

    1,196 
Less accumulated depreciation, depletion, amortization and impairment   (21,977)   (19,497)
   Oil and natural gas properties, net   83,351    83,170 
Other Assets:          
Restricted cash, long-term   493    493 
Debt issuance costs, net of current portion   975    1,101 
Security deposit and other assets   181    197 
Total Assets  $95,373   $97,226 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY          
Current Liabilities:          
Accounts payable  $4,467   $3,536 
Revenues payable   1,154    1,673 
Accrued expenses   2,605    2,035 
Commodities derivative liability   —      121 
Dividend payable   175    179 
Taxes payable   3    —   
Asset retirement obligation – current   178    214 
Environmental remediation liability – current   2,057    2,067 
Line of credit – current   26,800    —  
   Total current liabilities   37,439    9,825 
Long-Term Liabilities:          
Mandatorily redeemable preferred stock, net of discount of $1,464 and $1,561   4,898    4,801 
Line of credit, net of current portion   —     26,800 
Deferred tax liability – long-term   330    409 
Asset retirement obligation, net of current portion   5,570    5,531 
   Total long-term liabilities   10,798    37,541 
Total Liabilities   48,237    47,366 
Commitments and Contingencies (Note 10)          
Stockholders’ Equity:          
Common stock, $0.00001 par value; 50,000 shares authorized; 14,857 shares issued and 14,790 shares outstanding as of September 30, 2014 and June 30, 2014   1    1 
Noncontrolling interest   6,244    6,076 
Additional paid-in capital   78,105    78,105 
Accumulated deficit   (37,214)   (34,322)
   Total stockholders’ equity   47,136    49,860 
Total Liabilities and Stockholders’ Equity  $95,373   $97,226 

 

 

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

 

1
 

 

Red Mountain Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands, except per share amounts)

 

   Three Months
Ended
September 30,
   2014  2013
Revenue:          
Oil and natural gas sales  $5,272   $5,774 
Operating Expenses:          
Exploration expense   250    101 
Dry hole expense   533    —   
Production taxes   419    606 
Lease operating expenses   1,156    747 
Natural gas transportation and marketing expenses   98    38 
Depreciation, depletion, amortization and impairment   2,409    2,091 
Accretion of discount on asset retirement obligation   34    67 
General and administrative expense   2,689    1,942 
   Total operating expenses   7,588    5,592 
Income (Loss) from Operations   (2,316)   182 
Other Income (Expense):          
Interest expense   (665)   (927)
Gain (loss) on commodity derivatives   269    (384)
Total Other Expense   (396)   (1,311)
Loss Before Income Taxes   (2,712)   (1,129)
Income tax provision   (12)   —   
Net loss   (2,724)   (1,129)
Net income attributable to noncontrolling interest   168    146 
Net loss attributable to Red Mountain Resources, Inc.  $(2,892)  $(1,275)
Basic and diluted net loss per common share  $(0.19)  $(0.10)
Basic and diluted weighted average common shares outstanding   14,857    12,922 

 

 

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

 

2
 

 

Red Mountain Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

  

   Three Months
Ended
September 30,
   2014  2013
Cash Flow From Operating Activities:          
Net loss  $(2,724)  $(1,129)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:          
Deferred income tax expense   12    —  
Depreciation, depletion, amortization and impairment   2,409    2,091 
Amortization of debt issuance costs   223    510 
Accretion of discount on asset retirement obligation   34    67 
Dividend accrued for mandatorily redeemable preferred stock   (4)   149 
Change in commodity derivatives   (273)   382 
Change in working capital:          
Accounts receivable – oil and natural gas sales   414   883 
Accounts receivable – other   881    1,254 
Prepaid expenses and other assets   (6)   687 
Accounts payable   411    (4,733)
Accrued expenses   561    (543)
   Net cash provided by (used in) operating activities   1,938    (382)
Cash Flow From Investing Activities:          
Additions to oil and natural gas properties   (2,561)   (1,494)
Additions to other property and equipment   (23)   (71)
Settlement of asset retirement obligations   (36)   —   
   Net cash used in investing activities   (2,620)   (1,565)
Cash Flow From Financing Activities:          
Proceeds from issuance of common stock, net of issuance costs   —      3,605 
Proceeds from issuance of preferred stock, net of issuance costs   —      7,095 
Payments on line of credit   —      (5,000)
Payments on notes payable   —      (500)
   Net cash provided by financing activities   —      5,200 
Net change in cash and equivalents   (682)   3,253 
Cash at beginning of period   1,682    456 
Cash at end of period  $1,000   $3,709 
Supplemental Disclosure of Cash Flow Information:          
Cash paid during the period for interest  $446   $536 
Non-Cash Transactions:          
Change in asset retirement obligation estimate  $5   $22 
Issuance of warrants with preferred stock  $—     $2,395 

 

 

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

 

 

3
 

Red Mountain Resources, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

(in thousands)

 

   Common Stock           
   Shares  Amount  Additional Paid-in Capital  Accumulated Deficit  Noncontrolling Interest  Total
Balance at June 30, 2014   14,857   $1.487   $78,105   $(34,322)  $6,076   $49,860 
Net income (loss)   —      —      —      (2,892)   168    (2,724)
Balance at September 30, 2014   14,857   $1.487   $78,105   $(37,214)  $6,244   $47,136 

 

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

 

4
 

 

Red Mountain Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

1.  Organization

 

Red Mountain Resources, Inc. is a Texas corporation formed on January 23, 2014. On January 31, 2014, the Company changed its state of incorporation from the State of Florida to the State of Texas by merging Red Mountain Resources, Inc., a Florida corporation (“RMR FL”), with and into Red Mountain Resources, Inc., a Texas corporation. RMR FL was formed in January 2010 and acquired Black Rock Capital, LLC in a reverse merger effective July 1, 2011. Unless the context otherwise requires, the terms “Red Mountain” and “Company” refer to Red Mountain Resources, Inc. and its consolidated subsidiaries.

 

The Company is a Dallas-based growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, the Company has established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Additionally, the Company has an established and growing acreage position in Kansas.

 

Reverse stock split

 

On January 31, 2014, RMR FL effected a reverse stock split of RMR FL’s common stock, par value $0.00001 per share (“RMR FL Common Stock”), at an exchange ratio of 1-for-10 (the “Reverse Stock Split”), together with a proportional reduction in the number of authorized shares of RMR FL Common Stock from 500.0 million shares to 50.0 million shares. The par value of RMR FL Common Stock did not change as a result of the Reverse Stock Split. As of January 31, 2014, every ten shares of RMR FL Common Stock were combined into one share of RMR FL Common Stock, reducing the number of outstanding shares of RMR FL Common Stock from approximately 134.0 million to approximately 13.4 million. In addition, a proportionate adjustment was made to the per share exercise price and the number of shares issuable upon the exercise of all outstanding warrants to purchase shares of RMR FL Common Stock. All share and per share amounts and calculations have been retroactively adjusted to reflect the effects of the Reverse Stock Split.

 

2. Going Concern

These consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that the Company will be able to realize its assets and discharge its obligations in the normal course of operations for the foreseeable future.

