Saratoga Resources, Inc. (NYSE MKT: SARA; the “Company” or
“Saratoga”) today announced financial and operating results for the
quarter and year-ended December 31, 2013.
Key Financial Results
Year-Ended 2013
- Production of 803,400 barrels of oil
equivalent, or 2,201 barrels of oil equivalent per day, for 2013,
down 28% from 2012;
- Oil and gas revenues of $68.7 million
for 2013 compared to $82.5 million for 2012;
- Discretionary cash flow of $9.1
million, or $0.29 per fully diluted share, for 2013 compared to
$29.3 million, or $1.00 per fully diluted share, for 2012;
- EBITDAX of $28.7 million for 2013
compared to $45.7 million for 2012;
- Operating income of $3.7 million, or
$0.12 per fully diluted shares, for 2013 compared to operating
income of $12.3 million, or $0.42 per fully diluted share, for
2012; and
- Net loss of $(26.4) million, or $(0.85)
per fully diluted share, as compared to $(3.7) million, or $(0.13)
per fully diluted share, for 2012.
Fourth Quarter
- Oil and gas revenues of $14.5 million
for fourth quarter 2013 compared to $22.9 million for fourth
quarter 2012;
- Discretionary cash flow of $(0.7)
million, or $(0.02) per fully diluted share, for fourth quarter
2013 compared to discretionary cash flow of $9.7 million, or $0.31
per fully diluted share, for fourth quarter 2012;
- EBITDAX of $4.3 million for fourth
quarter 2013 compared to $13.8 million for fourth quarter 2012;
and
- Net loss of $(17.3) million, or $(0.56)
per fully diluted share, for fourth quarter 2013 compared to $(2.9)
million, or $(0.09) per fully diluted share, for fourth quarter
2012.
Discretionary cash flow, EBITDAX, net asset value per share, and
PV-10 are non-GAAP financial measures and are defined and
reconciled to the most directly comparable GAAP measure under
“Non-GAAP Financial Measures” below.
The net loss for the year reflects the substantial decline in
production volumes together with non-cash charges totaling $11.7
million, or $0.38 per share, consisting of hedging losses of $1.0
million, an impairment loss of $2.2 million and a tax provision of
$8.5 million as a result of fully reserving against the net
deferred tax asset. The hedging loss for the quarter and year
totaled $1.7 million and included $1.0 million in non-cash charges
attributable to the failure of certain hedges (HLS and LLS
production hedged against Brent pricing) to satisfy U.S. GAAP
requirements for correlation between product pricing and benchmark
prices. The impairment loss was a non-cash charge related to the
expiration of the Little Bay lease which was required to be
recognized under GAAP despite the fact that substantially the same
acreage was subsequently re-leased, recouping substantially all
associated reserves, shortly after the lease expiration at a cost
of less than $100,000. The tax provision reflected the
determination to fully reserve against a net deferred tax asset in
the amount of $13.8 million. Net operating losses totaling $73.9
million remain available for use against future taxable income.
The change in revenues for the 2013 quarter and year reflects a
decrease in production volumes (down 28.0% year over year)
partially offset by higher average realized oil and natural gas
prices. The decrease in production reflects a 10.8% decline in oil
volumes and a 54.6% decline in natural gas volumes. The decline in
production was attributable to multiple field operating issues,
principally arising from low gas volumes available for gas lift in
Grand Bay and Main Pass 25 fields, flow line restrictions and
facility repairs in Main Pass 46 Field and third party product
handling issues and platform shut-ins due to construction projects
in Main Pass 25 Field; all, partially offset by production from new
drills during 2013.
For the full year, the decline in operating income and
profitability was partially offset by a decline in operating
expenses, reflecting, among other items, (i) decreased workover
expense (down $1.4 million, or 35.3%), reflecting decreased
workover activity; (ii) decreased loss on plugging and abandonment
(down $1.8 million, or 71.6%), reflecting a lower level of P&A
expenses in excess of estimates during 2013; (iii) lower
depreciation, depletion and amortization expense (down $10.1
million, or 37%), reflecting lower production volumes during 2013;
and (iv) decreased severance taxes (down $0.5 million, or 6.4%),
resulting from lower production volumes; all partially offset by
(v) increased lease operating expenses (up $2.4 million, or 12.3%),
reflecting one-time non-recurring expenses associated with the
salvage of a barge in Little Bay, regulatory compliance charges
relating to Grand Bay and cleaning of a flowline in Main Pass 46;
(vi) increased exploration expense (up $0.4 million, or 64.5%),
reflecting increased delay rentals associated with the acquisition
of Gulf of Mexico leases and field study expense in the Gulf of
Mexico and Grand Bay; (vii) increased accretion expense (up $1.0
million, or 69%), reflecting an upward revision in asset retirement
obligation (“ARO”) recorded during 2012; and (viii) increased
general and administrative expense (up $0.7 million, or 7.8%),
reflecting increased contract and reserve engineering fees, legal
costs and employee recruiting fees partially offset by lower stock
based compensation and bonuses.
