UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
x | QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2015
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ___________ to ______________.
Commission File Number 001-35241
SARATOGA RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Texas |
| 76-0314489 |
(State or other jurisdiction of incorporation or organization) |
| (IRS Employer Identification No.) |
9225 Katy Freeway, Suite 100, Houston, Texas 77024 |
(Address of principal executive offices)(Zip Code) |
(713) 458-1560 |
(Registrant's telephone number, including area code) |
|
(Former name, former address and former fiscal year, if changed since last report) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
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 definition 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 ¨ | Smaller reporting company x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨
As of May 14, 2015, we had 30,986,601 shares of $0.001 par value Common Stock outstanding.
SARATOGA RESOURCES, INC.
FORM 10-Q
INDEX
|
| Page No. |
PART I FINANCIAL INFORMATION | 3 | |
|
|
|
3 | ||
| Consolidated Balance Sheets as of March 31, 2015 and December 31,2014 | 3 |
| 4 | |
| Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014 | 5 |
| 6 | |
ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of Operations | 16 | |
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk | 23 | |
24 | ||
|
|
|
PART II OTHER INFORMATION | 25 | |
|
|
|
25 |
2
PART I - FINANCIAL INFORMATION
ITEM 1
Financial Statements
SARATOGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| March 31, |
| December 31, | ||
| 2015 |
| 2014 | ||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
Cash and cash equivalents | $ | 5,708,152 |
| $ | 10,911,070 |
Accounts receivable |
| 2,969,669 |
|
| 3,778,808 |
Prepaid expenses and other |
| 1,121,825 |
|
| 1,006,758 |
Other current asset |
| 1,874,910 |
|
| 150,000 |
Total current assets |
| 11,674,556 |
|
| 15,846,636 |
|
|
|
|
|
|
Property and equipment: |
|
|
|
|
|
Oil and gas properties - proved (successful efforts method) |
| 301,561,285 |
|
| 301,399,079 |
Other |
| 1,031,779 |
|
| 1,031,779 |
|
| 302,593,064 |
|
| 302,430,858 |
Less: Accumulated depreciation, depletion and amortization |
| (229,464,795) |
|
| (226,716,401) |
Total property and equipment, net |
| 73,128,269 |
|
| 75,714,457 |
|
|
|
|
|
|
Other assets, net |
| 16,476,436 |
|
| 20,350,655 |
Total assets | $ | 101,279,261 |
| $ | 111,911,748 |
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT |
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
Accounts payable | $ | 2,851,235 |
| $ | 6,722,116 |
Revenue and severance tax payable |
| 2,095,401 |
|
| 2,711,229 |
Accrued liabilities |
| 17,358,778 |
|
| 13,006,617 |
Derivative liabilities short term |
| - |
|
| 117 |
Short-term notes payable |
| 614,155 |
|
| 329,964 |
First lien notes, net of unamortized discount of $63,956 and $151,169, respectively |
| 54,536,044 |
|
| 54,448,831 |
Second lien notes, net of unamortized discount of $358,746 and $847,947, respectively |
| 124,841,254 |
|
| 124,352,053 |
Total current liabilities |
| 202,296,867 |
|
| 201,570,927 |
|
|
|
|
|
|
Long-term liabilities: |
|
|
|
|
|
Asset retirement obligation |
| 16,939,106 |
|
| 16,397,804 |
Total long-term liabilities |
| 16,939,106 |
|
| 16,397,804 |
|
|
|
|
|
|
Commitment and contingencies (see notes) |
|
|
|
|
|
|
|
|
|
|
|
Stockholders' deficit: |
|
|
|
|
|
Common stock, $0.001 par value; 100,000,000 shares authorized 30,986,601 shares issued and outstanding at March 31, 2015 and December 31, 2014 |
| 30,987 |
|
| 30,987 |
Additional paid-in capital |
| 78,851,360 |
|
| 78,754,854 |
Retained deficit |
| (196,839,059) |
|
| (184,842,824) |
|
|
|
|
|
|
Total stockholders' deficit |
| (117,956,712) |
|
| (106,056,983) |
|
|
|
|
|
|
Total liabilities and stockholders' deficit | $ | 101,279,261 |
| $ | 111,911,748 |
The accompanying notes are an integral part of these unaudited consolidated financial statements
3
SARATOGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
(Unaudited)
| For the Three Months Ended | ||||
| March 31, | ||||
| 2015 |
| 2014 | ||
Revenues: |
|
|
|
|
|
Oil and gas revenues | $ | 6,330,462 |
| $ | 10,602,991 |
Oil and gas hedging |
| 117 |
|
| 1,061,123 |
Other revenues |
| 71,385 |
|
| 76,175 |
|
|
|
|
|
|
Total revenues |
| 6,401,964 |
|
| 11,740,289 |
|
|
|
|
|
|
Operating Expense: |
|
|
|
|
|
Lease operating expense |
| 4,008,007 |
|
| 5,492,815 |
Workover expense |
| 18,978 |
|
| 2,192,186 |
Exploration expense |
| 19,098 |
|
| 221,352 |
Depreciation, depletion and amortization |
| 2,748,394 |
|
| 2,742,059 |
Accretion expense |
| 595,562 |
|
| 448,466 |
General and administrative |
| 1,887,412 |
|
| 2,352,570 |
Severance taxes |
| 580,204 |
|
| 500,750 |
|
|
|
|
|
|
Total operating expenses |
| 9,857,655 |
|
| 13,950,198 |
|
|
|
|
|
|
Operating loss |
| (3,455,691) |
|
| (2,209,909) |
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
Interest income |
| 4 |
|
| 16,321 |
Interest expense |
| (8,515,048) |
|
| (6,013,533) |
|
|
|
|
|
|
Total other expense |
| (8,515,044) |
|
| (5,997,212) |
|
|
|
|
|
|
Net loss before income taxes |
| (11,970,735) |
|
| (8,207,121) |
|
|
|
|
|
|
Income tax expense |
| 25,500 |
|
| 82,066 |
|
|
|
|
|
|
Net loss | $ | (11,996,235) |
| $ | (8,289,187) |
|
|
|
|
|
|
Other Comprehensive income (loss) |
|
|
|
|
|
Unrealized gain on derivative instruments |
| - |
|
| 100,353 |
Total comprehensive loss | $ | (11,996,235) |
| $ | (8,188,834) |
|
|
|
|
|
|
Net loss per share: |
|
|
|
|
|
Basic | $ | (0.39) |
| $ | (0.27) |
Diluted | $ | (0.39) |
| $ | (0.27) |
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
Basic |
| 30,986,601 |
|
| 30,946,601 |
Diluted |
| 30,986,601 |
|
| 30,946,601 |
The accompanying notes are an integral part of these unaudited consolidated financial statements
4
SARATOGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| For the Three Months Ended | ||||
| March 31, | ||||
| 2015 |
| 2014 | ||
Cash flows from operating activities: |
|
|
|
|
|
Net loss | $ | (11,996,235) |
| $ | (8,289,187) |
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
Depreciation, depletion and amortization |
| 2,748,394 |
|
| 2,742,059 |
Accretion expense |
| 595,562 |
|
| 448,466 |
Amortization of debt issuance costs |
| 2,352,150 |
|
| 589,306 |
Amortization of debt discount |
| 576,414 |
|
| 143,127 |
Stock-based compensation |
| 96,506 |
|
| 6,029 |
Unrealized gain on hedges |
| (117) |
|
| (1,092,960) |
Changes in operating assets and liabilities: |
|
|
|
|
|
Accounts receivable |
| 809,139 |
|
| (439,237) |
Prepaids and other |
| 567,327 |
|
| 352,166 |
Accounts payable |
| (2,950,057) |
|
| 150,078 |
Revenue and severance tax payable |
| (615,828) |
|
| (13,349) |
Payments to settle asset retirement obligations |
| (54,260) |
|
| - |
Accrued liabilities |
| 4,352,161 |
|
| (4,118,957) |
Net cash used in operating activities |
| (3,518,844) |
|
| (9,522,459) |
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
Additions to oil and gas property |
| (1,083,030) |
|
| (2,293,169) |
Additions to other property and equipment |
| - |
|
| (7,727) |
Other assets |
| (202,841) |
|
| (13,559) |
Net cash used in investing activities |
| (1,285,871) |
|
| (2,314,455) |
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
Repayment of short-term notes payable |
| (398,203) |
|
| (338,512) |
Net cash used in financing activities |
| (398,203) |
|
| (338,512) |
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
| (5,202,918) |
|
| (12,175,426) |
Cash and cash equivalents - beginning of period |
| 10,911,070 |
|
| 32,547,380 |
Cash and cash equivalents - end of period | $ | 5,708,152 |
| $ | 20,371,954 |
|
|
|
|
|
|
Supplemental disclosures of cash flow information: |
|
|
|
|
|
Cash paid for income taxes | $ | - |
| $ | 49,566 |
Cash paid for interest |
| 1,385,287 |
|
| 9,190,000 |
|
|
|
|
|
|
Non-cash investing and financing activities: |
|
|
|
|
|
Unrealized gain on derivative instruments | $ | - |
| $ | 100,353 |
Accounts payable for oil and gas additions |
| - |
|
| (941,459) |
Accrued liabilities for oil and gas additions |
| - |
|
| (46,768) |
Prepaid insurance financed with debt |
| 682,394 |
|
| - |
The accompanying notes are an integral part of these unaudited consolidated financial statements
5
SARATOGA RESOURCES, INC.