The Company incurred a net loss of $2.9 million during the three months ended September 30, 2014. At September 30, 2014, the outstanding principal amount of the Company’s debt was $31.7 million, net of an aggregate discount of $1.5 million, and the Company had a working capital deficit of $31.9 million. Of the outstanding debt, $26.8 million is outstanding under the Company’s Credit Facility (as defined below). Of the $31.9 million working capital deficit at September 30, 2014, $26.8 million relates to the reclassification of the full amount of the outstanding borrowings under the Company's Credit Facility from a long-term liability to a short-term liability on its Consolidated Balance Sheets as of September 30, 2014. The Company is currently in default under the Credit Facility, and the lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the borrowers. The Company is in discussions with the lender regarding either a waiver of the non-compliance or an amendment to the credit agreement to cure the non-compliance. While the Company anticipates obtaining a waiver from the lender, it cannot provide any assurance that these negotiations will be successful. The Company is exploring available financing options, including the sale of debt or equity. If the Company is unable to finance its operations on acceptable terms or at all, its business, financial condition and results of operations may be materially and adversely affected. As a result of recurring losses from operations and a working capital deficiency, there is substantial doubt regarding the Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amount and classification of liabilities that may result from the possible inability of the Company to continue as a going concern. 

3.  Significant Accounting Policies

 

Basis of Presentation

 

The condensed consolidated financial statements include the accounts of Red Mountain Resources, Inc. and its subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States (“GAAP”).

 

The Company has prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of the Company at September 30, 2014 and June 30, 2014 and its results of operations and cash flows for the periods presented. The Company has omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although the Company believes that the disclosures it has made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with the Company’s audited consolidated financial statements and related footnotes included in its most recent Annual Report on Form 10-K.

 

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results the Company expects for the full fiscal year. The Company has not made any changes in its significant accounting policies from those disclosed in its most recent Annual Report on Form 10-K.

 

5
 

Noncontrolling Interests

 

Subsequent to January 28, 2013, the Company accounts for the noncontrolling interest in Cross Border Resources, Inc. (“Cross Border”) in accordance with ASC Topic 810, Consolidation (“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. In addition, this guidance provides for increases and decreases in the Company’s controlling financial interests in consolidated subsidiaries to be reported in equity similar to treasury stock transactions.

 

Debentures - Held to Maturity

 

The Company’s investments in non-performing debentures were initially recorded at cost which the Company believes was fair value. Management estimated cash flows expected to be collected considering the contractual terms of the loans, the nature and estimated fair value of collateral, and other factors it deemed appropriate. The estimated fair value of the loans at acquisition was significantly less than the contractual amounts due under the terms of the loan agreements.

 

Since, at the acquisition date, the Company expected to collect less than the contractual amounts due under the terms of the loans based, at least in part, on the assessment of the credit quality of the borrower, the loans are accounted for in accordance with ASC Topic 310-30, Loans and Debt Securities Acquired with Deteriorated Credit Quality (“ASC 310-30”). The difference between the contractually required payments on the loans as of the acquisition date and the total cash flows expected to be collected, or non-accretable difference, is not recognized and totaled $2.1 million and $2.1 million, plus accrued interest in arrears as of September 30, 2014 and June 30, 2014, respectively.

 

Debentures are classified as non-accrual when management is unable to reasonably estimate the timing or amount of cash flows expected to be collected from the debentures or has serious doubts about further collectability of principal or interest. As of September 30, 2014 and June 30, 2014, all of the Company’s debentures were on non-accrual status since the borrower remains under the supervision of the bankruptcy court.

6
 

 

The Company periodically re-evaluates cash flows expected to be collected for each debenture based upon all available information as of the measurement date. Subsequent increases in cash flows expected to be collected are recognized prospectively through an adjustment to the debenture’s yield over its remaining life, which may result in a reclassification from non-accretable difference to accretable yield. Subsequent decreases in cash flows expected to be collected are evaluated to determine whether a provision for loan loss should be established. If decreases in expected cash flows result in a decrease in the estimated fair value of the debenture below its amortized cost, the debenture is deemed to be impaired and the Company will record a provision for impairment to write the debenture down to its estimated fair value. The Company did not record an impairment during the three months ended September 30, 2014.

 

The Company’s investments in non-performing debentures are classified as held to maturity because the Company has the intent and ability to hold them until maturity.

 

Recent Accounting Pronouncements

 

In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), which requires management to evaluate, at each annual and interim reporting period, whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued and provide related disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter, and early adoption is permitted. The Company is currently in the process of evaluating the impact the adoption of ASU 2014-15 will have on the Company’s consolidated financial statements. 

 

4.  Oil and Natural Gas Properties and Other Property and Equipment

 

Oil and Natural Gas Properties

 

The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:

 

   September 30,  June 30,
   2014  2014
(in thousands)      
Oil and natural gas properties:          
Proved  $85,146   $82,362 
Unproved   19,043    19,109 
   Total oil and natural gas properties   104,189    101,471 
Less accumulated depletion and impairment   (21,456)   (19,138)
   Net oil and natural gas properties capitalized costs  $82,733   $82,333 

 

 

At September 30, 2014 and June 30, 2014, the capitalized costs of the Company’s oil and natural gas properties included (i) $38.8 million and $39.0 million, respectively, relating to acquisition costs of proved properties which are being amortized by the unit-of-production method using total proved reserves and (ii) $45.8 million and $39.6 million, respectively, relating to exploratory well costs and additional development costs which are being amortized by the unit-of-production method using proved developed reserves.

 

During the three months ended September 30, 2014 and 2013, the Company incurred $0.5 million and $0 million in exploratory drilling costs. The Company transferred $30,000 and $0 of exploratory well costs to proved properties during the three months ended September 30, 2014 and 2013, respectively.

 

The Company recorded an impairment of approximately $36,000 related to its unproved oil and natural gas properties during the three months ended September 30, 2014.

 

Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between the carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs and discount rates. The Company did not record any impairment charges on its proved properties for the three months ended September 30, 2014 and 2013.

 

7
 

 

Other Property and Equipment

 

The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation and amortization is summarized as follows: 

 

   September 30,  June 30,
   2014  2014
(in thousands)      
Other property and equipment  $1,139   $1,196 
Less accumulated depreciation and amortization   (521)   (359)
   Net property and equipment  $618   $837 

 

5.  Asset Retirement Obligations

 

The following table summarizes the changes in the Company’s asset retirement obligations (“AROs”) for the periods indicated:

 

   Three Months Ended
September 30,
  Fiscal Year Ended
June 30,
   2014  2014
(in thousands)      
Asset retirement obligations at beginning of period  $5,745   $5,020 
Liabilities incurred   5    75 
Liabilities settled   (36)   (2)
Accretion expense   34    267 
Revisions in estimated liabilities   —      385 
Asset retirement obligations at end of period   5,748    5,745 
Less:  current portion   178    214 
Long-term portion  $5,570   $5,531 

 

During the three months ended September 30, 2013, the Company recorded an upward revision to previous estimates for its ARO primarily due to changes in the estimated future cash outlays.

 

6.   Derivatives

 

At September 30, 2014, the Company had the following commodity derivatives positions outstanding:

 

Commodity and Time Period  Contract
 Type
  Volume Transacted  Contract Price
Crude Oil           
October 1, 2014―November 30, 2014  Swap  2,000 Bbls/month  $93.50/Bbl
October 1, 2014―December 31, 2014  Put  1,979-8,330 Bbls/month   $95.00 - $100.00/Bbl
October 1, 2014―January 31, 2015  Put  6,000 Bbls/month  $95.00/Bbl

 

 

 

8
 

 

The following table summarizes the fair value of the Company’s open commodity derivatives as of September 30, 2014 and June 30, 2014:

 

   Balance Sheet Location   Fair Values 
       September 30,    June 30, 
       2014    2014 
(in thousands)             
Derivatives not designated as hedging instruments             
Commodity derivatives  Commodities derivative asset  $189   $37 
             
Commodity derivatives  Commodities derivative liability  $—     $(121)

 

The following table summarizes the change in the fair value of the Company’s commodity derivatives:

 

   Income Statement Location  Three Months Ended
September 30,
      2014  2013
(in thousands)         
Derivatives not designated as hedging instruments         
Commodity derivatives  Gain (loss) on commodity derivatives  $269   $(384)

 

 

Unrealized gains and losses, at fair value, are included on the Company’s Consolidated Balance Sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of the Company’s commodity derivatives contracts are recorded in earnings as they occur and included in other income (expense) on the Company’s Consolidated Statements of Operations. The Company estimates the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. The Company internally valued the option contracts using industry-standard option pricing models and observable market inputs. The Company uses its internal valuations to determine the fair values of the contracts that are reflected on its Consolidated Balance Sheets. Realized gains and losses are also included in other income (expense) on its Consolidated Statements of Operations.