Operational Highlights
Operational highlights for 2013 included:
- 4 development wells, 17 recompletions
and 9 workovers successfully completed;
- completion of first horizontal
well;
- 90 gross (89 net) wells in production
at December 31, 2013;
- acquisition of 19,814 acres of Gulf of
Mexico leases, including 2,740 Mboe of proved reserves; and
- 52,103 gross/net acres in 12 fields
under lease at December 31, 2013.
During 2013, Saratoga drilled 4 successful development wells,
the “Buddy” well in Grand Bay Field, the “Roux Toux” well in Main
Pass 47 Field, and the “Rocky” and “Zeke” wells in Breton Found 32
Field. The Rocky well was Saratoga’s first horizontal well.
Saratoga also undertook 22 recompletions and 10 workovers during
the year. Seventeen of the 22 recompletions and 9 of the 10
workovers were successful.
Production Highlights
- Oil and gas production of 142.5
thousand barrels of oil (“MBO”) and 138.2 million cubic feet of gas
(“MMCFG”), or 165.6 thousand barrels of oil equivalent (“MBOE”)
(86% oil) in Q4 2013, and 603.6 MBO and 1,198.8 MMCFG, or 803.4
MBOE (75% oil) for 2013, down 28% from 1,116.3 MBOE in 2012.
The decrease in production during 2013 reflects operating issues
across multiple fields. During Q4 and continuing into Q1 2014, a
bottom up review of field operations was commenced to diagnose and
remedy field operating issues weighing on production. Saratoga
brought in outside consultants and Saratoga’s CEO spent a
substantial amount of time in the field observing first hand
operations. That review confirmed some of management’s original
beliefs regarding operational issues in the field and revealed a
few issues that were previously unknown. Most notable among the
issues identified were an ongoing inadequacy of gas lift gas to
support production in the field and certain personnel issues that
have directly impacted run times. As a result of such review,
Saratoga focused much of its recompletion and workover program in
Q4 and into Q1 2014 on restoring gas production levels to provide
an adequate supply of gas to support gas lift needs. Management
believes that by the end of Q1 2014 gas supplies had been increased
to a level adequate to support gas lift requirements. On the
personnel front, Saratoga has made numerous personnel changes in
the field and is continuing to evaluate performance of select
personnel to assure that field personnel have both the requisite
expertise and commitment to maintain optimal well performance
across all fields. As a result of increased gas lift supply and
personnel changes in the field, by late Q1 2014, run times in the
field had increased and production levels had stabilized and begun
to climb.
Reserve Highlights
- Year-end 2013 SEC proved reserves
consisted of 9.239 million barrels of oil (“MMBO”) and 47.997
billion cubic feet of gas (“BCFG”), or 17.239 million barrels of
oil equivalent (“MMBOE”), up marginally from 17.226 MMBOE of proved
reserves at year-end 2012;
- Oil represents 53.6% of year-end 2013
1P reserves;
- Year-end 2013 PV10 of $410.8 million,
up 0.9% from $407 million at year-end 2012;
- Proved developed reserves comprised
25.5% of year-end 2013 proved reserves;
- Year-end 2013 probable reserved totaled
6.9 MMBO and 59.5 BCFG, or 16.8 MMBOE;
- Year-end 2013 possible reserves totaled
19.0 MMBO and 124.4 BCFG, or 39.7 MMBOE;
- Year-end 2013 3P reserves totaled
73.739 MMBOE.
Year-end 2013 reserves reflect production of 803.4 Mboe during
the year as well as the addition of 3,503.5 Mboe of proved
undeveloped reserves associated with the acquisition of new leases
in the state waters of Louisiana and in the Gulf of Mexico and the
reclassification of 2,439.0 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 53 proved developed
non-producing (“PDNP”) opportunities in 33 wellbores in 6
fields;
- Development of proved undeveloped
(“PUD”) reserves from inventory of 88 PUD opportunities in 24
wellbores in 7 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 proved undeveloped
opportunities and conversion of PDNP opportunities. At December 31,
2013, 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, the first of which is expected to be
a second horizontal well planned for Q2 2014. Present development
plans are expected to be similar to those undertaken during 2013 in
terms of both number of wells and capex.