Notes to Consolidated Financial Statements
March 31, 2015
(Unaudited)
NOTE 1 ORGANIZATION AND BASIS OF PRESENTATION
Organization
Saratoga Resources, Inc. (Saratoga or the Company) is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of natural gas and crude oil properties.
Financial Statements Presented
The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q. They do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for a complete financial presentation. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation, have been included in the accompanying unaudited financial statements. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
The Company utilizes the successful efforts method of accounting for oil and gas producing activities.
These financial statements should be read in conjunction with the financial statements and footnotes which are included as part of the Companys Form 10-K for the year ended December 31, 2014.
Reclassifications of Prior Period Statements
Certain reclassifications of prior period consolidated financial statement balances have been made to conform to current reporting practices.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and any marketable securities. The Company had cash deposits of approximately $5,458,152 million in excess of FDIC insured limits at the period end. The Company has not experienced any losses on its deposits of cash and cash equivalents.
Going Concern
The accompanying consolidated financial statements have been prepared in conformity with accounting principles accepted in the United States of America which contemplate the continuation of the Company as a going concern. During the three months ended March 31, 2015, the Company incurred a loss from operations of $3,455,691, had negative cash flow from operations of $3,518,844, and has a working capital deficit of $190,622,311 at March 31, 2015. These conditions raise substantial doubt as to the Companys ability to continue as a going concern. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
To address these matters, the Company is seeking to restructure its debt, or find alternative sources of financing. There can be no assurance that the Company will be successful in its efforts.
NOTE 2 OIL AND GAS PROPERTIES
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
During three months ended March 31, 2015 and 2014, we did not recognize any impairment expense.
6
NOTE 3 DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objective and Strategies for Using Commodity Derivative Instruments
The Company periodically enters into commodity derivative instruments, primarily fixed price swaps, to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The fixed price swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price. The amount payable by us, if the floating price is above the fixed price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed price with respect to each calculation period. The amount payable by the counterparty, if the floating price is below the fixed price, is the product of the notional quantity per calculation period and the excess of the fixed price over the floating price with respect to each calculation period. We receive proceeds for the sale of crude oil call options which carry a strike price. The call option, when combined with the Companys long production position, represents a covered call and creates a ceiling, at the strike price, on the price to be received during the covered period for the related production.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.
See Note 4 Fair Value Measurements for a discussion of the methods and assumptions used to estimate the fair values of our commodity derivative instruments.
The Company utilizes hedge accounting for our commodity derivative instruments, which are designated as cash flow hedges.
Counterparty Credit Risk
Commodity derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments were with one counterparty at December 31, 2014. We monitor and manage our level of financial exposure with respect to the counterparties we use. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.
As of March 31, 2015, the Company had no hedge contracts outstanding.
The following table presents the fair value of the Companys commodity derivative instruments at March 31, 2015 and December 31, 2014:
|
|
| March 31, |
| December 31, | |
Description |
|
| 2015 |
| 2014 | |
Current liabilities: |
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 117 |
|
| $ | - |
| $ | 117 |
The following tables present the effect of commodity derivative instruments on our consolidated statements of operations and comprehensive loss for the three months ended March 31, 2015 and 2014:
|
| For the Three months Ended March 31, | ||||
Description |
| 2015 |
| 2014 | ||
Unrealized mark-to-market gain |
| $ | - |
| $ | 1,092,960 |
Realized gain (loss) on settlements |
|
| 117 |
|
| (31,837) |
Total gain (loss) on commodity derivative instruments |
| $ | 117 |
| $ | 1,061,123 |
7
|
| For the Three months Ended March 31, | ||||
Description |
| 2015 |
| 2014 | ||
Unrealized mark-to-market gain (loss) in other comprehensive income |
| $ | - |
| $ | 100,353 |
Total other comprehensive income |
| $ | - |
| $ | 100,353 |
NOTE 4 FAIR VALUE MEASUREMENTS
The Company has various financial instruments that are measured at fair value in the financial statements, including commodity derivatives. The Companys financial assets and liabilities are measured using input from three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level 1 Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 Inputs include quoted prices for similar assets and 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 assets or liability and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means (market corroborated inputs).
Level 3 Unobservable inputs that reflect the Companys judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, using internal and external data.
The Company had no assets or liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of March 31, 2015.
The following table presents the Companys assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of December 31, 2014:
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 117 |
| $ | - |
| $ | 117 |
|
| $ | - |
| $ | 117 |
| $ | - |
| $ | 117 |
The Company uses various commodity derivative instruments, including fixed price swaps. We consider the fair value of our commodity derivative instruments to be level 2 on the fair value hierarchy. The fair value of commodity derivatives is determined using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data.
NOTE 5 OTHER ASSETS
Other assets consist of the following:
| March 31, |
| December 31, | ||
| 2015 |
| 2014 | ||
Site specific trust accounts - P&A escrow | $ | 5,564,129 |
| $ | 5,564,129 |
Debt issuance cost, net |
| - |
|
| 4,077,060 |
Restricted cash P&A bond |
| 10,628,903 |
|
| 10,628,903 |
Other |
| 283,404 |
|
| 80,563 |
| $ | 16,476,436 |
| $ | 20,350,655 |
Site Specific Trust Accounts P&A Escrow
The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties in certain fields. Changes in the escrow accounts reflect additional contributions and interest earned during 2015. See Note 9 Asset Retirement Obligations.
8
Debt Issuance Costs, Net
The Company capitalizes certain debt issuance costs and amortizes those costs as additional interest expense over the lives of the associated debt. Net debt issuance costs at March 31, 2015 and December 31, 2014 reflect the issuance of the 12½% Second Lien Notes in December 2012 and July 2011 and the issuance of the 10% First Lien Notes in November 2013. See Note 10 Debt.
Restricted Cash P&A Bond
Restricted Cash P&A Bond consists of cash collateral held in escrow to assure maintenance and administration of performance bonds which secures certain plugging and abandonment obligations imposed by state law. The cash collateral is reflected as a long term asset to correspond with the expected timing of the related asset retirement obligation liability. See Note 9 Asset Retirement Obligations.
NOTE 6 STOCK-BASED COMPENSATION EXPENSE
The Company periodically grants restricted stock and stock options to employees, directors and consultants. The Company is required to make estimates of the fair value of the related instruments and recognize expense over the period benefited, usually the vesting period.
Compensation Plan
In September 2011, the Companys board of directors adopted, and in June 2012 the Companys stockholders approved, the Saratoga Resources, Inc. 2011 Omnibus Equity Plan (the 2011 Plan). The 2011 Plan reserves a total of 3,000,000 shares for issuance to eligible employees, officers, directors and other service providers pursuant to grants of options, restricted stock, performance stock and other equity based compensation agreements.