 

The Company is exposed to credit losses in the event of nonperformance by the counterparties on its commodity derivatives positions and has considered the exposure in its internal valuations. However, the Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

 

In connection with the closing of the Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (collectively with the Company, the “Borrowers”) and Independent Bank, as Lender (the “Lender”), the Company was required to enter into hedging agreements effectively hedging at least 50% of the oil volumes of the Company and its subsidiaries. At the same time, the Company entered into a Novation Agreement with BP Energy Company that transferred Cross Border’s then-existing swap agreements to the Company. Pursuant to an Inter-Borrower Agreement among the Borrowers, the Company allocates these swap agreements back to Cross Border and may allocate future hedging agreements related to Cross Border’s production to Cross Border. See ‘Note 8. Debt-Credit Facility.”

 

7.  Fair Value Measurements

 

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

 

Level 1 - quoted prices for identical assets or liabilities in active markets.

   
Level 2 - quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
   
Level 3 - unobservable inputs for the asset or liability.
   
9
 

 

 

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

 

The following table summarizes the valuation of the Company’s financial assets and liabilities at September 30, 2014 and June 30, 2014:

 

   Fair Value Measurements at Reporting Date Using
   Quoted Prices in
Active Markets for
Identical Assets or
Liabilities (Level 1)
  Significant or
Other Observable
Inputs (Level 2)
  Significant
Unobservable
Inputs (Level 3)
  Fair Value at
September 30, 2014
(in thousands)            
Assets:                    
Commodity derivatives  $—     $189   $—     $189 
Oil and gas properties impairment (non-recurring)   —      —      (36)   (36)
Total  $—     $189   $(36)  $153 
                     
Liabilities:                    
Asset retirement obligations (non-recurring)  $—     $—     $(5,748)  $(5,748)
Environmental remediation liability   —      —      (2,057)   (2,057)
Total  $—     $—     $(7,805)  $(7,805)

 

 

   Fair Value Measurements at Reporting Date Using
   Quoted Prices in
Active Markets for
Identical Assets or
Liabilities (Level 1)
  Significant or
Other Observable
Inputs (Level 2)
  Significant
Unobservable
Inputs (Level 3)
  Fair Value at
June 30, 2014
(in thousands)            
Assets:                    
Commodity derivatives  $—     $37   $—     $37 
Oil and gas properties impairment (non-recurring)   —      —      (487)   (487)
Total  $—     $37   $(487)  $(450)
                     
Liabilities:                    
Asset retirement obligations (non-recurring)  $—     $—     $(5,745)  $(5,745)
Commodities derivative liability   —      (121)   —      (121)
Environmental remediation liability   —      —      (2,067)   (2,067)
Total  $—     $(121)  $(7,812)  $(7,933)

 

The following is a summary of changes to fair value measurements using Level 3 inputs during the quarter ended September 30, 2014: 

(in thousands)  Environmental
Liability
      
Balance, June 30, 2014  $(2,067)
Settlement of liabilities   10 
Balance, September 30, 2014  $(2,057)

 

10
 

 

8.  Debt

 

As of the dates indicated, the Company’s debt consisted of the following:

 

   September 30,  June 30,
   2014  2014
(in thousands)      
Credit Facility  $26,800   $26,800 
Mandatorily redeemable preferred stock and accrued dividends, net of discount of $1,464 and $1,561, respectively   4,898    4,801 
Total debt   31,698    31,601 
Less:  short-term portion   26,800    —   
Long-term debt  $4,898   $31,601 

 

Credit Facility

 

On February 5, 2013, the Company entered into the Credit Agreement with the Borrowers and Lender. The Credit Agreement provides for an up to $100.0 million revolving credit facility (as amended, the “Credit Facility”) with a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of September 30, 2014, the borrowing base was $30.0 million.

 

A portion of the Credit Facility, in an aggregate amount not to exceed $2.0 million, may be used to issue letters of credit for the account of Borrowers. The Borrowers may be required to prepay the Credit Facility in the event of a borrowing base deficiency as a result of over-advances, sales of oil and gas properties or terminations of hedging transactions.

 

Amounts outstanding under the Credit Facility bear interest at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (4.0% at September 30, 2014). Interest is payable monthly in arrears on the last day of each calendar month. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.

 

Under the Credit Agreement, the Borrowers are required to pay fees consisting of (i) an unused facility fee equal to 0.5% multiplied by the average daily unused commitment amount, payable quarterly in arrears until the commitment is terminated; (ii) a fronting fee payable on the date of issuance of each letter of credit and annually thereafter or on the date of any increase or extension thereof, equal to the greater of (a) 2.0% per annum multiplied by the face amount of such letter of credit or (b) $1,000; and (iii) an origination fee (x) of $200,000, and (y) payable on any date the commitment is increased, an additional facility fee equal to 1.0% multiplied by any increase of the commitment above the highest previously determined or redetermined commitment.

 

The Credit Agreement contains negative covenants that may limit the Borrowers’ ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. The Credit Agreement permits the payment of cash dividends on the Company’s 10.0% Series A Convertible Redeemable Preferred Stock (the “Series A Preferred Stock”) so long as the Company is not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause the Company to be in default under the Credit Agreement.

 

11
 

The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain, requiring the Borrowers to maintain a ratio of (i) the Borrowers’ and their consolidated subsidiaries’ consolidated current assets (inclusive of the unfunded commitment amount under the Credit Agreement) to consolidated current liabilities (exclusive of the current portion of long-term debt under the Credit Agreement) of at least 1.00 to 1.00; (ii) the Borrowers’ and their subsidiaries’ consolidated “Funded Debt” to consolidated EBITDAX (for the four fiscal quarter period then ended) of less than 3.50 to 1.00; and (iii) the Borrowers’ and their subsidiaries’ consolidated EBITDAX less paid and accrued dividends on the Series A Preferred Stock to interest expenses (each for the four fiscal quarter period then ended) of at least 3.00 to 1.00. Funded Debt is defined in the Credit Agreement as the sum of all debt for borrowed money, whether as a direct or reimbursement obligor, but excludes shares of Series A Preferred Stock. EBITDAX is defined in the Credit Agreement as (a) consolidated net income plus (b) (i) interest expense, (ii) income taxes, (iii) depreciation, (iv) depletion and amortization expenses, (v) dry hole and exploration expenses, (vi) non-cash losses or charges on any hedge agreements resulting from derivative accounting, (vii) extraordinary or non-recurring losses, (viii) expenses that could be capitalized under GAAP but by election of Borrowers are being expensed for such period under GAAP, (ix) costs associated with intangible drilling costs, (x) other non-cash charges, (xi) one-time expenses associated with transactions associated with (b)(i) through (iv), minus (c)(i) non-cash income on any hedge agreements resulting from FASB Statement 133, (ii) extraordinary or non-recurring income, and (iii) other non-cash income.

 

Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, failure to perform or observe covenants under the Credit Facility, a material inaccuracy of a representation or warranty, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.

