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Saratoga Resources, Inc. (NYSE MKT:SARA; the “Company” or “Saratoga”) today announced financial and operating results for the quarter and year-ended December 31, 2014. Additionally, as required by NYSE Mkt Company Guide Section 610(b), Saratoga announced that its audited consolidated financial statements for the fiscal year ended December 31, 2014, included in the Company’s Annual Report on Form 10-K which was filed with the Securities and Exchange Commission on April 15, 2015, contained a going concern qualification from its independent registered public accounting firm.

The Company is reporting a loss including a non-cash, impairment charge totaling $107.8 million. The charge reflects reclassification of certain reserves out of the proved undeveloped category and into the probable category due to application of the SEC “5-year rule” – accounting for approximately $95.3 million, or 88.4%, of the impairment charge – and the steep decline in commodity prices, as tested against December 31, 2014 NYMEX futures strip pricing, resulting in the expected undiscounted future cash flows at a producing field level to be less than the unamortized capitalized cost of assets in several of the Company’s fields.

Key Financial Results

Year-Ended 2014

  • Production of 670,050 barrels of oil equivalent, or 1,836 barrels of oil equivalent per day;
  • Reserve replacement ratio of more than two to one with proved reserve revisions of 1,483,200 barrels of oil equivalent;
  • Oil and gas revenues of $52.3 million for 2014;
  • Discretionary cash flow of $(10.4) million, or $(0.34) per fully diluted share, for 2014;
  • EBITDAX of $10.9 million for 2014;
  • Operating loss of $(119.5) million, or $(3.86) per fully diluted share, for 2014; and
  • Net loss of $(143.9) million, or $(4.65) per fully diluted share, for 2014.

Discretionary cash flow and EBITDAX are non-GAAP financial measures and are defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” below.

The revenues for 2014 reflect a decrease in production volumes (down 16.6% year over year) and lower average realized oil and natural gas prices. The decrease in production reflects a 15.2% decline in oil volumes and a 20.7% decline in natural gas volumes.

Oil production was down 91.9 thousand barrels of oil (“MBO”), or 15.2%, as compared to 2013. The decrease was primarily due to lost run time, anticipated decline rates in certain high production wells, mechanical downhole issues relating to specific wells, gas lift gas shortages and flow line capacity constraints, all of which were partially offset by the addition of production from recompletions, workovers and new drills during 2014 and the second half of 2013.

Production optimization initiatives and infrastructure improvements undertaken throughout 2014 addressed the principal causes of decreased run times, gas lift gas shortages, mechanical issues and flow line capacity constraints, raising run time and production rates to approximately 80% and 1,904 barrels of oil equivalent per day (“BOEPD”) during the fourth quarter of 2014 from 54% and 1,330 BOEPD during the first quarter of 2014.

Natural gas production was down 248.7 million cubic feet of gas (“MMCFG”), or 20.7%, as compared to 2013. The decrease in gas production principally related to natural decline and depletion of several wells and the recompletion of a previous gas producer uphole to an oil zone, partially offset by gas-targeted recompletions.

The decrease in realized hydrocarbon prices reflects the steep drop in global oil prices during the second half of 2014. We continued to realize a premium pricing on both our crude oil and natural gas production.

Operational Highlights

Operational highlights for 2014 included:

  • 1 development well, 6 recompletions and 9 workovers successfully completed;
  • Completion of Saratoga’s third horizontal well;
  • 105 gross (104 net) wells in production at December 31, 2014; and
  • 51,511 gross/net acres in 13 fields under lease at December 31, 2014.

Saratoga carried out 9 recompletions and 14 workovers in 2014. Six of the recompletions and nine of the workovers were successful. One workover was still in progress at year end.

Production Highlights

  • Oil and gas production of 133.0 MBO and 252.8 thousand cubic feet of gas (“MCFG”), or 175.1 thousand barrels of oil equivalent (“MBOE”) (75.9% oil) in Q4 2014, and 511.7 MBO and 950.1 MCFG, or 670.0 MBOE (76.4% oil) for 2014.