Stock Option Activity
In February 2015, the Companys board of directors approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to an executive officer. The options are exercisable for a term of seven years at $0.21 per share and vest 1/3 after six months and 1/3 on each of the first two grant date anniversaries. The grant date value of the options was $3,900. The options were valued using the Black-Scholes model with the following assumptions: 84% volatility; 4.1 year estimated life; zero dividends; 1.28% discount rate; and, quoted stock price and exercise price of $0.21.
In February 2015, the Companys management approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at $0.21 per share and vest 1/3 after six months and 1/3 on each of the first two grant date anniversaries. The grant date value of the options was $3,900. The options were valued using the Black-Scholes model with the following assumptions: 84% volatility; 4.1 year estimated life; zero dividends; 1.28% discount rate; and, quoted stock price and exercise price of $0.21.
In February 2015, the Companys management approved a stock option grant to purchase an aggregate of 15,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at $0.27 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $2,700. The options were valued using the Black-Scholes model with the following assumptions: 86% volatility; 4.5 year estimated life; zero dividends; 1.57% discount rate; and, quoted stock price and exercise price of $0.27.
9
The following table summarizes information about stock option activity and related information for the three months ended March 31, 2015:
(1)
The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. On March 31, 2015, the last reported sales price of our common stock on the NYSE MKT was $0.20 per share.
Share-Based Compensation Expense
The following table reflects share-based compensation recorded by the Company for the three months ended March 31, 2015 and 2014:
| Three Months Ended March 31, | ||||
| 2014 |
| 2014 | ||
Share-based compensation expense included in reported net income | $ | 96,506 |
| $ | 6,029 |
Basic earnings per share effect of share-based compensation expense | $ | - |
| $ | - |
As of March 31, 2015, total unrecognized stock-based compensation expense related to non-vested stock options was $0.2 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.5 years.
NOTE 7 EQUITY
Common Stock Activity
There was no common stock activity during the three months ended March 31, 2015.
Warrant Activity
The following table summarizes information about stock warrant activity and related information for the three months ended March 31, 2015:
| Number of Shares Underlying Warrants |
| Weighted Average Exercise Price per Share |
| Weighted Average Grant Date Fair Value per Share |
| Weighted Average Remaining Contractual Life (in Years) |
| Aggregate Intrinsic Value (1) | ||||
Outstanding at December 31, 2014 |
| 146,998 |
| $ | 6.64 |
| $ | 5.33 |
| 0.4 |
| $ | - |
Granted |
| - |
|
| - |
|
| - |
| - |
|
| - |
Exercised |
| - |
|
| - |
|
| - |
| - |
|
| - |
Forfeited |
| - |
|
| - |
|
| - |
| - |
|
| - |
Outstanding at March 31, 2015 |
| 146,998 |
| $ | 6.64 |
| $ | 5.33 |
| 0.1 |
| $ | - |
Exercisable at March 31, 2015 |
| 146,998 |
| $ | 6.64 |
| $ | 5.33 |
| 0.1 |
| $ | - |
(1)
The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On March 31, 2015, the last reported sales price of our common stock on the NYSE MKT was $0.20 per share.
10
NOTE 8 EARNINGS (LOSS) PER SHARE
A reconciliation of the components of basic and diluted net loss per common share is presented in the tables below:
| For the Three Months Ended March 31, | ||||||||||||||
| 2015 |
| 2014 | ||||||||||||
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share |
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share | ||||
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock | $ | (11,996,235) |
| 30,986,601 |
| $ | (0.39) |
| $ | (8,289,187) |
| 30,946,601 |
| $ | (0.27) |
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
| - |
|
|
|
|
|
|
| - |
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock, including assumed conversions | $ | (11,996,235) |
| 30,986,601 |
| $ | (0.39) |
| $ | (8,289,187) |
| 30,946,601 |
| $ | (0.27) |
NOTE 9 ASSET RETIREMENT OBLIGATIONS
The Company accounts for plugging and abandonment costs in accordance with FASB Accounting Standards Codification 410-20, Accounting for Asset Retirement Obligations.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations are as follows:
Balance at December 31, 2014 | $ | 16,397,804 |
Accretion expense |
| 595,562 |
Additions |
| - |
Revisions |
| - |
Settlements |
| (54,260) |
Balance at March 31, 2015 | $ | 16,939,106 |
NOTE 10 DEBT
Debt consists of the following:
|
| March 31, |
| December 31 | ||
|
| 2015 |
| 2014 | ||
10% First Lien Notes due 2015 |
| $ | 54,600,000 |
| $ | 54,600,000 |
12 ½% Second Lien Notes due 2016 |
|
| 125,200,000 |
|
| 125,200,000 |
Less unamortized discount |
|
| (422,702) |
|
| (999,116) |
|
| $ | 179,377,298 |
| $ | 178,800,884 |
10.0% First Lien Notes
In November 2013, the Company, and its wholly-owned subsidiaries (the Guarantors), issued $54.6 million in aggregate principal amount of 10.0% Senior Secured Notes due 2015 (the First Lien Notes) to two institutional accredited investors (the Purchasers).
The First Lien Notes were issued pursuant to Purchase Agreements (the Purchase Agreement), and under an Indenture (the First Lien Indenture), by and among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the First Lien Trustee). The First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed (the Guarantees) on a senior secured basis by the Guarantors and will rank equally in right of payment with our, and the Guarantors, existing and future senior indebtedness and senior in right of payment to Second Lien Notes (as defined below).
The purchase price for the First Lien Notes and Guarantees was 100% of their principal amount. We received net proceeds from the issuance and sale of the First Lien Notes of approximately $25.4 million, after commissions and estimated offering expenses, and the surrender for retirement by the Purchasers of $27.3 million in face amount of 12½% Senior Secured Notes (the Second Lien Notes).
11
The First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the First Lien Notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.
The First Lien Indenture includes customary events of default and places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Companys common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The Company has the option to redeem all or a portion of the First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to offer to purchase the First Lien Notes at a price equal to 101% of the aggregate principal amount of First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the First Lien Notes at a price equal to 100% of the principal amount of First Lien Notes repurchased plus accrued and unpaid interest.
In connection with the issuance and sale of the First Lien Notes, the Company, the First Lien Trustee and The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral under the Second Lien Documents (as defined below)(the Second Lien Trustee) entered into an Intercreditor Agreement (the Intercreditor Agreement). Pursuant to the Intercreditor Agreement, parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Notes and Guarantees (the First Lien Obligations) shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under that certain Indenture dated as of June 12, 2011, as supplemented or amended from time to time thereafter (the Second Lien Indenture), by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related Second Lien Notes in the aggregate amount of $125.2 million (the Second Lien Obligations).
Interest accrued and owing as of December 31, 2014, in the amount of $1,365,000, was not paid as of the due date. Such interest was subsequently paid in connection with a Forbearance Agreement to First Lien Indenture (see below). Interest accrued and owing as of March 31, 2015, in the amount of $1,365,000, has not been paid and, as a result, the First Lien Notes are in default and are included as a current liability in the accompany consolidated financial statements.
12½% Second Lien Notes
In July 2011, the Company and the Guarantors entered into a Purchase Agreement with Imperial Capital, LLC (the Initial Purchaser), relating to the issuance and sale of $127.5 million in aggregate principal amount of 12½% Senior Secured Notes due 2016. The Second Lien Notes were sold at 98.221% of par in a transaction exempt from the registration requirements of the Securities Act and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
In December 2012, the Company and the Guarantors entered into another Purchase Agreement with the Initial Purchaser, relating to the issuance and sale of an additional $25 million in aggregate principal amount of the Second Lien Notes. The Second Lien Notes were sold at 98.58% of par in a transaction exempt from the registration requirements of the Securities Act and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
The Second Lien Notes were issued pursuant to the Second Lien Indenture among the Company, the Guarantors named therein and Second Lien Trustee, as trustee and collateral agent and, with respect to the Second Lien Notes issued in 2012, a First Supplemental Indenture, dated December 4, 2012. The Second Lien Notes are the senior secured obligations of the Company and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with the Companys and the Guarantors existing and future senior indebtedness, subject, however, to the Intercreditor Agreement pursuant to which the First Lien Notes are senior in right, priority, operation and effect to the lien securing the Second Lien Notes.