 

Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Red Mountain has outstanding hedge agreements with various counterparties hedging a portion of the future oil production of the Borrowers. However, these hedge agreements did not comply with the volume and time period requirements of the Credit Agreement as of September 30, 2014.

 

As of September 30, 2014, the Borrowers had collectively borrowed $26.8 million and had availability of $3.2 million under the Credit Facility. On October 14, 2014, the Company borrowed an additional $1.0 million under the Credit Facility. The Company was not in compliance with all of the financial covenants and the hedge agreement covenant under the Credit Facility described above at September 30, 2014, which constitutes an event of default under the Credit Facility, and the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. As a result, the Company has recorded the full amount of its outstanding borrowings under the Credit Facility as a current liability on its Consolidated Balance Sheet as of September 30, 2014. 

 

Mandatorily Redeemable Preferred Stock

 

The Company’s Series A Preferred Stock is mandatorily redeemable and is not convertible into shares of the Company’s common stock. The Company classifies the Series A Preferred Stock as a long-term liability, and the Company records dividends paid or accrued as interest expense in the Company’s Condensed Consolidated Statement of Operations.

 

In August 2013, the Company closed offerings of 376,685 Units, raising net cash proceeds of $7.1 million. Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 2.5 shares of common stock at a price of $22.50 per Unit. The warrants are exercisable until the earlier of (i) August 2016 or (ii) the first trading day that is at least 30 days after the date that the Company has provided notice to the holders of the warrants by filing a Current Report on Form 8-K stating that the common stock has (A) achieved a 20 trading day volume weighted average price of $15.00 per share or more and (B) traded, in the aggregate, 300,000 shares or more over the same 20 consecutive trading days for which the 20 trading day volume weighted average price was calculated; provided, that clause (ii) shall only be applicable so long as a warrant is exercisable for shares of common stock. The warrants have an exercise price of $10.00 per share. The warrants issued with the Series A Preferred Stock were valued at $2.4 million. The value of the warrants is treated as a discount to the Series A Preferred Stock and will be accreted over the life of the mandatorily redeemable preferred stock. Management determined the fair value using a probability weighted Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The volatility and remaining term was approximately 55% and three years, respectively.

 

12
 

 

The Series A Preferred Stock is mandatorily redeemable on July 15, 2018 at $25.00 per share, plus accrued and unpaid dividends to the redemption date, for a total redeemable value of $11.9 million at the time of issuance. The difference between the $11.9 million redeemable value and the $10.8 million of gross proceeds and canceled debt is treated as a discount and will be accreted over the life of the Series A Preferred Stock. Effective as of April 1, 2014, the Company agreed to exchange 222,224 outstanding shares of its Series A Preferred Stock for the issuance of 1,388,898 shares of common stock. After the exchange, the Company had 254,463 shares of Series A Preferred Stock outstanding with an aggregate redemption amount of $6.4 million as of September 30, 2014.

 

For the three months ended September 30, 2014, the Company recognized total interest expense of $0.3 million related to the Series A Preferred Stock, which includes accretion of discount and issuance cost of $0.1 million for the three months ended September 30, 2014.

 

Schedule of Future Debt Payments

 

The following is a schedule by fiscal year of future principal payments required under the Company’s outstanding debt as of September 30, 2014:

 

(in thousands)    
Fiscal Years Ending June 30,    
2015 $26,800 
2016  —  
2017  —  
2018  —  
2019  6,362 
Total  33,162 
Discount  (1,464)
Total,  net value $31,698 

   

13
 

 

9.  Earnings Per Share

 

The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of basic and diluted earnings per share:

 

  

Three Months Ended

September 30,

   2014  2013
(dollars in thousands, except per share amounts)      
Net loss (numerator):          
Net loss – basic  $(2,892)  $(1,129)
Weighted average shares (denominator):          
Weighted average shares – basic   14,857    12,922 
Dilution effect of share-based compensation, treasury method(1)   —      —   
Weighted average shares – diluted   14,857    12,922 
Loss per share:          
Basic  $(0.19)  $(0.10)
Diluted  $(0.19)  $(0.10)

 


 

(1)

Approximately 1,349,051 and 1,653,559 shares of common stock underlying warrants to purchase shares of the Company’s common stock were excluded from this calculation because they were anti-dilutive during the periods ended September 30, 2014 and 2013, respectively.

  

10.  Commitments and Contingencies

 

Litigation

 

On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of Cross Border, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by Cross Border. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral West Corp, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and Cross Border deny that Mr. Bloodworth’s claims have any merit.

 

Cross Border was previously party to an engagement letter, dated February 7, 2012 (the “Engagement Letter”) with KeyBanc Capital Markets Inc. (“KeyBanc”) pursuant to which KeyBanc was to act as exclusive financial advisor to Cross Border’s board of directors in connection with a possible “Transaction” (as defined in the Engagement Letter). The Engagement Letter was formally terminated by Cross Border on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to Cross Border representing a fee and out-of-pocket expenses purportedly owed by Cross Border to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period. Cross Border disputed that any Transaction was consummated and that KeyBanc was entitled to any fees or out-of-pocket expenses. Cross Border filed a complaint seeking (i) a declaration that it was not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. On August 26, 2014, Cross Border entered into a settlement agreement with KeyBanc, settling a lawsuit between the parties. In connection with the settlement, Cross Border agreed to pay KeyBanc $900,000 in three equal installments of $300,000 each on or before August 28, 2014, October 31, 2014 and December 31, 2014, and the parties agreed to mutual releases of liability related to the Engagement Letter. The Company fully accrued this amount at June 30, 2014. The Company paid the first installment and the remaining installments are recorded in accrued expenses on the Company’s Consolidated Balance Sheets at September 30, 2014.

 

14
 

 

In addition to the foregoing, in the ordinary course of business, the Company is periodically a party to various litigation matters that it does not believe will have a material adverse effect on its results of operations or financial condition.

 

Environmental Issues

 

The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in all oil and natural gas operations, and the Company could be subject to environmental cleanup and enforcement actions. The Company manages this environmental risk through appropriate environmental policies and practices to minimize the impact to the Company.

 

As of September 30, 2014, the Company had approximately $2.1 million in environmental remediation liabilities related to Cross Border’s operated Tom Tom and Tomahawk fields located in Chaves and Roosevelt counties in New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted Cross Border’s remediation plan for the Tom Tom and Tomahawk fields. Cross Border is working in conjunction with the BLM to initiate remediation on a site-by-site basis. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. Inherent uncertainties exist in these estimates due to unknown conditions, changing governmental regulation, and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration. Cross Border has incurred approximately $43,000 in costs and expects to incur the remaining expenditures during the Company’s fiscal year ending June 30, 2015.

 

Leases

 

As of September 30, 2014, the Company rented various office spaces in Dallas, Texas; Midland, Texas; and Lafayette, Louisiana under non-cancelable lease agreements. In the aggregate, these leases cover approximately 16,884 square feet at a cost of approximately $24,000 per month and have remaining lease terms ranging from 2 months to 24 months. The following is a schedule by year of future minimum rental payments required under these lease arrangements as of September 30, 2014:

 

(in thousands)   
Fiscal Years Ending June 30,   
2015  $147 
2016   181 
2017   45 
2018   —   
Total  $373 

 

Rent expense under the Company’s lease arrangements amounted to approximately $74,000 and $69,000 for the three months ended September 30, 2014 and 2013, respectively.

 

 11.  Related Party Transactions

 

Enerstar Resources O&G, LLC (“Enerstar”), a company owned by Tommy Folsom, the former Executive Vice President and Director of Exploration and Production for RMR Operating, LLC, a subsidiary of the Company, and formerly the Executive Vice President and Director of Exploration and Production for the Company, owns an overriding royalty interest in the Company’s Madera Prospect. During the three months ended September 30, 2014 and 2013, the Company paid royalties of approximately $7,000 and $3,000, respectively, to Enerstar.