In order to advance development plans with respect to its
inventory of deep and ultra-deep prospects, including advancing
discussions with potential partners beyond general discussions,
Saratoga has additionally tasked its expanded professional staff
with developing exhaustive analyses and marketing materials to
support a full professional marketing plan to identify, and secure,
potential drilling partners. Those efforts are expected to lead to
commencement of a formal marketing plan to potential partners
during Q2 2014.
Financial Position and CAPEX Highlights
- $32.5 million of cash on hand at
December 31, 2013, up from $32.3 million at December 31, 2012;
- $37.3 million of shareholders’ equity
at December 31, 2013;
- $25.3 million of new debt raised during
2013;
- $27.3 million of debt refinanced during
2013, lowering interest from 12½% to 10% and eliminating prepayment
premiums;
- $31.4 million of CAPEX for 2013;
- 2014 CAPEX budget expected to be fully
funded by cash on hand and projected operating cash flow;
- Working capital adjusted debt to
trailing twelve month EBITDAX of 5.5 times; and
- Net asset value per share (based on
working capital adjusted PV-10) of approximately $8.11.
Saratoga supplemented its liquidity through the sale of $27.3
million of 10% senior first lien notes with no prepayment premiums.
Supplemented by proceeds of the 2013 debt offering, Saratoga
expects to fully fund its 2014 development budget through cash on
hand and projected operating cash flow. The 2014 CAPEX budget is
expected to be roughly equal to that of 2013. Saratoga also issued
an additional $27.3 million of 10% senior first lien notes to
retire a like amount of outstanding 12½% secured notes which
included prepayment premiums that were eliminated in the
refinancing.
Management Comments
Thomas Cooke, Chairman and CEO, commented, “2013 saw some
exciting developments for Saratoga as well as challenging issues at
the field operating level. The net result of such developments was
disappointing financial performance for the year but, we believe,
tangible progress in addressing difficult and lingering issues in
the field which we expect will allow us to improve run times in the
field and renew stable and growing production levels.
Highlighting our efforts during 2013 were the drilling of our
first horizontal well, Rocky, and our first high angle well, Zeke.
2013 also saw success in lease acquisitions with the addition of
19,814 acres in the Gulf of Mexico including four identified
prospects containing 2,740.0 Mboe of proved reserves and 1,070
acres in state waters of Louisiana including two prospects
containing 763.0 Mboe of proved reserves.
We also are excited about a number of additions to our
professional staff as well as personnel changes at the field level.
We are seeing positive results from those additions in terms of
improving field performance and upgraded capabilities in prospect
analysis, selection and planning. We expect those additions, along
with other initiatives to result in ongoing improvements in the
field and improved performance in our development drilling
program.
I personally have spent substantial time in the field in recent
months to observe first hand performance and issues that have
resulted in production being below expected levels. With the
addition of gas lift supplies to meet our needs for the foreseeable
future and personnel changes in the field, we are beginning to see
improved run times and resulting stabilization and increases in
production rates that we expect to see flow through our operating
results by the second quarter of 2014.
With expected improvements in production and operating results
and cash on hand to support our development plans, we are
optimistic that initiatives taken in recent months will produce
improved performance in 2014.”
Conference Call Information
The company will host a conference call to discuss these results
on April 1, 2014 at 10:30 AM EDT (9:30 AM CDT, 7:30 AM PDT) and
interested parties in the U.S. can participate in the call by
dialing (866) 501-1535. Interested international parties can
participate in the call by dialing (216) 672-5582. The participant
passcode for both the U.S. and international call is 17109721.
Alternatively, the audio content of the call can be accessed on the
Company’s web site at www.saratogaresources.com. The call will be
archived on the Company web site for parties who are unable to
listen to the live call.
About Saratoga Resources
Saratoga Resources is an independent exploration and production
company with offices in Houston, Texas and Covington, Louisiana.