The Second Lien Notes mature on July 1, 2016, and interest is payable on January 1 and July 1 of each year.
The Second Lien Indenture includes customary events of default and places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Companys common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
12
The Company has the option to redeem all or a portion of the Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture plus accrued and unpaid interest.
Interest accrued and owing as of January 1, 2015, in the amount of $7,825,000, has not been paid and, as a result, the Second Lien Notes are in default and are included as a current liability in the accompanying consolidated financial statements. The Company and the principal holders of the Second Lien Notes entered into a Forbearance Agreement to Second Lien Debenture in January 2015. See below.
Forbearance Agreements
On January 30, 2015, the Company, along with its subsidiaries, Lobo Operating, Inc., Lobo Resources, Inc., Harvest Oil & Gas, LLC and The Harvest Group, LLC entered into a forbearance agreement (the First Lien Forbearance Agreement) with the holders (the First Lien Lenders) of certain notes (the First Lien Notes) issued under that certain Indenture dated as of November 22, 2013 (the First Lien Indenture), by and among the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the First Lien Trustee). Also on January 30, 2015, the Company entered into a forbearance agreement (the Second Lien Forbearance Agreement and, together with the First Lien Forbearance Agreement, the Forbearance Agreements) with the holders (the Second Lien Lenders) of seventy-five percent (75%) or more in principal amount of the notes (the Second Lien Notes) issued under that certain Indenture dated as of July 12, 2011 (as supplemented or amended, the Second Lien Indenture), by and among the Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the Second Lien Trustee).
The Forbearance Agreements were entered into following (i) the Companys failure to pay to the First Lien Lenders an interest installment in the amount of $1.3 million scheduled for payment on December 31, 2014, and constituting a default if not paid by January 30, 2015 (the Anticipated First Lien Default), and (ii) the Companys failure to pay to the Second Lien Lenders an interest installment in the amount of $7.9 million scheduled for payment on January 1, 2015, and constituting a default if not paid by February 2, 2015 (the Anticipated Second Lien Default, and, together with the Anticipated First Lien Default, the Specified Defaults).
The Company has received confirmation from the First Lien Lenders that they hold more than 75% of the principal amount of the outstanding Second Lien Notes and have each agreed, during the Forbearance Period (as defined below), not to provide any direction to the Second Lien Trustee or to take any steps to enforce any rights of the Second Lien Trustee or the holders of Second Lien Notes occasioned by the failure of the Company to make the January 1, 2015 interest payment.
Pursuant to the First Lien Forbearance Agreement, the First Lien Lenders agreed to forbear, until the earlier of March 16, 2015 or the occurrence of certain defaults defined in the First Lien Forbearance Agreement (the Forbearance Period), from exercising certain of their default-related rights and remedies against the Company with respect to the Specified Defaults in order to permit the Company an opportunity to effectuate a restructuring/refinancing or implement operational improvements.
Under the terms of the First Lien Forbearance Agreement, among other things, the Company agreed to (i) pay, by February 2, 2015, the December 31, 2014 interest payment owing to the First Lien Lenders, with interest at the default rate, in the amount of $1,378,650; (ii) pay expenses incurred by the First Lien Lenders in connection with the Forbearance Agreement, including paying a retainer to counsel for the First Lien Lenders; (iii) retain, by March 2, 2015, a financial advisor acceptable to the First Lien Lenders on terms acceptable to the First Lien Lenders; (iv) deliver to the First Lien Lenders a 6-week operating budget in form and methodology acceptable to the First Lien Lenders and to abide by that budget within permitted variances; (v) deliver to the First Lien Lenders, not later than March 2, 2015, certain financial, operating and other information and, not later than March 15, 2015, a two year business plan and 2015 budget; and (vi) cause its officers, financial advisors, investment bankers and others to furnish information reasonably requested by the First Lien Lenders.
Any breach by the Company of any covenant in the First Lien Forbearance Agreement, or the commencement of any bankruptcy, insolvency or creditor relief proceedings by or with respect to the Company, will constitute an event of default under the First Lien Forbearance Agreement.
Pursuant to the Second Lien Forbearance Agreement, the Second Lien Lenders agreed to forbear, during the Forbearance Period, from exercising certain of their default-related rights and remedies against the Company with respect to the Specified Defaults in order to permit the Company an opportunity to effectuate a restructuring/refinancing or implement operational improvements. Second Lien Forbearance Agreement is substantially identical to the First Lien Forbearance Agreement except that the January 1, 2015 interest payment on the First Lien Notes was not required to be made.
On March 16, 2015, the Company entered into amendments to the Forbearance Agreements extending the Forbearance Period to April 30, 2015. Subsequent to March 31, 2015, the Company entered into further amendments to the Forbearance Agreements. See Note 12 Subsequent Events.
13
Advisory Agreement
In March 2015, pursuant to the terms of the Forbearance Agreements, the Company entered into an engagement letter (the Engagement Letter) with Conway MacKenzie Management Services, LLC (CMS). Pursuant to the Engagement Letter, the Company appointed principals of CMS to the Interim Chief Financial Officer and Strategic Alternatives Officer positions. Those officers are engaged to assist the Company in connection with its efforts to restructure or repay the First Lien Notes and Second Lien Notes. The Company will pay CMS a fee of $50,000 per month for services of the Interim Chief Financial Officer and pay hourly fees for services of other CMS personnel.
NOTE 11 COMMITMENTS AND CONTINGENCIES
Contingencies
From time to time the Company may become involved in litigation in the ordinary course of business. At March 31, 2015, except as described below, the Companys management was not aware, and as of the date of this report is not aware, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of March 31, 2015, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Companys properties.
The Harvest Group, LLC, et al. v. Brian Carl Albrecht; Harvest Operating LLC v. The Harvest Group, LLC, et al.
In February 2010, the Company filed a complaint in the United States Bankruptcy Court for the Western District of Louisiana against Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer, each being former owners of The Harvest Group LLC and/or Harvest Oil & Gas, LLC. The complaint alleged breach of the Purchase and Sale Agreements with the former owners arising from the underpayment or nonpayment of royalties to the State of Louisiana for periods prior to the Companys acquisition of the Harvest Companies and related claims for damages. The claims against all parties other than Brian Carl Albrecht were subsequently settled and the claim against Mr. Albrecht was converted to an arbitration proceeding.
Harvest Operating, LLC, a company controlled by Mr. Albrecht, brought a separate cause of action against The Harvest Group, LLC, Harvest Oil & Gas, LLC and Saratoga Resources, Inc. (the Saratoga Parties), which cause of action was consolidated with the arbitration proceedings noted above. Harvest Operatings cause of action asserted a claim for damages based on the alleged wrongful termination of rights to use a pipeline owned and operated by the Saratoga Parties and the loss in value of a property operated by Harvest Operating based on its inability to transport production from that property via the pipeline in question.
The consolidated arbitration proceeding was conducted before a single arbitrator and, in August 2014, the arbitrator issued an Award and Reasons ruling (1) in favor of Saratoga, as relates to the royalty claim, and awarding to Saratoga $355,879, and (2) in favor of Harvest Operating, as relates to the pipeline use claim, and awarding to Harvest Operating $3,757,050. As a result of such award, the Company recorded an arbitration award expense and an accrued liability of $3.4 million.
In November 2014, Saratoga filed a motion with the arbitrator to reconsider and clarify the arbitration award. Separately, in November 2014, Saratoga filed a Motion for Clarification and Remittitur in the 19th District Court of East Baton Rouge Parish, Louisiana. Both the motion with the arbitrator and the Motion in the District Court sought to vacate the arbitrators award relating to the pipeline claim on multiple grounds. In December 2014, the arbitrator agreed to hear arguments as to the authority and grounds for reconsidering the arbitration award and the arbitrators decision in that matter is pending. Subsequent to March 31, 2015, the motion before the arbitrator to vacate the arbitration award was denied and the 19th District Court entered a final judgment denying Saratogas motion to vacate or modify the arbitration award and granted the plaintiffs motion to confirm the arbitration award.