 

15
 

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Unless the context otherwise requires, all references to “Red Mountain,” the “Company,” “we,” “our” and “us” refer to (i) Red Mountain Resources, Inc., (ii) Red Mountain’s wholly owned subsidiaries, including Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”), and (iii) subsequent to January 28, 2013, Cross Border Resources, Inc. (“Cross Border”). As of September 30, 2014, we owned 83% of the outstanding common stock of Cross Border. Acreage, reserves and production information presented subsequent to January 28, 2013 includes acreage, reserves and production represented by the 17% of Cross Border’s common stock not owned by us.

 

Overview

 

We are a Dallas-based growth-oriented energy company engaged in the acquisition, development and exploration of oil and natural gas properties in established basins with demonstrable prolific producing zones. Currently, we have established acreage positions and production in the Permian Basin of West Texas and Southeast New Mexico and the onshore Gulf Coast of Texas. Additionally, we have an established and growing acreage position in Kansas.

 

We plan to grow production and reserves by acquiring, exploring and developing an inventory of long-life, low risk drilling opportunities with attractive rates of return. Our focus is on opportunities in and around producing oil and natural gas properties where we can enhance production and reserves through application of newer drilling and completion techniques, infill drilling targeting untapped but known productive hydrocarbon strata, and enhanced oil recovery applications.

 

As of November 17, 2014, we owned interests in 887,501 gross (310,392 net) mineral and lease acres in New Mexico, Texas and Kansas, of which 336,331 gross (30,926 net) acres are within the Permian Basin. We have successfully leased 9,868 net acres in Kansas located on the Central Kansas Uplift, and we also owned interests in over 1,405 net acres located on the Villarreal, Frost Bank, Resendez, Peal Ranch and La Duquesa Prospects in the Gulf Coast of Texas.

 

As of September 30, 2014, we had $26.8 million of borrowings under our Senior First Lien Secured Credit Agreement (as amended, the “Credit Agreement”) with Cross Border, Black Rock and RMR Operating (collectively with the Company, the “Borrowers”) and Independent Bank, as Lender (the “Lender”), which provides for an up to $100.0 million revolving credit facility (as amended, the “Credit Facility”). This indebtedness is secured by substantially all of our assets and the assets of our subsidiaries. The Credit Agreement contains covenants which require us to maintain compliance with certain financial ratios, aging of accounts payable and maintenance of agreements that hedge the price of oil. As of September 30, 2014, we were not in compliance with certain of these covenants and, as a result, the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. Due to the noncompliance, we have (i) reclassified the full amount of the outstanding borrowings under the Credit Facility from a long-term liability to a short-term liability on our Consolidated Balance Sheets as of September 30, 2014 and (ii) included a “going concern” note in our consolidated financial statements. We are in discussions with the Lender regarding either a waiver of the non-compliance or an amendment to the Credit Agreement to cure the non-compliance. While we anticipate obtaining a waiver from the Lender, we cannot provide any assurance that these negotiations will be successful.

 

16
 

 

Fiscal 2015 First Quarter Operational Update

 

Net production sold for the quarter ended September 30, 2014 was 100,000 barrels of oil equivalent (“Boe”), or 1,087 Boe per day (“Boe/d”), based on actual calendar days during the period, inclusive of 9.6 Mboe, or 105 Boe/d, of prior period adjustments.

 

During the three months ended September 30, 2014, we completed two wells (0.2 net) at our Turkey Track Prospect, worked over three wells (2.8 net) in the Tom Tom Area, and drilled five gross (five net) wells in Kansas. We recently commenced the completion of the Madera 25 Federal 2H well.

 

During the quarter, we completed the Zircon 2 B1EH State 2H well, our first well targeting the 1st Bone Spring reservoir at our Turkey Track Prospect. It was completed in July 2014 and achieved a maximum 24-hour production rate of 632 Boe/d (of which 87% was oil) and a 10-day average production rate of 549 Boe/d (of which 81% was oil). We own an approximately 13% working interest and 9% net revenue interest in this well. The Bradley 31 B2DA Federal Com 1H well, a horizontal well targeting the 2nd Bone Spring, was completed in September 2014 and achieved a maximum 24-hour production rate of 889 Boe/d (of which 88% was oil) and a 10-day average production rate of 790 Boe/d (of which 88% was oil). We own an approximately 7% working interest and 5% net revenue interest in this well. In October 2014, we spud the Perla Verde 31 State 2H, a horizontal well targeting the 3rd Bone Spring, in which we own an approximately 6.3% working interest and 4.7% net revenue interest. In November 2014, we spud the Scooter Federal Com 1H and the Zircon 12/7 B2JK Federal Com 1H horizontal wells targeting the 2nd Bone Spring, in which we own an approximately 0.8% working interest and 0.6% net revenue interest and an approximately 16% working interest and 12% net revenue interest, respectively. All three of these wells are non-operated wells and are currently drilling.

 

In the Tom Tom Area, we continued our workover program completing work on three wells in the field during the three months ended September 30, 2014. In the first of these, on the Strange Federal 1 well, we added perforations, treated the well with acid, and fracture stimulated the well, increasing its production from less than 1 Bbl/d of oil to approximately 6 Bbl/d oil. We own a 100% working interest and an approximately 75% net revenue interest in the well. We also completed work on the Wattam Federal 4 and Hahn Federal 7 wells during the first quarter, adding new perforations to the Hahn Federal 7 well and treating both wells with acid. We are awaiting flowback results on both of these workovers. We own a 100% working interest and 77% net revenue interest in the Wattam Federal 4 well, and an approximately 78% working interest and 64% net revenue interest in the Hahn Federal 7 well. In October 2014, we commenced work on the Loveless LQ State 2 well, a well in the Tom Tom Area in which we own an approximately 65% working interest and 57% net revenue interest. We added new perforations, treated the well with acid, and are currently awaiting flowback results.

 

During the quarter, we also drilled five wells in Rush County, Kansas, targeting the Arbuckle, Basal Penn, Reagan, and Lansing-Kansas City formations. Three of these wells, the Besperat 1, Koriel 1, and Elder 1 wells, did not encounter commercial hydrocarbons and were plugged and abandoned. The Stalcup 1 well was completed in the Arbuckle formation in September 2014 and is currently producing. The well has averaged approximately 8 Bbl/d of oil since its completion. As of September 30, 2014, the Gisick 1 well was drilled and awaiting completion. We own a 100% working interest and a net revenue interest ranging from 83% to 88% in these five wells.

 

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations is based upon our condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The preparation of these condensed consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures. Our significant accounting policies are described in “Note 2—Significant Accounting Policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014.

 

17
 

 

Results of Operations

 

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the three months ended September 30, 2014 and 2013.

 

   Three Months Ended 
   September 30, 2014   September 30, 2013 
(dollars in thousands, except per unit prices)              
Revenue          
Oil and natural gas sales  $5,272   $5,774 
           
Net Production sold          
Oil (Bbl)   48,896    43,649 
Natural gas (Mcf)   224,146    241,017 
Natural gas liquids (Bbl)   13,728    6,293 
Total (Boe)   99,982    90,112 
Total (Boe/d) (1)   1,087    979 
           
Average sales prices          
Oil ($/Bbl)  $83.61   $102.46 
Natural gas ($/Mcf)   3.17    4.52 
Natural gas liquids ($/Bbl)   32.17    28.57 
Total average price ($/Boe)  $52.41   $63.72 
           
Costs and expenses (per Boe)          
Exploration expense  $2.50   $1.12 
Dry hole expense   5.33     
Production taxes   4.19    6.72 
Lease operating expenses   11.56    8.29 
Natural gas transportation and marketing expenses   0.98    0.42 
Depreciation, depletion, amortization and impairment   24.09    23.20 
Accretion of discount on asset retirement obligation   0.34    0.75 
General and administrative expense   26.89    21.57 

 

 

(1) Boe/d is calculated based on actual calendar days during the period.