Principal holdings cover 52,103 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 and grow reserves, production, revenues and
profitability, ability to reach and sustain target production
levels, 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, 2013 2012
ASSETS Current assets: Cash and cash equivalents $
32,547,380 $ 32,302,313 Accounts receivable 6,758,572 12,430,158
Prepaid expenses and other 1,056,350 1,268,971 Other current assets
150,000 150,000 Total current assets
40,512,302 46,151,442 Property and equipment: Oil and gas
properties - proved (successful efforts method) 286,441,663
260,916,084 Other 892,694 795,138
287,334,357 261,711,222 Less: Accumulated depreciation, depletion
and amortization (101,088,696 ) (81,640,272 ) Total
property and equipment, net 186,245,661 180,070,950 Deferred
tax asset, net - 8,499,575 Other assets, net 21,665,830
19,929,394 Total assets $ 248,423,793 $
254,651,361
LIABILITIES AND STOCKHOLDERS'
EQUITY Current liabilities: Accounts payable $ 5,391,648 $
7,259,244 Revenue and severance tax payable 3,754,812 6,129,867
Accrued liabilities 9,807,935 10,787,044 Derivative liabilities –
short term 837,758 171,086 Short-term notes payable 338,512 373,360
Asset retirement obligation – current -
256,200 Total current liabilities 20,130,665 24,976,801
Long-term liabilities Asset retirement obligation 12,649,458
16,815,736 Long-term debt, net of discount of $1,603,016 and
$2,104,106, respectively 178,196,984 150,395,894 Derivative
liabilities 182,174 - Total long-term
liabilities 191,028,616 167,211,630 Commitment and
contingencies (see notes) Stockholders' equity: Common
stock, $0.001 par value; 100,000,000 shares authorized 30,946,601
and 30,905,101 shares issued and outstanding at December 31, 2013
and 2012, respectively 30,947 30,905 Additional paid-in capital
78,165,364 77,140,451 Accumulated other comprehensive loss -
(171,086 ) Retained earnings (40,931,799 )
(14,537,340 ) Total stockholders' equity 37,264,512
62,462,930 Total liabilities and
stockholders' equity $ 248,423,793 $ 254,651,361
Saratoga Resources, Inc. CONSOLIDATED STATEMENTS
OF OPERATIONS AND OTHER COMPREHENSIVE INCOME
For the Year Ended December 31, 2013
2012 Revenues: Oil and gas revenues $ 68,696,055 $
82,528,932 Oil and gas hedging (1,701,569 ) 72,078 Other revenues
420,429 1,411,465 Total revenues
67,414,915 84,012,475 Operating Expense: Lease operating
expense 21,685,103 19,317,283 Workover expense 2,475,541 3,828,197
Exploration expense 900,255 547,192 Loss on plugging and
abandonment 701,241 2,468,969 Dry hole costs - 93,353 Depreciation,
depletion and amortization 17,269,349 27,407,700 Impairment expense
2,179,075 401,752 Accretion expense 2,552,381 1,510,165 Gain on
revision of asset retirement obligations (564,719 ) (245,007 )
General and administrative 9,253,600 8,584,486 Severance taxes
7,274,808 7,768,426 Total
operating expenses 63,726,634 71,682,516
Operating income 3,688,281 12,329,959 Other
income (expense): Interest income 16,197 32,433 Interest expense
(21,466,162 ) (17,651,496 ) Financing expense -
(7,527 ) Total other expense (21,449,965 )
(17,626,590 ) Net income (loss) before reorganization
expenses and income taxes (17,761,684 ) (5,296,631 ) Reorganization
expenses 2,319 161,416 Net income
(loss) before income taxes (17,764,003 ) (5,458,047 ) Income tax
provision (benefit) 8,630,456 (1,750,418 ) Net
income (loss) $ (26,394,459 ) $ (3,707,629 ) Other
Comprehensive income(loss) Unrealized gain (loss) on derivative
instruments 171,086 (171,086 ) Total
comprehensive income (loss) $ (26,223,373 ) $ (3,878,715 )
Net income (loss) per share: Basic $ (0.85 ) $ (0.13 ) Diluted $
(0.85 ) $ (0.13 ) Weighted average number of common shares
outstanding: Basic 30,932,541 29,378,542
Diluted 30,932,541 29,378,542
Saratoga Resources, Inc. CONSOLIDATED STATEMENTS
OF STOCKHOLDERS’ EQUITY (DEFICIT)
Additional Net Other
Total Common Stock Paid-in Income
Comprehensive Stockholders’ Shares
Amount Capital (Loss) (Loss) Equity
(Deficit) Balance, December 31, 2011 26,714,815 $ 26,714
$ 52,674,252 $ (10,829,711 ) $ - $ 41,871,255 Common stock
options exercised 208,599 209 405,047 - - 405,256 Common