14
Also, in November 2014, Saratoga filed a separate cause of action against Brian Albrecht in the 24th District Court of Jefferson Parish, Louisiana. The cause of action alleges breach of contract on the part of Mr. Albrecht and seeks damages in an amount equal to those awarded in the above arbitration proceeding. Saratoga asserts that the Purchase and Sale Agreement under which Saratoga secured beneficial ownership of the pipeline that was subject of the arbitration proceeding and the claims of Harvest Operating was illusory in that, based on the reasoning of the arbitration award, Saratoga would not have received the rights associated with beneficial ownership and control of the pipeline and that, by withholding from Saratoga the ordinary rights associated with ownership of the pipeline, Mr. Albrecht was in breach of the terms of the Purchase and Sale Agreement.
NOTE 12 SUBSEQUENT EVENTS
Forbearance Agreements
On April 30, 2015, the Company entered into amendments to the Forbearance Agreements extending the Forbearance Period to May 8, 2015 subject to a further extension of the Forbearance Period to May 11, 2015 if the Company paid an additional retainer to legal counsel for the First Lien Lenders in the amount of $200,000 and subject to a further extension of the Forbearance Period to May 22, 2015 if the Company appoints an additional independent director designated by the First Lien Lenders. The payment of an additional legal fee retainer and appointment of an additional director both occurred by the designated dates and the Forbearance Period was extended until May 22, 2015.
On May 18, 2015, the Company entered into further amendments to the Forbearance Agreements extending the Forbearance Period to June 5, 2015.
Appointment of Director
Pursuant to the terms of the April 30, 2015 amendment to the Forbearance Agreements, on May 11, 2015, the Company appointed an additional independent director to the Companys board of directors and to the independent committee of the board.
Stock Option Grants
In April 2015, the Company granted stock options to a non-executive employee to purchase an aggregate of 60,000 shares of common stock. The options vest over three years and are exercisable for a term of seven years at a price of $0.23 per share.
15
ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Information
This Form 10-Q quarterly report of Saratoga Resources, Inc. (the Company) for the three months ended March 31, 2015, contains certain 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, which are intended to be covered by the safe harbors created thereby. To the extent that there are statements that are not recitations of historical fact, such statements constitute forward-looking statements that, by definition, involve risks and uncertainties. In any forward-looking statement, where we express an expectation or belief as to future results or events, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will be achieved or accomplished.
The actual results or events may differ materially from those anticipated and as reflected in forward-looking statements included herein. Factors that may cause actual results or events to differ from those anticipated in the forward-looking statements included herein include the Risk Factors described in Item 1A of our Form 10-K for the year ended December 31, 2014.
Readers are cautioned not to place undue reliance on the forward-looking statements contained herein, which speak only as of the date hereof. We believe the information contained in this Form 10-Q to be accurate as of the date hereof. Changes may occur after that date, and we will not update that information except as required by law in the normal course of our public disclosure practices.
Additionally, the following discussion regarding our financial condition and results of operations should be read in conjunction with the financial statements and related notes contained in Item 1 of Part 1 of this Form 10-Q, as well as the Risk Factors in Item 1A and the financial statements in Item 8 of Part II of our Form 10-K for the fiscal year ended December 31, 2014.
Overview
We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of crude oil and natural gas properties. Our lease holdings totaled approximately 51,500 acres at March 31, 2015, comprised of our principal producing properties covering approximately 31,700 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and approximately 19,800 acres of leases in the shallow Gulf of Mexico shelf.
At March 31, 2015, we operated or had interests in 105 producing wells and our principal properties covered approximately 51,500 gross/net acres, more than half of which were held by production without near-term lease expirations, across 13 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana as well as in the shallow Gulf of Mexico. We own approximately 100% working interest in all our properties, with the only exception being a single well where we have an overriding royalty interest. Our net revenue interests in our properties range from 69% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 99% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.
2015 Developments
Commodity Prices
During the quarter ended March 31, 2015, we continued to be subject to a sharp decline in commodity prices that began during the second half of 2014 with average prices realized from the sale of crude being down to $45.72 per barrel during the 2015 quarter as compared to $102.93 per barrel in the 2014 quarter and average prices realized from the sale of natural gas being down to $3.29 per mcf in the 2015 quarter as compared to $5.90 per mcf in the 2014 quarter.
Drilling and Development Activities
Drilling and development and infrastructure project operations to date in 2015 are summarized as follows:
Development Drilling. We did not drill any developmental wells during the three months ended March 31, 2015.
Exploratory Drilling. We did not drill any exploratory wells during the three months ended March 31, 2015.
16
Recompletion and Workover Program. During the three months ended March 31, 2015 we did not undertake any recompletions or workovers, however we invested $89,049 in recompletions and workovers that were begun during 2014.
Infrastructure Program. During the three months ended March 31, 2015, we invested $87,713 in infrastructure improvements and additions to support existing production and anticipated increases in production.
Drilling and Development Plans. We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities. With the drop in commodity prices we have put efforts to drill these prospects on hold. We expect to resume efforts to seek partners to drill at such time as commodity prices support such efforts.
For the three months ended March 31, 2015, we had approximately 105 gross, and 104 net, wells in production.
Compensation
During the three months ended March 31, 2015, we granted 30,000 stock options to an executive officer at an exercise price of $0.21 per share and a total of 45,000 stock options to two employees at exercise prices ranging from $0.21 to 0.27 per share.
We recorded $96,506 of compensation charges that is reflected in general and administrative expense for the three months ended March 31, 2015 and is attributable to equity grants during 2015 and prior years.
As of March 31, 2015, total compensation cost relating to unvested stock option awards not yet recognized in earnings was approximately $0.2 million, which is expected to be recognized over a weighted average period of approximately 0.5 years.
Operating Costs
During the three months ended March 31, 2015, we continued a program, begun during the fourth quarter of 2014, to decrease lease operating expenses and general and administrative expenses. Cost reduction measures have focused on bringing contract employees in-house, eliminating redundant positions, managing marine transportation, optimizing our chemical program, lowering communications costs, replacing/modifying our compressors, downsizing our Houston office, curtailing expenditures on certain longer term projects and tightening discretionary spending. Those cost cutting measures are targeted to reduce lease operating expenses and general and administrative expenses by $13.3 million (a 39% decrease), in the aggregate, during 2015 as compared to 2014. The anticipated cost reductions will be partially offset by additional legal fees, consulting and other expenses incurred pursuant to the Forbearance Agreements and our ongoing efforts to restructure/refinance existing debt.
Forbearance Agreements
On January 30, 2015, we, along with our subsidiaries, Lobo Operating, Inc., Lobo Resources, Inc., Harvest Oil & Gas, LLC and The Harvest Group, LLC (collectively, the Borrowers) entered into a forbearance agreement (the First Lien Forbearance Agreement) with the holders (the First Lien Lenders) of certain notes (the First Lien Notes) issued under that certain Indenture dated as of November 22, 2013 (the First Lien Indenture), by and among the Borrowers and The Bank of New York Mellon Trust Company, N.A., as trustee (the First Lien Trustee). Also on January 30, 2015, the Borrowers entered into a forbearance agreement (the Second Lien Forbearance Agreement and, together with the First Lien Forbearance Agreement, the Forbearance Agreements) with the holders (the Second Lien Lenders) of seventy-five percent (75%) or more in principal amount of the notes (the Second Lien Notes) issued under that certain Indenture dated as of July 12, 2011 (as supplemented or amended, the Second Lien Indenture), by and among the Borrowers and The Bank of New York Mellon Trust Company, N.A., as trustee (the Second Lien Trustee).
The Forbearance Agreements were entered into following (i) the Borrowers failure to pay to the First Lien Lenders an interest installment in the amount of $1.4 million scheduled for payment on December 31, 2014, and constituting a default if not paid by January 30, 2015 (the Anticipated First Lien Default), and (ii) the Borrowers failure to pay to the Second Lien Lenders an interest installment in the amount of $7.9 million scheduled for payment on January 1, 2015, and constituting a default if not paid by February 2, 2015 (the Anticipated Second Lien Default, and, together with the Anticipated First Lien Default, the Specified Defaults).