 

Revenues and Production

 

Oil and Natural Gas Production. During the three months ended September 30, 2014, we had net production sold of 99,982 Boe, compared to net production sold of 90,112 Boe during the three months ended September 30, 2013. The increase in net production sold was primarily attributable to production from new wells and from prior period adjustments, partially offset by the natural decline of producing properties. For the three months ended September 30, 2014, 48.9% of our production was oil, 37.4% was natural gas and 13.7% was natural gas liquids, compared to 48.4% oil, 44.6% natural gas and 7.0% natural gas liquids for the three months ended September 30, 2013.

 

18
 

 

Oil and Natural Gas Sales. During the three months ended September 30, 2014, we had oil and natural gas sales of $5.3 million, as compared to $5.8 million during the three months ended September 30, 2013. The decrease in oil and natural gas sales was primarily attributable to the decrease in commodity prices.

 

Costs and Expenses

 

Exploration Expense. Exploration expense was $0.3 million for the three months ended September 30, 2014, as compared to $0.1 million for the three months ended September 30, 2013. The increase in exploration expense was primarily attributable to increased seismic activity during the three months ended September 30, 2014.

 

Dry Hole Expense. Dry hole expense was $0.5 million for the three months ended September 30, 2014, as compared to $0 million for the three months ended September 30, 2013. The increase in dry hole expense was primarily attributable to three Kansas wells that did not encounter commercial hydrocarbons and were plugged and abandoned.

 

Production Taxes. Production taxes were $0.4 million for the three months ended September 30, 2014, as compared to $0.6 million for the three months ended September 30, 2013.

 

Lease Operating Expenses. During the three months ended September 30, 2014, we incurred lease operating expenses of $1.2 million, as compared to $0.7 million during the three months ended September 30, 2013. The increase in lease operating expenses was attributable to new wells and workover expense that was not incurred in the prior year.

 

Natural Gas Transportation and Marketing Expenses. For the three months ended September 30, 2014, natural gas transportation and marketing expenses was $98,000, as compared to $38,000 for the three months ended September 30, 2013.

 

Depreciation, Depletion, Amortization and Impairment. For the three months ended September 30, 2014, depreciation, depletion, amortization and impairment was $2.4 million, as compared to $2.1 million for the three months ended September 30, 2013. The increase in depreciation, depletion, amortization and impairment was attributable to additional wells in our Madera field.

 

General and Administrative Expense. General and administrative expense was $2.7 million for the three months ended September 30, 2014, as compared to $1.9 million for the three months ended September 30, 2013. The increase in general and administrative expense was due primarily to approximately $1.0 million of non-recurring expenses related to our cancelled preferred stock offering in September 2014 and increased professional fees associated with our internal control improvements.

 

Other Expense. Other expense was $0.4 million for the three months ended September 30, 2014, as compared to other expense of $1.3 million for the three months ended September 30, 2013. The decrease in other expense was primarily attributable to a decrease in interest expense and an increased cash and non-cash gains from commodity derivatives contracts.

 

Liquidity and Capital Resources

 

General

 

Our primary sources of liquidity for the first quarter of fiscal 2015 were borrowings under our Credit Facility and our cash flow from operations. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under the Credit Facility, and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control and have recently declined.

 

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Capital Expenditures

 

Most of our capital expenditures are for the exploration, development, production and acquisition of oil and natural gas reserves. We anticipate cash capital expenditures of between $15 million and $20 million for the remainder of fiscal year 2015. We currently do not have access to sufficient funds for our planned exploration or development activities for the next twelve months and will need additional capital to continue our operations beyond March 31, 2015, or sooner if the Lender accelerates the repayment of our obligations under the Credit Facility. We are currently seeking funding for our 2015 capital development program.

 

Liquidity

 

At September 30, 2014, we had $1.0 million in cash and cash equivalents, $26.8 million of total indebtedness under the Credit Facility and $4.9 million of our 10.0% Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”), net of a discount of $1.5 million. At September 30, 2014, we had a working capital deficit of $31.9 million compared to a working capital deficit of $1.1 million at September 30, 2013. Of the $31.9 million working capital deficit at September 30, 2014, $26.8 million relates to the reclassification of the full amount of the outstanding borrowings under the Credit Facility from a long-term liability to a short-term liability on our Consolidated Balance Sheets as of September 30, 2014.

 

We are currently in default under the Credit Facility, and the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. We are in discussions with the Lender regarding either a waiver of the non-compliance or an amendment to the Credit Agreement to cure the non-compliance. While we anticipate obtaining a waiver from the Lender, we cannot provide any assurance that these negotiations will be successful.

 

Cash Flows

 

Net cash provided by operating activities was $1.9 million for the three months ended September 30, 2014, compared to net cash used in operating activities of $0.4 million for the three months ended September 30, 2013. The increase in net cash provided by operating activities was primarily due to an increase in net loss of $1.6 million, offset by an increase in depletion, depreciation, amortization, and impairment of approximately $0.3 million, an increase in income from commodities derivatives of approximately $0.7 million and beneficial changes in working capital items.

 

 Net cash used in investing activities increased to $2.6 million for the three months ended September 30, 2014 from $1.6 million for the three months ended September 30, 2013 due to an increase in expenditures for drilling activity.

 

 Net cash provided by financing activities was $0 for the three months ended September 30, 2014, as compared to $5.2 million for the three months ended September 30, 2013. Net cash provided by financing activities for the three months ended September 30, 2013 was primarily comprised of $10.7 million of net proceeds from the sale of shares of common stock and Series A Preferred Stock. These amounts were partially offset by $5.5 million of payments on the Credit Facility and convertible notes payable.

 

Indebtedness

 

Credit Facility. The Credit Agreement provides for the Credit Facility, which has a maturity date of February 5, 2016. The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of September 30, 2014, the borrowing base was $30.0 million.

 

A portion of the Credit Facility, in an aggregate amount not to exceed $2.0 million, may be used to issue letters of credit for the account of Borrowers. The Borrowers may be required to prepay the Credit Facility in the event of a borrowing base deficiency as a result of over-advances, sales of oil and gas properties or terminations of hedging transactions.

 

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Amounts outstanding under the Credit Facility will bear interest at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0%. Interest is payable monthly in arrears on the last day of each calendar month. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.

 

Under the Credit Agreement, the Borrowers are required to pay fees consisting of (i) an unused facility fee equal to 0.5% multiplied by the average daily unused commitment amount, payable quarterly in arrears until the commitment is terminated; (ii) a fronting fee payable on the date of issuance of each letter of credit and annually thereafter or on the date of any increase or extension thereof, equal to the greater of (a) 2.0% per annum multiplied by the face amount of such letter of credit or (b) $1,000; and (iii) an origination fee (x) of $200,000, and (y) payable on any date the commitment is increased, an additional facility fee equal to 1.0% multiplied by any increase of the commitment above the highest previously determined or redetermined commitment.

 

The Credit Agreement contains negative covenants that may limit the Borrowers’ ability to, among other things, incur liens, incur additional indebtedness, enter into mergers, sell assets, make investments and pay dividends. The Credit Agreement permits the payment of cash dividends on our Series A Preferred Stock so long as we are not otherwise in default under the Credit Agreement and payment of such cash dividends would not cause us to be in default under the Credit Agreement.