stock warrants exercised 892,327 892 4,460,743 - - 4,461,635
Common stock issued in private placement 3,089,360 3,090 18,394,490
- - 18,397,580 Stock-based employee compensation - -
1,205,919 - - 1,205,919 Other comprehensive loss - - - -
(171,086 ) (171,086 ) Net loss - - -
(3,707,629 ) - (3,707,629 ) 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
Saratoga Resources,
Inc. CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2013
2012 Cash flows from operating activities: Net income (loss)
$ (26,394,459 ) $ (3,707,629 ) Adjustments to reconcile net income
(loss) to net cash used in operating activities: Depreciation,
depletion, amortization and impairment 19,448,424 27,809,452
Accretion expense 2,552,381 1,510,165 Amortization of debt issuance
costs and debt discount 1,959,218 1,304,362 Unrealized (gain)loss
on hedges 1,019,932 - Dry hole costs - 93,353 Stock-based
compensation 1,001,160 1,205,919 Loss on plugging and abandonment
701,241 2,468,969 Gain on revision of asset retirement obligations
(564,719 ) (245,007 ) Deferred tax provision (benefit) 8,499,575
(1,951,613 ) Changes in operating assets and liabilities: Accounts
receivable 5,671,586 (1,890,401 ) Prepaids and other 1,735,926
1,605,661 Accounts payable (3,419,534 ) 180,923 Revenue and
severance tax payable (2,375,055 ) 420,094 Payments to settle asset
retirement obligations (1,229,042 ) (3,062,625 ) Accrued
liabilities (1,058,909 ) 2,002,499 Net cash
provided (used) by operating activities 7,547,725 27,744,122
Cash flows from investing activities: Additions to oil and gas
property (29,776,182 ) (57,096,363 ) Additions to other property
and equipment (97,556 ) (137,025 ) Other assets (1,157,161 )
944,305 Net cash used by investing activities
(31,030,899 ) (56,289,083 ) Cash flows from financing
activities: Proceeds from issuance of common stock 23,795
23,264,470 Proceeds from long term debt 27,300,000 24,645,000
Repayment of short-term notes payable (1,558,152 ) (1,656,122 )
Debt issuance costs of long term debt (2,037,402 )
(1,280,754 ) Net cash provided (used) by financing activities
23,728,241 44,972,594 Net
increase (decrease) in cash and cash equivalents 245,067 16,427,633
Cash and cash equivalents - beginning of period 32,302,313
15,874,680 Cash and cash equivalents - end of
period $ 32,547,380 $ 32,302,313 Supplemental
disclosures of cash flow information: Cash paid for income taxes $
130,881 $ 201,195 Cash paid for interest 19,815,440 8,011,117
Non-cash investing and financing activities: Unrealized
gain(loss) on derivative instruments $ 171,086 $ (171,086 )
Accounts payable for oil and gas additions 1,551,937 2,479,787
Accrued liabilities for oil and gas additions 79,800 332,891
Revisions to asset retirement obligations (6,509,866 ) 4,572,244
Asset retirement obligations acquired 62,808 181,318 Prepaid
insurance financed with debt 1,523,305 1,685,226 Senior secured
notes exchanged for first lien notes 27,300,000 -
Proved Oil and Gas Reserves
Gas (Mcf) Oil (Bbls)
Boe For the year ended December 31, 2012 Beginning of year
65,961,600 7,975,000 18,968,602 Acquisition of reserves - - -
Discoveries and extensions - - - Improved recovery - - - Revisions
(10,403,800 ) 1,108,000 (625,968 ) Production (2,639,500 ) (676,400
) (1,116,317 ) End of year 52,918,300 8,406,600 17,226,317 Proved
developed reserves Beginning of year 10,101,000 2,580,600 4,264,100
End of year 9,159,500 2,809,200 4,335,783 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
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)
2013 2012
2011 Future cash inflows $ 1,213,823 $ 1,102,848 $ 1,210,125
Future production costs (297,786) (258,251) (281,429) Future
development costs (255,309) (232,806)
(226,552) Future net cash flows before income taxes 660,728 611,791
702,144 Future income tax expense (181,935) (171,671)
(207,555) Future net cash flows before 10% discount 478,793
440,120 494,589 10% annual discount for estimating timing of cash
flows (178,003) (147,435) (163,705)
Standardized measure of discounted future net cash flows $ 300,790
$ 292,685 $ 330,884
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)
2013 2012