We received confirmation from the First Lien Lenders that they hold more than 75% of the principal amount of the outstanding Second Lien Notes and have each agreed, during the Forbearance Period (as defined below), not to provide any direction to the Second Lien Trustee or to take any steps to enforce any rights of the Second Lien Trustee or the holders of Second Lien Notes occasioned by the failure of the Borrowers to make the January 1, 2015 interest payment.
17
Pursuant to the First Lien Forbearance Agreement, the First Lien Lenders agreed to forbear, until the earlier of March 16, 2015 or the occurrence of certain defaults defined in the First Lien Forbearance Agreement (the Forbearance Period), from exercising certain of their default-related rights and remedies against the Borrowers with respect to the Specified Defaults in order to permit the Borrowers an opportunity to effectuate a restructuring/refinancing or implement operational improvements.
Under the terms of the First Lien Forbearance Agreement, among other things, we agreed to (i) pay, by February 2, 2015, the December 31, 2014 interest payment owing to the First Lien Lenders, with interest at the default rate, in the amount of $1,378,650; (ii) pay expenses incurred by the First Lien Lenders in connection with the Forbearance Agreement, including paying a retainer to counsel for the First Lien Lenders; (iii) retain, by March 2, 2015, a financial advisor acceptable to the First Lien Lenders on terms acceptable to the First Lien Lenders; (iv) deliver to the First Lien Lenders a 6-week operating budget in form and methodology acceptable to the First Lien Lenders and to abide by that budget within permitted variances; (v) deliver to the First Lien Lenders, not later than March 2, 2015, certain financial, operating and other information and, not later than March 15, 2015, a two year business plan and 2015 budget; and (vi) cause its officers, financial advisors, investment bankers and others to furnish information reasonably requested by the First Lien Lenders.
Any breach by the Borrowers of any covenant in the First Lien Forbearance Agreement, or the commencement of any bankruptcy, insolvency or creditor relief proceedings by or with respect to the Borrowers, will constitute an event of default under the First Lien Forbearance Agreement.
Pursuant to the Second Lien Forbearance Agreement, the Second Lien Lenders agreed to forbear, during the Forbearance Period, from exercising certain of their default-related rights and remedies against the Borrowers with respect to the Specified Defaults in order to permit the Borrowers an opportunity to effectuate a restructuring/refinancing or implement operational improvements. Second Lien Forbearance Agreement is substantially identical to the First Lien Forbearance Agreement except that the January 1, 2015 interest payment on the First Lien Notes was not required to be made.
On March 16, 2015, we entered into amendments to the Forbearance Agreements extending the Forbearance Period to April 30, 2015.
On April 30, 2015, we entered into further amendments to the Forbearance Agreements extending the Forbearance Period to May 8, 2015 subject to a further extension of the Forbearance Period to May 11, 2015 if we paid an additional retainer to legal counsel for the First Lien Lenders in the amount of $200,000 and subject to a further extension of the Forbearance Period to May 22, 2015 if we appoint an additional independent director designated by the First Lien Lenders. The payment of an additional legal fee retainer and appointment of an additional director both occurred by the designated dates and the Forbearance Period was extended until May 22, 2015.
On May 18, 2015, the Company entered into further amendments to the Forbearance Agreements extending the Forbearance Period to June 5, 2015.
Advisory Agreement
In March 2015, pursuant to the terms of the Forbearance Agreements, we entered into an engagement letter (the Engagement Letter) with Conway MacKenzie Management Services, LLC (CMS). Pursuant to the Engagement Letter, we appointed principals of CMS to the Interim Chief Financial Officer and Strategic Alternatives Officer positions. Those officers are engaged to assist in connection with our efforts to restructure or repay the First Lien Notes and Second Lien Notes. We will pay CMS a fee of $50,000 per month for services of the Interim Chief Financial Officer and pay hourly fees for services of other CMS personnel.
Appointment of Director
Pursuant to the terms of the April 30, 2015 amendment to the Forbearance Agreements, on May 11, 2015, we appointed an additional independent director to our board of directors and to the independent committee of our board.
Results of Operations
Oil and Gas Revenue
Oil and gas revenue for the quarter ended March 31, 2015 decreased by 40.3% to $6.3 million from $10.6 million in the 2014 quarter.
18
The decrease in revenue was attributable to a 41.0% decrease in oil revenues on a 55.6% decrease in average oil prices realized partially offset by a 32.7% increase in oil production volumes and a 32.2% decline in gas revenues on a 44.2% decrease in average gas prices realized partially offset by a 21.8% increase in gas production volumes, each as compared to the 2014 quarter.
The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three ended March 31, 2015 and 2014:
|
| Three Months Ended March 31, | |||||
|
| 2015 |
|
| 2014 | ||
Revenues |
|
|
|
|
|
|
|
Oil |
| $ | 5,718,867 |
|
| $ | 9,700,842 |
Gas |
|
| 611,595 |
|
|
| 902,149 |
Total oil and gas revenues |
| $ | 6,330,462 |
|
| $ | 10,602,991 |
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
Oil (Bbls) |
|
| 125,096 |
|
|
| 94,247 |
Gas (Mcf) |
|
| 186,135 |
|
|
| 152,861 |
Total production (Boe) |
|
| 156,118 |
|
|
| 119,724 |
|
|
|
|
|
|
|
|
Average sales price |
|
|
|
|
|
|
|
Oil (per Bbl) |
| $ | 45.72 |
|
| $ | 102.93 |
Gas (per Mcf) |
|
| 3.29 |
|
|
| 5.90 |
Total average sales price (per Boe) |
| $ | 40.55 |
|
| $ | 88.56 |
Oil production was up 30.8 MBbl, or 32.7%, and gas production was up 33.3MMcf, or 21.8%, for the three months ended March 31, 2015 as compared to the same period in 2014. The increase in production was largely attributable to improved run times during the first quarter of 2015 as compared to the first quarter of 2014. Average run times and production rates during the first quarter of 2014 were negatively affected by elevated decline rates in certain high production wells, increased water-cut in selected wells, gas lift shortages, mechanical issues and flow line capacity constraints. Production optimization initiatives and infrastructure improvements undertaken throughout 2014 addressed the principal causes of the decreased run times, gas lift shortages, mechanical issues and flow line capacity constraints, raising production rates to 1,735 Boepd during the first quarter of 2015 from 1,330 Boepd during the first quarter of 2014.
The decrease in realized oil and natural gas prices reflects the steep drop in global hydrocarbon prices during the second half of 2014. While prices stabilized during the first quarter of 2015, they remained at levels that were significantly lower than in the comparable period in 2014. We continue to realize a premium pricing on both our crude oil and natural gas production.
Oil and Gas Hedging
For the quarter ended March 31, 2015, we recorded a gain on oil and gas hedging of $117 compared to $1.1 million for the same period in 2014. All of our oil and gas hedges have expired at March 31, 2015 and we have not entered into any new hedges during 2015 due to the current uncertainty surrounding oil and gas prices.
Other Revenues
Other revenue consists principally of production handling fees and contract operator fees received.
Operating Expenses
Operating expenses decreased by 29.3% to $9.9 million for the quarter ended March 31, 2015 from $14.0 million in the 2014 quarter. The following table sets forth the components of operating expenses for the 2015 and 2014 quarters:
| Three Months Ended |
| Three Months Ended | ||||||||
| March 31, 2015 |
| March 31, 2014 | ||||||||
| Total |
| Per Boe |
| Total |
| Per Boe | ||||
Lease operating expense | $ | 4,008,007 |
| $ | 25.67 |
| $ | 5,492,815 |
| $ | 45.88 |
Workover expense |
| 18,978 |
|
| 0.12 |
|
| 2,192,186 |
|
| 18.31 |
Exploration expense |
| 19,098 |
|
| 0.12 |
|
| 221,352 |
|
| 1.85 |
Depreciation, depletion and amortization |
| 2,748,394 |
|
| 17.61 |
|
| 2,742,059 |
|
| 22.90 |
Accretion expense |
| 595,562 |
|
| 3.81 |
|
| 448,466 |
|
| 3.75 |
General and administrative |
| 1,887,412 |
|
| 12.09 |
|
| 2,352,570 |
|
| 19.65 |
Severance taxes |
| 580,204 |
|
| 3.72 |
|
| 500,750 |
|
| 4.18 |
| $ | 9,857,655 |
| $ | 63.14 |
| $ | 13,950,198 |
| $ | 116.52 |
19
The changes in operating expenses were primarily attributable to the factors discussed below.