 

The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of Red Mountain, requiring the Borrowers to maintain a ratio of (i) the Borrowers’ and their consolidated subsidiaries’ consolidated current assets (inclusive of the unfunded commitment amount under the Credit Agreement) to consolidated current liabilities (exclusive of the current portion of long-term debt under the Credit Agreement) of at least 1.00 to 1.00; (ii) the Borrowers’ and their subsidiaries’ consolidated “Funded Debt” to consolidated EBITDAX (for the four fiscal quarter period then ended) of less than 3.50 to 1.00; and (iii) the Borrowers’ and their subsidiaries’ consolidated EBITDAX less paid and accrued dividends on the Series A Preferred Stock to interest expenses (each for the four fiscal quarter period then ended) of at least 3.00 to 1.00. Funded Debt is defined in the Credit Agreement as the sum of all debt for borrowed money, whether as a direct or reimbursement obligor, but excludes shares of Series A Preferred Stock. EBITDAX is defined in the Credit Agreement as (a) consolidated net income plus (b) (i) interest expense, (ii) income taxes, (iii) depreciation, (iv) depletion and amortization expenses, (v) dry hole and exploration expenses, (vi) non-cash losses or charges on any hedge agreements resulting from derivative accounting, (vii) extraordinary or non-recurring losses, (viii) expenses that could be capitalized under GAAP but by election of Borrowers are being expensed for such period under GAAP, (ix) costs associated with intangible drilling costs, (x) other non-cash charges, (xi) one-time expenses associated with transactions associated with (b)(i) through (iv), minus (c)(i) non-cash income on any hedge agreements resulting from FASB Statement 133, (ii) extraordinary or non-recurring income, and (iii) other non-cash income.

 

Amounts outstanding under the Credit Facility may be accelerated and become immediately due and payable upon specified events of default of Borrowers, including, among other things, a default in the payment of principal, interest or other amounts due under the Credit Facility, certain loan documents or hydrocarbon hedge agreements, failure to perform or observe covenants under the Credit Facility, a material inaccuracy of a representation or warranty, a default with regard to certain loan documents which remains unremedied for a period of 30 days following notice, a default in the payment of other indebtedness of the Borrowers of $200,000 or more, bankruptcy or insolvency, certain changes in control, failure of the Lender’s security interest in any portion of the collateral with a value greater than $500,000, cessation of any security document to be in full force and effect, or Alan Barksdale ceasing to be Red Mountain’s Chief Executive Officer or Chairman of Cross Border and not being replaced with an officer acceptable to the Lender within 30 days.

 

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Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Red Mountain has outstanding hedge agreements with various counterparties hedging a portion of the future oil production of the Borrowers. However, these hedge agreements did not comply with the volume and time period requirements of the Credit Agreement as of September 30, 2014.

 

As of September 30, 2014, the Borrowers had collectively borrowed $26.8 million and had availability of $3.2 million under the Credit Facility. On October 14, 2014, we borrowed an additional $1.0 million under the Credit Facility. We were not in compliance with all of the financial covenants and the hedge agreement covenant under the Credit Facility described above at September 30, 2014, which constitutes an event of default under the Credit Facility, and the Lender has the right to accelerate all amounts outstanding under the Credit Facility upon notice to the Borrowers. As a result, we have recorded the full amount of the outstanding borrowings under the Credit Facility as a current liability on our Consolidated Balance Sheets as of September 30, 2014.

 

Series A Preferred Stock. As of September 30, 2014, we had 254,463 shares of Series A Preferred Stock outstanding. The Series A Preferred Stock is mandatorily redeemable and is not convertible into shares of our common stock. We classify the Series A Preferred Stock as a long-term liability, and we record dividends paid or accrued as interest expense in our condensed consolidated statements of operations.

 

In August 2013, we closed offerings of 376,685 Units (the “Units”). Each Unit consisted of one share of Series A Preferred Stock and one warrant to purchase up to 2.5 shares of common stock. The warrants are exercisable until the earlier of (i) August 2016 or (ii) the first trading day that is at least 30 days after the date that we have provided notice to the holders of the warrants by filing a Current Report on Form 8-K stating that the common stock has (A) achieved a 20 trading day volume weighted average price of $15.00 per share or more and (B) traded, in the aggregate, 300,000 shares or more over the same 20 consecutive trading days for which the 20 trading day volume weighted average price was calculated; provided, that clause (ii) shall only be applicable so long as a warrant is exercisable for shares of common stock. The warrants have an exercise price of $10.00 per share. The warrants issued with the Series A Preferred Stock were valued at $2.4 million. The value of the warrants is treated as a discount to the Series A Preferred Stock and will be accreted over the life of the mandatorily redeemable preferred stock. Management determined the fair value using a probability weighted Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of our common stock on the OTCBB on the date of issuance. The volatility and remaining term was approximately 55% and three years, respectively.

 

The Series A Preferred Stock is mandatorily redeemable on July 15, 2018 at $25.00 per share, plus accrued and unpaid dividends to the redemption date, for a total redeemable value of $6.4 million.

 

For the three months ended September 30, 2014, we recognized total interest expense of $0.3 million related to the Series A Preferred Stock, which includes accretion of discount of $0.1 million.

 

Contractual Obligations

 

The following table presents our contractual obligations at September 30, 2014 (in thousands):

 

   Payments Due by Period
   Total  Less than
1 Year
  1 – 3 Years  3 – 5 Years  More than
5 Years
Line of credit  $26,800   $26,800   $—     $—     $—   
Series A Preferred Stock   8,986    700    1,924    6,362    —   
Environmental remediation liability   2,057    2,057    —      —      —   
Asset retirement obligations   5,748    178    2,394    157    3,019 
Lease obligations   373    192    181    —      —   
Total  $43,964   $29,927   $4,499   $6,519   $3,019 

 

Off-Balance Sheet Arrangements

 

Since June 30, 2014, there have been no material changes to our off-balance sheet arrangements as reported in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014.

 

Forward-Looking Statements

 

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” “understand,” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.

 

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Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:

 

  our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;

 

  declines or volatility in the prices we receive for our oil and natural gas;

 

  general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

 

  risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

 

  uncertainties associated with estimates of proved oil and natural gas reserves;

 

  the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

 

  risks and liabilities associated with acquired companies and properties;

 

  risks related to integration of acquired companies and properties;

 

  potential defects in title to our properties;

 

  cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;

 

  geological concentration of our reserves;

 

  environmental or other governmental regulations, including legislation of hydraulic fracture stimulation;

 

  our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

 

  exploration and development risks;

 

  management’s ability to execute our plans to meet our goals;

 

  our ability to retain key members of our management team;

 

  weather conditions;

 

  actions or inactions of third-party operators of our properties;

 

  costs and liabilities associated with environmental, health and safety laws;

 

23
 

 

  our ability to find and retain highly skilled personnel;

 

  operating hazards attendant to the oil and natural gas business;

 

  competition in the oil and natural gas industry; and

 

  the other factors discussed under Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014.

 

 Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk

 

Our major market risk exposure is the price we receive for our oil and natural gas production. Realized pricing is primarily driven by the prevailing price for oil and spot market prices for natural gas. Prices for oil and natural gas production are volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions.

 

Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. We have entered into derivative contracts, including costless collars, swaps, and puts, which hedge the price of oil for a portion of our expected production through January 2015.

 

The derivative contracts economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. While the use of the hedging arrangements will limit the downside risk of adverse price movements, it may also limit future gains from favorable movements.

 

The costless collars provide us with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price we will receive for the hedged volumes while the ceiling price represents the highest price we will receive for the hedged volumes. The costless collars are settled monthly.