Reserve Highlights

  • Year-end 2014 SEC proved reserves consisted of 5.792 million barrels of oil (“MMBO”) and 26.579 billion cubic feet of gas (“BCFG”), or 10.222 million barrels of oil equivalent (“MMBOE”), down from 17.240 MMBOE of proved reserves at year-end 2013, largely due to downward revisions at year-end of 7.755 MMBOE associated with SEC “5-year” rule;
  • Proved reserve revisions of 435.7 MBO and 6,285.2 MMCFG, or 1,483.2 MBOE, more than double 2014 annual production of 670.1 MBOE;
  • Oil represents 56.6% of year-end 2014 1P reserves;
  • Year-end 2014 PV10 of $209.3 million, down 49% from $410.7 million at year-end 2013, largely due to downward revisions associated with SEC “5-year” rule;
  • Proved developed reserves comprised 36.8% of year-end 2014 proved reserves;
  • Year-end 2014 probable reserves totaled 10.4 MMBO and 94.0 BCFG, or 25.9 MMBOE;
  • Year-end 2014 possible reserves totaled 16.8 MMBO and 122.0 BCFG, or 37.1 MMBOE;
  • Year-end 2014 3P reserves totaled 73.271 MMBOE.

Year-end 2014 reserves reflect production of 670.0 MBOE during the year and the reclassification of 7,755.0 MBOE of reserves out of the proved undeveloped category to the probable category pursuant to the SEC “5-year rule” wherein reserves cannot be maintain in the proved undeveloped category for more than 5 years. The reclassified reserves in question were primarily gas, are associated with leases held by production and may at a future date be reclassified to the proved category once more.

Development Plans

  • Low risk recompletions, thru-tubing plugbacks and workovers from inventory of 61 proved developed non-producing (“PDNP”) opportunities in 44 wellbores in 6 fields;
  • Development of proved undeveloped (“PUD”) reserves from inventory of 36 PUD opportunities in 15 wellbores in 5 fields;
  • Development of probable P90 undeveloped reserves from inventory of 61 formerly PUD opportunities in 21 proposed wells in 3 fields; and
  • Strategic partnerships and joint ventures for risk-sharing on exploratory drilling of deep and ultra-deep prospects at Grand Bay, Vermilion 16 and in Central Gulf of Mexico leases.

Near term development plans are focused on conversion of PDNP opportunities. At December 31, 2014, an exhaustive review of prospects was underway to identify, prioritize and bring forward the most promising prospects. With added depth and quality of professional staff, Saratoga has identified, and intends to focus development drilling plans on, a pool of high impact prospects. Saratoga has now completed three horizontal wells in its Breton Sound 32 field and results from the reservoir simulation are now becoming available to the Company and expected to help identify a number of additional development locations for additional horizontal wells and horizontal sidetracks from existing wells.

There appears to be renewed interest in the high profile, ultra-deep play following Freeport-McMoRan’s recent onshore success at their Highlander Prospect so we will continue to evaluate the ultra-deep potential underlying our Grand Bay and Vermilion Block 16 fields.

With the drop in commodity prices during the second half of 2014, we have put efforts to seek joint venture partners to drill four initial prospects, two of which have proved undeveloped reserves, within the Gulf of Mexico shelf acreage, as well as the Goldeneye prospect under Grand Bay field, on hold. We expect to resume efforts to seek partners to drill the first of the prospects at such time as commodity prices support such efforts.

The 2015 capital expenditure budget is expected to be severely reduced due to the continuing low commodity price environment and the Company will concentrate its efforts on low-cost recompletions and workovers together with continued cost reduction and production optimization.

Debt and Strategic Initiatives

As a result of the steep decline in commodity prices during the second half of 2014 and continuing into 2015, compounded by production declines associated with run time issues in early 2014, we are operating in a cash constrained environment and have undertaken strategic initiatives to address operations in the current climate. Those initiatives include:

  • Forbearance agreements with principal lenders;
  • Extensive cost-cutting program with targeted LOE and G&A savings of $13.3 million for 2015 compared to 2014; and
  • Retained Conway MacKenzie Management Services, LLC to assist in efforts to restructure or repay secured debt.

Saratoga is working closely with its secured lenders to address liquidity issues with a view to either restructure or repay existing debt. We are presently operating under forbearance agreements with our first and second lien debt holders under which interest owing on our second lien debt was not paid in January 2015 and subsequent interest payments are not presently being made. The forbearance period ends April 30, 2015. We have retained Conway MacKenzie to assist in our evaluation of potential alternatives to either restructure or repay our existing secured debt. In conjunction with those efforts, we have undertaken extensive cost-cutting efforts that are expected to lower our total LOE and G&A by approximately $13.3 million during 2015.

