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 at www.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.
Saratoga Resources, Inc.Thomas CookeChairman/Chief Executive
OfficerorAndrew CliffordPresidentorRandal McDonald,
713-458-1560Vice President – Finance and
Accountingwww.saratogaresources.com