 

The swaps provide us with a fixed settlement price for our hedged volumes. The swaps are settled monthly.

 

The puts provide a fixed floor price on a notional amount of sales volumes while allowing full price appreciation if the relevant index price closes above the floor price.

 

We have elected not to designate our derivative financial instruments as hedges for accounting purposes, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur. Our commodity derivative contracts are carried at their fair value in earnings as they occur. We recognize unrealized and realized gains and losses related to these contracts on a mark-to-market basis in our condensed consolidated statements of operations under the caption “Gain (loss) on commodity derivatives”. Each derivative contract is evaluated separately to determine its own fair value. During the three months ended September 30, 2014, we recorded a gain on commodity derivative contracts of $0.3 million.

 

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The following table summarizes our outstanding derivatives contracts with respect to future oil production as of September 30, 2014:

 

Commodity and Time Period   Contract Type   Volume Transacted   Contract Price
Crude Oil            
October 1, 2014―November 30, 2014   Swap   2,000 Bbls/month   $93.50/Bbl
October 1, 2014―December 31, 2014   Put   1,979-8,330 Bbls/month   $95.00 - $100.00/Bbl
October 1, 2014―January 31, 2015   Put   6,000 Bbls/month   $95.00/Bbl

 

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2014 and June 30, 2014, a 10% increase in underlying commodity prices would neither reduce nor increase the fair value of these derivatives by a material amount.

 

Interest Rate Risk

 

The Credit Facility exposes us to interest risk associated with interest rate fluctuations on outstanding borrowings. At each of September 30, 2014 and June 30, 2014, we had $26.8 million in outstanding borrowings under the Credit Facility. We incur interest on borrowings under the Credit Facility at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (which interest rate was 4.0% at September 30, 2014 and June 30, 2014). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of each of September 30, 2014 and June 30, 2014 would result in an increase or decrease in our interest costs of approximately $107,000 per year.

 

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

 

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2014 and, based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

 

Changes in Internal Control Over Financial Reporting

 

There have been no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

 

There have been no material changes to the pending legal proceedings discussed in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014.

 

Item 1A. Risk Factors

 

There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the fiscal year ended June 30, 2014, except as follows:

 

We were not in compliance with our covenants under our Credit Agreement as of September 30, 2014. As a result, the Lender may exercise one or more of its remedies, including the right to accelerate the repayment of all outstanding borrowings.

 

As of September 30, 2014, we had $26.8 million of borrowings under our Credit Facility. This indebtedness is secured by substantially all of our assets and the assets of our subsidiaries. The Credit Agreement contains covenants which require us to maintain compliance with certain financial ratios, aging of accounts payable and agreements that hedge the price of oil. As of September 30, 2014, we were not in compliance with certain of these covenants and, as a result, the Lender can declare an event of default under the Credit Agreement. In the event of an event of default, the Lender has the right to accelerate repayment of all outstanding indebtedness and take actions to collect monies owed to it, including enforcing and foreclosing on its security interest on our assets and the assets of our subsidiaries. In addition, the Lender can restrict our access to additional borrowings under the Credit Facility. As of the date hereof, the Lender has not accelerated our repayment obligations or taken any of the other actions described above.

 

We are in discussions with the Lender regarding either a waiver of the non-compliance or an amendment to the Credit Agreement to cure the non-compliance. However, we cannot provide any assurance that these negotiations will be successful. Even if we successfully obtain a waiver or an amendment that cures the non-compliance, we can provide no assurance that we will not violate our covenants in the future.

 

If the Lender were to accelerate our repayment obligation under the Credit Facility, our assets may not be sufficient to fully repay the debt and we may not be able to obtain capital from other sources at favorable terms or at all. If additional funding is required, this funding may not be available on favorable terms, if at all, or without potentially very substantial dilution to our stockholders. If we do not raise the necessary funds, we may need to curtail or cease our operations, sell certain assets and/or file for bankruptcy, which would have a material adverse effect on our financial condition and results of operations.

 

While the Lender has not accelerated the repayment of our obligations under the Credit Facility, its ability to do so has caused all of our outstanding indebtedness under the Credit Facility to be classified as a current liability on our consolidated balance sheets at September 30, 2014.

 

We currently do not have sufficient funds to continue our exploration and development activities beyond March 31, 2015, or sooner if the Lender accelerates the repayment of our obligations under the Credit Facility.

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make significant capital expenditures in our business for the exploration, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures.

 

We plan to spend between $15 million and $20 million during the remainder of fiscal 2015 to drill and complete wells or re-enter and complete wells. However, as of September 30, 2014, we had a working capital deficit of $31.9 million. We currently do not have sufficient funds to continue our exploration and development activities beyond March 31, 2015, or sooner if the Lender accelerates our obligations under the Credit Agreement. If we are unable to finance our operations on acceptable terms or at all, we may be forced to curtail or suspend our planned exploration and development activities and our business, financial condition and results of operations may be materially and adversely affected.

 

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Our cash flows from operations and access to capital are subject to a number of variables, including:

 

  the value of our proved reserves;
     
  the level of oil and natural gas we are able to produce from existing wells;
     
  the prices at which our oil and natural gas are sold;
     
  our ability to acquire, locate and produce new reserves; and
     
  the ability of our banks to lend.

 

Debt financing could lead to:

 

  a substantial portion of operating cash flow being dedicated to the payment of principal and interest;
     
  us being more vulnerable to competitive pressures and economic downturns; and
     
  restrictions on our operations, including our ability to pay dividends.

 

If sufficient capital resources are not available, we might be forced to cease operations entirely, curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

None.

 

Item 3. Defaults Upon Senior Securities

 

None.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

Item 5. Other Information

 

None.

 

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Item 6. Exhibits

 

3.1 Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
3.2 Certificate of Correction to the Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 11, 2014).
   
3.3 Bylaws of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.1 Form of Common Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.2 Form of 10.0% Series A Cumulative Redeemable Preferred Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.3 Form of Warrant Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.4 Form of Warrant Agreement between the Company and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 8-A filed on July 24, 2013).
   
4.5 Amendment No. 1 to Warrant Agreement, effective as of January 31, 2014, between Broadridge Corporate Issuer Solutions, Inc. and Red Mountain Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
31.1* Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
31.2* Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
32.1** Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
   
101.INS* XBRL Instance Document
   
101.SCH* XBRL Taxonomy Extension Schema Document
   
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
   
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

 

 
* Filed herewith.
** Furnished herewith.

 

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Signatures

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

  RED MOUNTAIN RESOURCES, INC.
     
  By: /s/ Alan W. Barksdale
    Alan W. Barksdale
    Chief Executive Officer
     
  By: /s/ Hilda D. Kouvelis
    Hilda D. Kouvelis
    Chief Accounting Officer
     
  Date: November 17, 2014

 

29
 

 

INDEX TO EXHIBITS

 

3.1 Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
3.2 Certificate of Correction to the Certificate of Formation of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 11, 2014).
   
3.3 Bylaws of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.1 Form of Common Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.2 Form of 10.0% Series A Cumulative Redeemable Preferred Stock Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.3 Form of Warrant Certificate of Red Mountain Resources, Inc. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
4.4 Form of Warrant Agreement between the Company and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 8-A filed on July 24, 2013).
   
4.5 Amendment No. 1 to Warrant Agreement, effective as of January 31, 2014, between Broadridge Corporate Issuer Solutions, Inc. and Red Mountain Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 4, 2014).
   
31.1* Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
31.2* Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
32.1** Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
   
101.INS* XBRL Instance Document
   
101.SCH* XBRL Taxonomy Extension Schema Document
   
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
   
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

 

 
* Filed herewith.
** Furnished herewith.

 

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