Management Comments

Andy C. Clifford, President, commented, “The early part of 2014 presented challenges relating to our field operations while the latter part of 2014 presented challenges relating to commodity prices. Exhaustive initiatives undertaken in the field have remedied the field operating issues encountered in early 2014 and an ongoing cost containment program is bringing down operating costs to address this lower commodity price environment. Production optimization initiatives and infrastructure improvements undertaken throughout the year, including a successfully-executed complete field shutdown of Grand Bay, have addressed the principal causes of decreased run times, gas lift gas shortages, mechanical issues and flow line capacity constraints, raising run time and production rates to approximately 80% and 1,904 Boepd during the fourth quarter of 2014 from 54% and 1,330 Boepd during the first quarter of 2014. The run time on our facilities is over 90% and we continue to make improvements into 2015. Other initiatives we have undertaken include upgrading our field personnel and living quarters in the field.

In response to the dramatically lower commodity price environment, we have met this challenge by dramatically reducing lease operating expenses (“LOE”) and G&A. We are now seeing our LOE and G&A for the first quarter of 2015 at levels 44% and 33% lower respectively than the averages for 2014. We have downsized our Houston office during the first quarter and expect annual savings between LOE and G&A of over $13 million in 2015. Lifting costs are now running at under $40 per BOE and we forecast these to be under $30 per BOE by the end of 2015. Much of this improvement has been achieved by making improvements in the field but also by re-negotiating contracts with key service providers and reducing the use of external consultants and contract personnel.

The field operating issues early in the year and declining prices late in the year each had a substantial negative effect on our operating results for the year, compounded by an impairment charge of $107.8 million. I would note that more than $95 million of the non-cash impairment charge related specifically to the application of the SEC’s “five year rule” under which reserves may not generally remain in the proved undeveloped category for more than five years. The reserves in question relate to leases held by production and were reclassified to P90 probable reserves and may, in the future, become eligible for reclassification as proved reserves. There is no change in the nature and quality of the assets and the reclassification is not due to negative economics. Two thirds of the reserves in question are gas and were given a lower priority for development versus other projects for economic reasons. The remainder of the impairment is due to the lower commodity prices, tested against year-end 2014 NYMEX futures strip pricing, which combined with the SEC “5-year rule” is an industry-wide issue and not specific to Saratoga.”

About Saratoga Resources

Saratoga Resources is an independent exploration and production company with offices in Houston, Texas and Covington, Louisiana. Principal holdings cover approximately 51,500 gross/net acres, mostly held by production, located in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and in the shallow Gulf of Mexico Shelf. Most of the company’s large drilling inventory has multiple pay objectives that range from as shallow as 1,000 feet to the ultra-deep prospects below 20,000 feet in water depths ranging from less than 10 feet to a maximum of approximately 80 feet. For more information, go to Saratoga’s website atwww.saratogaresources.com and sign up for regular updates by clicking on the Updates button.

Forward-Looking Statements

This press release includes certain estimates and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, including, but not limited to, statements regarding future ability to fund the company’s development program, service and/or restructure or repay its debt and grow reserves, production, revenues and profitability, ability to reach and sustain target production levels and target cost savings, ability to secure commitments to participate in exploration of deep shelf prospects, ability to secure leases and the ultimate outcome of such efforts. Words such as “expects”, “anticipates”, “intends”, “plans”, “believes”, “assumes”, “seeks”, “estimates”, “should”, and variations of these words and similar expressions, are intended to identify these forward-looking statements. While we believe these statements are accurate, forward-looking statements are inherently uncertain and we cannot assure you that these expectations will occur and our actual results may be significantly different. These statements by the Company and its management are based on estimates, projections, beliefs and assumptions of management and are not guarantees of future performance. Important factors that could cause actual results to differ from those in the forward-looking statements include the factors described in the “Risk Factors” section of the Company’s filings with the Securities and Exchange Commission. The Company disclaims any obligation to update or revise any forward-looking statement based on the occurrence of future events, the receipt of new information, or otherwise.

