Saratoga Resources, Inc. (NYSE MKT: SARA; the “Company” or
“Saratoga”) today announced financial and operating results for the
quarter ended September 30, 2013.
Key Financial Results
- Oil revenue of $16.3 million for Q3
2013 compared to $14.2 million for Q3 2012;
- Gas revenue of $0.9 million for Q3 2013
compared to $2.2 million for Q3 2012;
- Discretionary cash flow of $1.8
million, or $0.06 per fully diluted share, for Q3 2013 compared to
discretionary cash flow of $4.4 million, or $0.14 per fully diluted
share, for Q3 2012;
- EBITDAX of $6.7 million for Q3 2013
compared to $8.5 million for Q3 2012;
- Operating loss of $(3.0) million, or
$(0.10) per fully diluted share, for Q3 2013 compared to operating
income of $3.8 million, or $0.12 per fully diluted share, for Q3
2012; and
- Net loss of $(5.7) million, or $(0.19)
per fully diluted share, for Q3 2013 compared to net loss of $(0.5)
million, or $(0.02) per fully diluted share, for Q3 2012.
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.
Oil and gas revenues totaled $17.2 million, up $0.7 million or
4.5% from the third quarter 2012. The increase in oil and gas
revenues reflects a 15.1%, or $2.1 million, increase in oil revenue
and a 62.2%, or $1.4 million, decline in gas revenue. The increase
in oil revenues was attributable to a 9.2% increase in oil
production and a 5.4% increase in average price. The decrease in
natural gas revenues was attributable to a 66.3% decrease in
natural gas production, partially offset by a 12.6% increase in
average price.
The increase in oil and gas revenues during the quarter was
offset by a $0.7 million increase in hedging losses and a $0.3
million decline in other revenues resulting in a $0.2 million, or
1.4%, decline in total revenues for the quarter.
The operating loss for the quarter reflected the slight decline
in total revenues ($0.2 million) and a $6.7 million increase in
operating costs during the quarter. Included in the increase in
operating costs for the quarter were a $2.2 million increase in
non-cash impairment expenses associated with the loss of the
company’s Little Bay lease when the Company opted to release the
operating agreement and a $0.7 million loss on P&A associated
with unusual conditions encountered in a high pressure well plugged
in Vermilion 16 field. In addition to the impairment loss
associated with termination of the Little Bay lease, the Company’s
lease operating expenses reflect a $0.4 million loss associated
with a barge removal in Little Bay field. An insurance claim has
been filed with respect to the barge removal operation which may
allow the Company to recoup a portion of the removal cost. The
Company has since re-nominated and bid on a larger acreage position
including the Little Bay lease and additional prospects.
Other increases in operating expense included a $0.6 million
increase in lease operating expense associated with chemically
treating and cleaning sales lines and flow lines; a $0.5 million
increase in workover expense reflecting increased workover
activity; a $0.2 million increase in exploration expense reflecting
delay rentals associated with new leases and increased field study
activities; a $1.3 million increase in DD&A expense associated
with increased capital expenditures late in 2012 and into 2013; a
$0.4 million increase in G&A expense associated with retention
of reservoir engineering consultants and increased headcount; and a
$0.4 million increase in severance taxes associated with a reduced
number of inactive wells qualifying for certain Louisiana severance
tax exemptions.
The net loss for the 2013 quarter reflected the decrease in
operating income together with higher interest cost (up $1.0
million), as a result of our add-on note offering closed in late
2012 and partially offset by an increased tax benefit (up $2.6
million).
Operational Highlights
Operational highlights for third quarter 2013 included:
- 2 development wells completed;
- 9 recompletions undertaken, 6 of which
were successful and 1 of which was in progress at quarter end. 3 of
the 6 successful recompletions were in our tubing replacement
program;
- 3 successful workovers completed,
including 1 well in our tubing replacement program;
- Plugged and abandoned one high pressure
legacy well;
- 94 gross (93 net) wells in production
at September 30, 2013;
- Federal Gulf of Mexico leases awarded
in July 2013, covering 19,814 acres;
- Louisiana state leases awarded in
September 2013, covering 857.96 acres in Breton Sound 18, 19 and
32; and
- 51,890 gross/net acres, 60% of which
were held by production without near-term lease expirations, across
10 fields at September 30, 2013.