Lease Operating Expense
Lease operating expenses for the quarter ended March 31, 2015 decreased 27.0% to $4.0 million from $5.5 million in the 2014 quarter and, on a per BOE basis, decreased 44.0% to $25.67 per BOE from $45.88 per BOE, in the 2014 quarter. The decrease in lease operating expense for the quarter was primarily due to (i) $0.5 million in contract labor and repair and maintenance charges associated with our production optimization initiative that were included in lease operating expense for the 2014 quarter (ii) one-time contract construction labor and building repair and maintenance expenses for the living quarters in Grand Bay Field incurred during 2014; and (iii) a reduction in our reliance on, and cost of, contract operating personnel. We are attempting to negotiate reduced rates with many of our vendors and expect our lease operating expenses will continue to decrease if hydrocarbon prices continue to remain at lower levels during the remainder of the year.
Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. The decrease in lease operating expenses on a per BOE basis for the quarter was higher on a percentage basis than the overall decrease in lease operating expense primarily due to the increases in production volumes and the fixed nature of certain lease operating expenses.
Workover Expense
Workover expense for the quarter ended March 31, 2015 decreased to $18,978 from $2,192,186 in the 2014 quarter. The change in workover expense was attributable to reduction in the number of workovers undertaken during the current quarter.
Exploration Expense
Exploration expense for the quarter ended March 31, 2015 decreased to $19,098 from $221,352 in the 2014 quarter. The decrease in exploration expenses was principally due to a reduction in field studies related to our Gulf of Mexico shelf acreage.
Depreciation, Depletion and Amortization (DD&A)
Depreciation, depletion and amortization for the quarter ended March 31, 2015 remained relatively flat at $2,748,394 as compared to $2,742,059 in the 2014 quarter. Increases in DD&A caused by higher production volumes was offset by a lower cost base due to impairments recorded during 2014 as reflected in a decrease to $17.61 per BOE during the 2015 quarter from $22.90 per BOE in the 2014 quarter.
We utilize the successful efforts method of accounting for oil and gas producing activities. Under this method, DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.
Accretion expense
Accretion expense relating to our asset retirement obligations increased to $595,562 from $448,466 for the quarter ended March 31, 2015 as compared to the 2014 quarter.
The decrease in accretion expense was attributable to changes in the anticipated plugging dates and discount rates used in calculating the asset retirement obligation for certain fields.
General and Administrative
General and administrative (G&A) expense for the quarter ended March 31, 2015 decreased 19.8% to $1,887,412 as compared to $2,352,570 in the 2014 quarter. The decrease in G&A expense for the quarter was primarily due a reduction in consulting fees and accounting costs, partially offset by an increase in non-cash stock compensation expense.
Severance Taxes
Severance taxes for the quarter ended March 31, 2015 increased to $580,204 from $500,750 in the 2014 quarter. The increase was primarily attributable to the fact that we received refunds of severance taxes paid in prior periods totaling $0.5 million during the 2014 quarter which more than offset the reductions in current quarter severance taxes from the decrease in oil and revenues. We continue to receive the horizontal well severance tax exemptions obtained for our Rocky and Zeke wells and the deep well severance tax exemption obtained for our Mesa Verde well.
20
Other Income (Expense), Net
Net other expense increased to $8.5 million for the quarter ended March 31, 2015 from $6.0 million for the 2014 quarter.
Interest expense reflects interest incurred on debt under our 10% First Lien Notes and 12.5% Second Lien Notes. The increase in interest expense was attributable to an increase in the amortization of the debt discount and debt issuance costs associated with the notes as the amortization period was reduced to reflect the forbearance period and penalty interest accrued due to the non-payment of interest on the Second Lien Notes.
Income Tax Expense (Benefit)
For the quarter ended March 31, 2015 we recorded an income tax expense of $25,500 compared to $82,066 during the 2014 quarter.
The decrease in income tax expense is primarily due to the fact that we expect lower state taxes during 2015 as a result of decreased revenues.
Our effective tax rates were different than our federal statutory tax rate due to Louisiana state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
Financial Condition
Liquidity and Capital Resources
Our principal requirements for capital are to fund our day-to-day operations and exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the repayment of debt.
During 2014 and 2015 we funded operations out of operating cash flow and cash on hand. We did not have access to available capital under a revolving credit agreement and do not at this time have a revolving credit facility.
We developed, and beginning in 2011 commenced, a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term objectives are focused on restoration of shut-in and curtailed production through investments in infrastructure and deferred maintenance and recompletions, workovers and thru-tubing plugbacks each designed to increase or restore production volumes from wells producing below capacity and an inventory of proved developed nonproducing opportunities. Mid-term, following or in conjunction with execution of short-term opportunities, our focus is on the development of an inventory of proved undeveloped opportunities within our inventory of proved undeveloped wells targeting normally pressured oil and gas. Long-term, following or in conjunction with the execution of our short- and mid-term opportunities, our focus is on continuing development of our reserves and exploratory drilling of deep shelf opportunities. During 2014, while continuing to advance short-term objectives associated with continual investment in our infrastructure, we focused on our mid-term objectives through drilling proved undeveloped opportunities.
As a result of sharply lower commodity prices, and resulting operating losses and declines in cash flows, our liquidity position deteriorated substantially during 2014 and the first quarter of 2015. We have implemented cost cutting measures and curtailed development of our proved undeveloped opportunities in favor of building our cash position to, among other things, support our scheduled payments of interest on outstanding debt. In January 2015, we entered into forbearance agreements with our lenders, paying only the interest on first lien indebtedness but not paying interest on second lien indebtedness. We are presently working with our lenders and with prospective financing sources to add liquidity and/or refinance our debt. Our cash on hand at March 31, 2015, together with operating cash flows, is expected to be adequate to support basic operations and maintenance but, absent increased commodity prices and/or production, is not expected to be adequate to support development activities or debt service obligations over the next twelve months. Further, should we be required to pay the 2014 arbitration award of approximately $3.4 million, our existing cash reserves would be materially reduced. We are presently evaluating options for bringing in additional financing to support our liquidity needs and planned development program. We do not, however, presently have any commitments to provide financing and there is no assurance that any additional financing will be provided on acceptable terms or at all. Should we be unable to pay our scheduled interest payments or to reach acceptable accommodations with our lenders regarding such payments, we may be subject to legal actions instituted by our lenders which may include foreclosure of liens and possible loss of assets.
21
Cash, Cash Flows and Working Capital
We had a cash balance of $5.7 million and a working capital deficit of $190.6 million at March 31, 2015 as compared to a cash balance of $10.9 million and a working capital deficit of $185.7 million at December 31, 2014. The decrease in cash on hand was primarily attributable the interest payment on our 10% First Lien Notes in January 2015 and to reductions in our operating cash flow. The decrease in our working capital was primarily attributable to the reduction in our cash balance and an increase in accrued liabilities, primarily due to unpaid interest, partially offset by reductions in accounts payable.
Operations used cash flow of $3.5 million for the three months ended March 31, 2015 as compared to using $9.5 million for the three months ended March 31, 2014. The change in operating cash flows during 2015 was principally attributable to changes in our operating assets and liabilities.
Investing activities used cash totaling $1.3 million during the three months ended March 31, 2015 as compared to $2.3 million during 2014. The decrease in cash used in investing activities was primarily due to a reduction in our development activities.
Financing activities used cash flows of $0.4 million during the three months ended March 31, 2015 as compared to $0.3 million during 2014. Cash flows used by financing activities during both periods are primarily related to repayments on our short-term notes payable.
Debt
At March 31, 2015, we had $179.9 million of indebtedness outstanding, consisting of $54.6 million in face amount of 10% First Lien Notes, less $0.1 million of debt discount, and $125.2 million in face amount of 12½% Senior Secured Notes due 2016 less $0.3 million of debt discount.
We had no letters of credit outstanding at March 31, 2015 that were not fully collateralized by cash.
10% First Lien Notes. In November 2013, we issued $54.6 million in aggregate principal amount of our 10.0% Senior Secured Notes due 2015 (the First Lien Notes).