Saratoga Resources, Inc.
CONSOLIDATED BALANCE SHEETS
December 31,
2014 2013
ASSETS
Current assets:
Cash and cash equivalents $ 10,911,070 $ 32,547,380
Accounts receivable 3,778,808 6,758,572
Prepaid expenses and other 1,006,758 1,056,350
Other current assets 150,000 150,000
Total current assets 15,846,636 40,512,302
Property and equipment:
Oil and gas properties – proved (successful efforts method) 301,399,079 286,441,663
Other 1,031,779 892,694
302,430,858 287,334,357
Less: Accumulated depreciation, depletion, amortization and impairment (226,716,401 ) (101,088,696 )
Total property and equipment, net 75,714,457 186,245,661
Other assets, net 20,350,655 21,665,830
Total assets $ 111,911,748 $ 248,423,793
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable $ 6,722,116 $ 5,391,648
Revenue and severance tax payable 2,711,229 3,754,812
Accrued liabilities 13,006,617 9,807,935
Derivative liabilities – short term 117 837,758
Short-term notes payable 329,964 338,512
First lien notes, net of discount of $151,169 at December 31, 2014 54,448,831
Second lien notes, net of discount of $847,947 at December 31, 2014 124,352,053
Total current liabilities 201,570,927 20,130,665
Long-term liabilities
Asset retirement obligation 16,397,804 12,649,458
Long-term debt, net of discount of $1,603,016 at December 31, 2013 178,196,984
Derivative liabilities 182,174
Total long-term liabilities 16,397,804 191,028,616
Commitment and contingencies (see notes)
Stockholders’ equity (deficit):
Common stock, $0.001 par value; 100,000,000 shares authorized 30,986,601 and 30,946,601 shares issued and outstanding at December 31, 2014 and 2013, respectively 30,987 30,947
Additional paid-in capital 78,754,854 78,165,364
Retained deficits (184,842,824 ) (40,931,799 )
Total stockholders’ equity (deficit) (106,056,983 ) 37,264,512
Total liabilities and stockholders’ equity (deficit) $ 111,911,748 $ 248,423,793
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME
For the Year Ended
December 31,
2014 2013
Revenues:
Oil and gas revenues $ 52,325,716 $ 68,696,055
Oil and gas hedging 1,550,871 (1,701,569 )
Other revenues 477,493 420,429
Total revenues 54,354,080 67,414,915
Operating Expense:
Lease operating expense 24,631,620 21,685,103
Workover expense 4,537,031 2,475,541
Exploration expense 706,904 900,255
Loss on plugging and abandonment 701,241
Depreciation, depletion and amortization 17,853,499 17,269,349
Impairment expense 107,774,206 2,179,075
Accretion expense 1,793,865 2,552,381
Gain on revision of asset retirement obligations (75,178 ) (564,719 )
General and administrative 9,549,430 9,253,600
Severance taxes 3,649,814 7,274,808
Arbitration loss 3,400,000
Total operating expenses 173,821,191 63,726,634
Operating income (loss) (119,467,111 ) 3,688,281
Other income (expense):
Interest income 48,328 16,197
Interest expense (24,302,387 ) (21,466,162 )
Total other expense (24,254,059 ) (21,449,965 )
Net loss before reorganization expenses and income taxes (143,721,170 ) (17,761,684 )
Reorganization expenses 2,319
Net loss before income taxes (143,721,170 ) (17,764,003 )
Income tax provision 189,855 8,630,456
Net loss $ (143,911,025 ) $ (26,394,459 )
Other Comprehensive Income
Unrealized gain on derivative instruments 171,086
Total comprehensive loss $ (143,911,025 ) $ (26,223,373 )
Net income per share:
Basic $ (4.65 ) $ (0.85 )
Diluted $ (4.65 ) $ (0.85 )
Weighted average number of common shares outstanding:
Basic 30,967,533 30,932,541
Diluted 30,967,533 30,932,541
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
Additional Other Total
Common Stock Paid-in Net Comprehensive Stockholders’
Shares Amount Capital (Loss) (Loss) Equity (Deficit)
Balance, December 31, 2012 30,905,101 $ 30,905 $ 77,140,451 $ (14,537,340 ) $ (171,086 ) $ 62,462,930
Common stock options exercised 6,500 7 9,938 9,945
Common stock warrants exercised 35,000 35 13,815 13,850
Stock-based employee compensation 1,001,160 1,001,160
Other comprehensive income 171,086 171,086
Net loss (26,394,459 ) (26,394,459 )
Balance, December 31, 2013 30,946,601 $ 30,947 $ 78,165,364 $ (40,931,799 ) $ $ 37,264,512
Common stock options exercised 40,000 40 61,160 61,200
Stock-based employee compensation 528,330 528,330
Net loss (143,911,025 ) (143,911,025 )
Balance, December 31, 2014 30,986,601 $ 30,987 $ 78,754,854 $ (184,842,824 ) $ $ (106,056,983 )
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended
December 31,
2014 2013
Cash flows from operating activities:
Net income (loss) $ (143,911,025 ) $ (26,394,459 )
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization 17,853,499 17,269,349
Impairment expense 107,774,206 2,179,075
Accretion expense 1,793,865 2,552,381
Amortization of debt issuance costs and debt discount 3,171,973 1,959,218
Unrealized (gain)loss on hedges (1,640,315 ) 1,019,932
Stock-based compensation 528,330 1,001,160
Loss on plugging and abandonment 701,241
Gain on revision of asset retirement obligations (75,178 ) (564,719 )
Deferred tax provision (benefit) 8,499,575
Changes in operating assets and liabilities:
Accounts receivable 2,979,764 5,671,586
Prepaids and other 1,656,870 1,735,926
Accounts payable 1,961,581 (3,419,534 )
Revenue and severance tax payable (1,043,583 ) (2,375,055 )
Payments to settle asset retirement obligations (1,229,042 )
Accrued liabilities 3,898,982 (1,058,909 )
Net cash provided (used) by operating activities (5,051,031 ) 7,547,725
Cash flows from investing activities:
Additions to oil and gas property (13,638,670 ) (29,776,182 )
Additions to other property and equipment (139,085 ) (97,556 )
Other assets (959,571 ) (1,157,161 )
Net cash used by investing activities (14,737,326 ) (31,030,889 )
Cash flows from financing activities:
Proceeds from issuance of common stock 61,200 23,795
Proceeds from long term debt 27,300,000
Repayment of short-term notes payable (1,615,826 ) (1,558,152 )
Debt issuance costs of long term debt (293,327 ) (2,037,402 )
Net cash provided (used) by financing activities (1,847,953 ) 23,728,241
Net increase (decrease) in cash and cash equivalents (21,636,310 ) 245,067
Cash and cash equivalents – beginning of period 32,547,380 32,302,313
Cash and cash equivalents – end of period $ 10,911,070 $ 32,547,380
Supplemental disclosures of cash flow information:
Cash paid for income taxes $ 157,355 $ 130,881
Cash paid for interest 19,765,423 19,815,440
Non-cash investing and financing activities:
Unrealized gain(loss) on derivative instruments $ $ 171,086
Accounts payable for oil and gas additions 920,824 1,551,937
Accrued liabilities for oil and gas additions 79,800
Revisions to asset retirement obligations 2,004,893 (6,509,866 )
Additions to asset retirement obligations 24,766 62,808
Prepaid insurance financed with debt 1,607,278 1,523,305
Senior secured notes exchanged for first lien notes 23,000,000