The Rocky well targeted an elongated ridge, offsetting the SL
1227 #21 and #22 wells in the 5,800’ sand, which is the main
producing reservoir in the Breton Sound 32 field. A seventy-degree
pilot hole was drilled followed by a sidetrack with a 750’ lateral
completion. This well was our first horizontal well. The Rocky well
had an IP rate of gross 600 BOPD, 120 MCFPD on a 16/64” choke with
650# FTP (net 508 BOEPD).
The Zeke also targeted the same 5,800’ sand but in a separate
structure to the south-east and was completed as a high angle (82
degrees) directional. The Zeke well also established a previously
unbooked uphole recompletion opportunity in the overlying 5,750’
sand, which also produces within the field. The Zeke well had an IP
rate of gross 312 BOPD, 89 MCFPD on a 38/64” choke with 480# FTP
(net 268 BOEPD).
During Q3 2013, we undertook 9 recompletions, 6 of which were
successful and 1 of which was in progress at quarter end, and 3
workovers, all of which were successful.
Plugging and abandonment operations were completed on a
non-producing high pressure well in Vermilion 16.
Production Highlights
- Oil and gas production of 151 thousand
barrels of oil (“MBO”) and 187 million cubic feet of gas (“MMCFG”),
or 182 thousand barrels of oil equivalent (“MBOE”) (82.9% oil), in
Q3 2013, down 21.2% from 230 MBOE (59.9% oil) in Q3 2012 and down
19.4% from Q2 2013; and
- Oil and gas production of 461 MBO of
oil and 1,061 MMCFG of gas, or 638 MBOE (72.3% oil), for the 2013
nine months period, down 20.9% from 807 MBOE (60.0% oil) for the
2012 nine month period.
The decrease in total production for the quarter and nine months
was primarily attributable to declines in natural gas production
and, for the nine months, a decline in oil production. Oil
production, while up 9.2% for the quarter, was down 4.7% for the
nine month period. Natural gas production was down 66.3% for the
quarter and 45.3% for the nine month period.
The decrease in oil production for the nine month period was
principally attributable to flow line problems experienced in Main
Pass 46 Field, a shut-in in Main Pass 25 Field during construction
projects and natural reservoir decline. For the quarter, the
increase in oil production reflects the addition of production from
the North Tiger well during the fourth quarter of 2012 and the
addition of production for a portion of the quarter from the Rocky
and Zeke wells.
The decrease in natural gas production, for both the quarter and
nine months, reflects natural reservoir declines and, for several
wells, mechanical and third party issues. Mechanical and third
party issues effecting natural gas production included flow line
problems in Main Pass 46 Field which also impacted oil production,
work undertaken in Breton Sound 18/32 and the undertaking of a
recompletion in the 6200’ sand in the Company’s Four Corners SL
20034 #1 well in Main Pass 46 with the depletion of the 6100’
sand.
Development Plans
- Low risk recompletions, thru-tubing
plugbacks and workovers from inventory of approximately 60 proved
developed non-producing (“PDNP”) opportunities in 7 fields;
- Development of proved undeveloped
(“PUD”) reserves from inventory of approximately 84 PUD
opportunities in 26 wellbores in 4 fields;
- Production enhancement program (“PEP”)
initiated to restore curtailed and shut-in production from
inventory of approximately 20 wells in Grand Bay and Breton Sound
32 fields; 9 wells in PEP program completed to date; and
- Strategic partnerships and joint
ventures for risk-sharing on exploratory drilling of deep and
ultra-deep prospects at Grand Bay and Vermilion 16 and on new
Central Gulf of Mexico leases.
Our near term development plans continue to focus on proved
undeveloped opportunities and conversion of PDNP opportunities.
With our increased emphasis on field studies to identify prime
prospects within our holdings and recent successes in several
fields, and in particular in our horizontal and high angle drilling
projects, we intend to focus on bringing forward development
prospects with similar characteristics to our proven successes,
particularly horizontal and high angle development prospects. We do
not presently anticipate conducting any further development
drilling over the balance of 2013 but expect to resume development
drilling during the first quarter of 2014.