2011 Beginning of year $ 292,685 $ 330,884 $ 235,657 Sales
of oil and gas produced, net of production costs (37,261) (51,615)
(49,945) Net change in prices and production costs 33,720 (2,218)
108,942 Extension, discoveries, and improved recovery, less related
costs 18,639 - 16,128 Development costs incurred during the year
8,230 20,993 7,088 Net change in estimated future development costs
13,418 (19,437) 7,493 Revisions of previous quantity estimates
(87,642) (20,211) 37,107 Net change from acquisitions of minerals
in place 37,224 - 16,861 Net change in income taxes 4,235 19,232
(53,119) Accretion of discount 40,688 46,431 31,597 Changes in
timing and other (23,146) (31,374) (26,925)
End of year $ 300,790 $ 292,685 $ 330,884
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,
2013 2012 2013 2012
Net income (loss) as reported $ (17,293,687) $
(2,873,847) $ (26,394,459) $ (3,707,629) Depreciation, depletion
and amortization 1,478,895 13,237,168 17,269,349 27,407,700
Impairment expense - 357,476 2,179,075 401,752 Income tax expense
(benefit) 12,794,728 (1,550,947) 8,499,575 (1,951,613) Exploration
expense 153,290 177,773 900,255 547,192 Loss on plugging and
abandonment (25,798) - 701,241 2,468,969 Dry hole costs - - -
93,353 Accretion expense 638,090 (156,347) 2,552,381 1,510,165 Gain
on revision of asset retirement obligation (564,719) (245,007)
(564,719) (245,007) Stock based compensation 231,734 165,792
1,001,160 1,205,919 Debt issuance costs and discount 586,270
363,385 1,959,218 1,304,362 Unrealized (gain) loss on hedges
1,310,600 - 1,019,932 - Other income – prior acquisition adj. -
225,900 - 225,900 Discretionary Cash Flow $ (690,597) $ 9,701,346 $
9,123,008 $ 29,261,063
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, non-controlling 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,
2013 2012 2013 2012
Net income (loss) as reported $ (17,293,687) $ (2,873,847) $
(26,394,459) $ (3,707,629) Depreciation, depletion and amortization
1,478,895 13,237,168 17,269,349 27,407,700 Impairment expense -
357,476 2,179,075 401,752 Income tax expense (benefit) 12,827,370
(1,536,522) 8,630,456 (1,750,418) Exploration expense 153,290
177,773 900,255 547,192 Loss on plugging and abandonment (25,798) -
701,241 2,468,969 Dry hole costs - - - 93,353 Accretion expense
638,090 (156,347) 2,552,381 1,510,165 Gain on revision of asset
retirement obligation
(564,719)
(245,007)
(564,719)
(245,007)
Stock based compensation 231,734 165,792 1,001,160 1,205,919
Interest expense, net 5,571,509 4,588,458 21,449,965 17,626,590
Reorganization costs - 39,888 2,319 161,416 Unrealized (gain) loss
on hedges 1,310,600 - 1,019,932 -
EBITDAX $ 4,327,284 $ 13,754,832 $ 28,746,955 $ 45,720,002
Net Asset Value is a non-GAAP financial measure.
The company defines Net Asset Value per Share, NAV, as the per
share value of the PV-10 value of its reserves plus working capital
less long-term debt. Net Asset Value Per Share 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 net value
of its tangible assets less liabilities. Net Asset Value per Share
assumes no future re-investment to find or acquire new reserves and
that a company stops operating once its reserves are depleted. Net
Asset Value Per Share should not be considered as a substitute for
any other measure of financial performance or liquidity presented
in accordance with generally accepted accounting principles
(“GAAP”). Net Asset Value per Share excludes certain intangible and
other assets and certain liabilities that may affect the realized
in the event of liquidation. Therefore, the company’s Net Asset
Value per Share may not be comparable to similarly titled measures
used by other companies.
12/31/2013 In Thousands (except per share amount)
PV-10 $ 410,754 Working capital 20,382 Long-term Debt (179,800 )
Net Asset Value 251,336 Shares Outstanding, Fully Diluted
30,981 Net Asset Value per share $ 8.11
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. PV10 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.Brad Holmes, 713-654-4009Investor
RelationsAndrew Clifford, 713-458-1560PresidentJohn Ebert,
985-809-9292Vice President – Finance and Business
Developmentwww.saratogaresources.com