Proved Oil and Gas Reserves

Gas (Mcf) Oil (Bbls) Boe
For the year ended December 31, 2013
Beginning of year 52,918,300 8,406,600 17,226,317
Acquisition of reserves 8,834,500 1,268,000 2,740,417
Discoveries and extensions 3,011,500 261,200 763,116
Improved recovery
Revisions (15,569,000 ) (92,900 ) (2,687,733 )
Production (1,198,800 ) (603,600 ) (803,400 )
End of year 47,996,500 9,239,300 17,238,717
Proved developed reserves
Beginning of year 9,159,500 2,809,200 4,335,783
End of year 6,880,800 3,245,700 4,392,500
For the year ended December 31, 2014
Beginning of year 47,996,500 9,239,300 17,238,717
Acquisition of reserves
Discoveries and extensions
Improved recovery
Revisions (20,467,200 ) (2,935,300 ) (6,346,500 )
Production (950,100 ) (511,700 ) (670,050 )
End of year 26,579,200 5,792,300 10,222,167
Proved developed reserves
Beginning of year 6,880,800 3,245,700 4,392,500
End of year 5,204,700 2,898,500 3,765,950

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows:

(dollars in thousands) 2014 2013
Future cash inflows $ 704,959 $ 1,213,823
Future production costs (242,110 ) (297,786 )
Future development costs (167,409 ) (255,309 )
Future net cash flows before income taxes 295,440 660,728
Future income tax expense (35,150 ) (181,935 )
Future net cash flows before 10% discount 260,290 478,793
10% annual discount for estimating timing of cash flows (71,495 ) (178,003 )
Standardized measure of discounted future net cash flows $ 188,795 $ 300,790

Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves:

(dollars in thousands) 2014 2013
Beginning of year $ 300,790 $ 292,685
Sales of oil and gas produced, net of production costs (19,507 ) (37,261 )
Net change in prices and production costs (66,042 ) 33,720
Extension, discoveries, and improved recovery, less related costs 18,639
Development costs incurred during the year 2,938 8,230
Net change in estimated future development costs 5,194 13,418
Revisions of previous quantity estimates (209,654 ) (87,642 )
Net change from acquisitions of minerals in place 37,224
Net change in income taxes 89,473 4,235
Accretion of discount 41,075 40,688
Changes in timing and other 44,528 (23,146 )
End of year $ 188,795 $ 300,790

Non-GAAP Financial Measures

Discretionary Cash Flow is a non-GAAP financial measure.