The 10% First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with our, and the Guarantors, existing and future senior indebtedness and senior in right of payment to 12½% Second Lien Notes.
The 10% First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.
We have the option to redeem all or a portion of the 10% First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to offer to purchase the 10% First Lien Notes at a price equal to 101% of the aggregate principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the 10% First Lien Notes at a price equal to 100% of the principal amount of 10% First Lien Notes repurchased plus accrued and unpaid interest.
In connection with the issuance and sale of the 10% First Lien Notes, we, the First Lien Trustee and Second Lien Trustee entered into an Intercreditor Agreement. Pursuant to the Intercreditor Agreement, the parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Obligations shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under Second Lien Indenture, by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related 12½% Second Lien Notes.
12½% Second Lien Notes. In July 2011, we issued $127.5 million of our 12½% Second Lien Notes and retired all obligations owing under our prior credit facilities and all outstanding letter of credit obligations. In December 2012, we issued an additional $25.0 million of our 12½% Second Lien Notes. In November 2013, we retired $27.3 million in face amount of our 12½% Second Lien Notes pursuant to the issuance of a like amount of 10% First Lien Notes described above.
22
The 12½% Second Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with our and the Guarantors existing and future senior indebtedness, subject, however, to the Intercreditor Agreement pursuant to which the 10% First Lien Notes are senior in right, priority, operation and effect to the lien securing the 12½% Second Lien Notes. The 12½% Second Lien Notes mature on July 1, 2016, and interest is payable on the notes on January 1 and July 1 of each year. We have the option to redeem all or a portion of the 12½% Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Second Lien Indenture pursuant to which the 12½% Second Lien Notes were issued plus accrued and unpaid interest.
In January 2015, we entered into forbearance agreements with respect to both the First Lien Notes and the Second Lien Notes and were in default under those notes, including being default on the payment of interest owing as of January 1, 2015 with respect to the Second Lien Notes in the amount of $7.8 million.
In March 2015, we entered into amendments to the forbearance agreements which extended the forbearance period to April 30, 2015.
In April 2015, we entered into further amendments to the forbearance agreements which extended the forbearance period to May 22, 2015.
Capital Expenditures and Commitments
Our capital spending for the three months ended March 31, 2015 was $181,184 relating primarily to infrastructure projects, recompletions and workovers that were begun during 2014. We did not undertake and recompletions or workovers during the quarter ended March 31, 2015 and capital expenditures were down from $3.5 million during the 2014 quarter.
As noted, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations. Actual levels of capital expenditures in any year may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services.
Risk Management Activities Commodity Derivative Instruments
We periodically enter into price-risk management transactions (e.g., swaps, and floors) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and partially limit our potential gains from future increases in prices. None of these instruments have been used for trading purposes. During the three months ended March 31, 2015, we recorded a gain on commodity derivatives of $117 in current earnings.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements or guarantees of third party obligations at March 31, 2015.
Inflation
We believe that inflation has not had a significant impact on our operations since inception.
ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market-risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Prices have fluctuated significantly during the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. In the normal course of business we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.
23
As of March 31, 2015, we had no hedge contracts outstanding:
We are exposed to market risk on derivative instruments to the extent of changes in market prices of crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. The change in the fair value of our commodity derivative contracts that are effective are recorded to Accumulated Other Comprehensive Income (Loss) in Stockholders Equity in the Consolidated Balance Sheet. The ineffective portion of the change in fair market value of derivatives is recorded currently in earnings as a component of Oil and Gas Hedging in the Consolidated Statements of Operations. We estimate 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.
Interest Rate Risk
All of our debt has a fixed interest rate, and we are not presently exposed to interest rate risk. In the event that we establish a new revolving credit facility we expect that such facility will provide for interest at a floating rate and that borrowing under such facility will expose us to risk of changing interest rates.
ITEM 4
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of March 31, 2015 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of March 31, 2015.
Changes in Internal Control over Financial Reporting
No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the quarter ended March 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
24
PART II
ITEM 1
LEGAL PROCEEDINGS
The Harvest Group, LLC, et al. v. Brian Carl Albrecht; Harvest Operating LLC v. The Harvest Group, LLC, et al.
In February 2010, the Company filed a complaint in the United States Bankruptcy Court for the Western District of Louisiana against Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer, each being former owners of The Harvest Group LLC and/or Harvest Oil & Gas, LLC. The complaint alleged breach of the Purchase and Sale Agreements with the former owners arising from the underpayment or nonpayment of royalties to the State of Louisiana for periods prior to the Companys acquisition of the Harvest Companies and related claims for damages. The claims against all parties other than Brian Carl Albrecht were subsequently settled and the claim against Mr. Albrecht was converted to an arbitration proceeding.
Harvest Operating, LLC, a company controlled by Mr. Albrecht, brought a separate cause of action against The Harvest Group, LLC, Harvest Oil & Gas, LLC and Saratoga Resources, Inc. (the Saratoga Parties), which cause of action was consolidated with the arbitration proceedings noted above. Harvest Operatings cause of action asserted a claim for damages based on the alleged wrongful termination of rights to use a pipeline owned and operated by the Saratoga Parties and the loss in value of a property operated by Harvest Operating based on its inability to transport production from that property via the pipeline in question.
The consolidated arbitration proceeding was conducted before a single arbitrator and, in August 2014, the arbitrator issued an Award and Reasons ruling (1) in favor of Saratoga, as relates to the royalty claim, and awarding to Saratoga $355,879, and (2) in favor of Harvest Operating, as relates to the pipeline use claim, and awarding to Harvest Operating $3,757,050. As a result of such award, the Company recorded an arbitration award expense and an accrued liability of $3.4 million.
In November 2014, Saratoga filed a motion with the arbitrator to reconsider and clarify the arbitration award. Separately, in November 2014, Saratoga filed a Motion for Clarification and Remittitur in the 19th District Court of East Baton Rouge Parish, Louisiana. Both the motion with the arbitrator and the Motion in the District Court sought to vacate the arbitrators award relating to the pipeline claim on multiple grounds. In December 2014, the arbitrator agreed to hear arguments as to the authority and grounds for reconsidering the arbitration award and the arbitrators decision in that matter is pending. Subsequent to March 31, 2015, the motion before the arbitrator to vacate the arbitration award was denied and the 19th District Court entered a final judgment denying Saratogas motion to vacate or modify the arbitration award and granted the plaintiffs motion to confirm the arbitration award.
Also, in November 2014, Saratoga filed a separate cause of action against Brian Albrecht in the 24th District Court of Jefferson Parish, Louisiana. The cause of action alleges breach of contract on the part of Mr. Albrecht and seeks damages in an amount equal to those awarded in the above arbitration proceeding. Saratoga asserts that the Purchase and Sale Agreement under which Saratoga secured beneficial ownership of the pipeline that is subject of the arbitration proceeding and the claims of Harvest Operating was illusory in that, if the reasoning of the arbitration award were to stand, Saratoga would not have received the rights associated with beneficial ownership and control of the pipeline and that, by withholding from Saratoga the ordinary rights associated with ownership of the pipeline, Mr. Albrecht was in breach of the terms of the Purchase and Sale Agreement.
ITEM 6
EXHIBITS
Exhibit No. |
| Description |
|
|
|
31.1 |
| Certification of CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.2 |
| Certification of CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
32.1 |
| Certification of CEO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
32.2 |
| Certification of CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
101.INS |
| XBRL Instance Document |
101.SCH |
| XBRL Schema Document |
101.CAL |
| XBRL Calculation Linkbase Document |
101.DEF |
| XBRL Definition Linkbase Document |
101.LAB |
| XBRL Labels Linkbase Document |
101.PRE |
| XBRL Presentation Linkbase Document |
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on behalf by the undersigned thereunto duly authorized.
| SARATOGA RESOURCES, INC. | |
Date: May 20, 2015 |
|
|
| By: | /s/ Thomas Cooke |
|
| Thomas Cooke |
|
| Chief Executive Officer |
|
|
|
| By: | |
|
| Randal B. McDonald, Jr. |
|
| Vice President Finance and Accounting |
26