The company defines Discretionary Cash Flow as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization excluding interest income, realized gains on out-of-period derivative contract settlements, (gain) loss on the sale of assets, acquisition costs, settlements for prior claims, other various non-cash items (including asset impairments, income from equity investments, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts), exploration and dry hole costs and costs associated with the company’s bankruptcy.

Discretionary Cash Flow is a supplemental financial measure used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities. Discretionary cash flow should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”). Discretionary cash flow excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s Discretionary Cash Flow may not be comparable to similarly titled measures used by other companies.

The table below reconciles the most directly comparable GAAP financial measure to Discretionary Cash Flow.

For the Three Months Ended For the Twelve Months Ended
December 31, December 31,
2014 2013 2014 2013
Net income (loss) as reported $ (118,695,917 ) $ (17,293,687 ) $ (143,911,025 ) $ (26,394,459 )
Depreciation, depletion and amortization 5,763,586 1,478,895 17,853,499 17,269,349
Impairment expense 107,774,206 107,774,206 2,179,075
Income tax expense (benefit) 12,794,728 8,499,575
Exploration expense 59,305 153,290 706,904 900,255
Loss on plugging and abandonment (25,798 ) 701,241
Accretion expense 448,466 638,090 1,793,865 2,552,381
Gain on revision of asset retirement obligation (75,178 ) (564,719 ) (75,178 ) (564,719 )
Stock based compensation 108,218 231,734 528,372 1,001,160
Debt issuance costs and discount 881,184 586,270 3,171,973 1,959,218
Arbitration loss 3,400,000
Unrealized (gain) loss on hedges (47,014 ) 1,310,600 (1,640,315 ) 1,019,932
Discretionary Cash Flow $ (3,783,144 ) $ (690,597 ) $ (10,397,699 ) $ 9,123,008

EBITDAX is a non-GAAP financial measure.

The company defines EBITDAX as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization excluding interest income, realized gains on out-of-period derivative contract settlements, (gain) loss on the sale of assets, acquisition costs, settlements for prior claims, other various non-cash items (including asset impairments, income from equity investments, noncontrolling interest, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts), exploration and dry hole costs and costs associated with the company’s bankruptcy.

EBITDAX is a supplemental financial measure used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses this measure because EBITDAX allows the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. EBITDAX should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles (“GAAP”). EBITDAX excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s EBITDAX may not be comparable to similarly titled measures used by other companies.

The table below reconciles the most directly comparable GAAP financial measure to EBITDAX:

For the Three Months Ended For the Twelve Months Ended
December 31, December 31,
2014 2013 2014 2013
Net income (loss) as reported $ (118,695,917 ) $ (17,293,687 ) $ (143,911,025 ) $ (26,394,459 )
Depreciation, depletion and amortization 5,763,586 1,478,895 17,853,499 17,269,349
Impairment expense 107,774,206 107,774,206 2,179,075
Income tax expense (benefit) 33,795 12,827,370 189,855 8,630,456
Exploration expense 59,305 153,290 706,904 900,255
Loss on plugging and abandonment (25,798 ) 701,241
Accretion expense 448,466 638,090 1,793,865 2,552,381
Gain on revision of asset retirement obligation (75,178 ) (564,719 ) (75,178 ) (564,719 )
Stock based compensation 108,218 231,734 528,372 1,001,160
Interest expense, net 6,146,957 5,571,509 24,254,059 21,449,965
Reorganization costs 2,319
Arbitration loss 3,400,000
Unrealized (gain) loss on hedges (47,014 ) 1,310,600 (1,640,315 ) 1,019,932
EBITDAX $ 1,516,424 $ 4,327,284 $ 10,874,242 $ 28,746,955

PV10 is the estimated present value of the future net revenues from proved oil and natural gas reserves before income taxes, discounted using a 10% discount rate. PV 10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. Saratoga believes that PV10 is an important measure that can be used to evaluate the relative significance of its oil and natural gas properties and that PV10 is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. Saratoga believes that most other companies in the oil and natural gas industry calculate PV10 on the same basis. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows, but without deducting income taxes.