With respect to our historical recompletion, workover and
infrastructure investment program, we expect to continue to invest
in selected opportunities to restore and/or increase production
from existing wells and upgrade facilities where associated
cost/benefit analysis and risks reflect favorable return potential
on dollars invested.
With respect to more expensive projects, including deeper
prospects and our recently acquired Gulf of Mexico prospects, we
are actively engaged in efforts to position one or more of those
prospects for development in conjunction with joint venture
partners. To that end, we have retained advisors to assist in
various aspects of that undertaking, including retaining a third
party engineering firm to evaluate reserves associated with our
Gulf of Mexico prospects. We are targeting initial development of
one or more of our deep prospects commencing in 2014, subject to
identification of suitable development partners.
Financial Position and CAPEX Highlights
- $9.6 million of cash on hand at
September 30, 2013, down from $30.2 million at June 30, 2013;
- $(0.1) million of working capital at
September 30, 2013, down from $18.0 million at June 30, 2013;
- $16.4 million of CAPEX for Q3 2013
(including $0.2 million acquisition of State Leases acreage);
- $1.7 million CAPEX budgeted for balance
of 2013;
- 2013 CAPEX budget fully funded by cash
on hand and projected operating cash flow; and
- Working capital adjusted debt to
trailing twelve month EBITDAX of 4.0 times.
We continued to fund our operations, including our development
program, from cash on hand and operating cash flows. The 2014 CAPEX
budget is not yet finalized. Subject to operating results, in order
to support CAPEX at 2013 levels, we may be required to seek
additional capital, whether from securing debt financing pursuant
to the company’s continuing efforts in that regard or other
sources.
Management Comments
Thomas Cooke, Chairman and CEO, commented, “Q3 2013 was a
quarter with some exciting developments as well as its share of
challenges. We are pleased to have successfully drilled our first
two horizontal wells, Rocky and Zeke, which have delivered superior
results as compared to our historical directional drilling results.
We are prioritizing additional horizontal prospects already
identified and evaluated along with look-alike prospects to other
high impact wells and are evaluating additional prospects with a
continuing emphasis on adding more impactful wells.
We nominated and successfully bid on two leases in Breton Sound
that contain the Panther and Tiger Toux prospects. These prospects
contain multiple stacked targets with proved undeveloped reserves
and will be part of our near-term drilling program.
We are also progressing in our efforts to ready our newly
acquired Gulf of Mexico prospects for presentation to potential
development partners. We have assembled a team of experienced
professionals to advise us in regard to all of the key aspects of
that effort. To that end, we have retained an established reserve
engineering firm to evaluate those prospects and expect to shortly
release their findings regarding reserves associated with our Gulf
of Mexico prospects which we believe will include substantial
proved undeveloped reserves.
On the production front, we have seen oil production continue to
grow but have seen a marked decline in natural gas production.
While we are targeting growth in oil production and, due to weak
pricing, have invested limited resources directed at natural gas
production, we are cognizant of our need to continue to invest in
natural gas production to both support gas lift requirements and
maintain production and revenues from natural gas wells.
In addition to challenges of maintaining natural gas production
levels, we experienced two unusual charges during the latest
quarter. In Vermilion 16 Field we plugged and abandoned one of our
few remaining high pressure wells and, in the process, discovered
previously unknown completion conditions that resulted in the
P&A cost substantially exceeding our prior estimate or the
typical cost we expect in future P&A operations. Additionally,
we took a non-cash impairment charge associated with the loss of
our Little Bay field when we released the operating agreement. The
Little Bay well was temporarily abandoned when the rig deployed on
the well was not capable of milling out the existing production
packer in the original completion. We were in the process of
installing a submersible pump when circulation with the
perforations was lost. We ultimately opted to release the Little
Bay lease, resulting in the impairment charge, and have
re-nominated and bid on the subject acreage and additional acreage
where we have identified additional prospects. If we are successful
in re-acquiring the Little Bay acreage, the reserves associated
with the lease are expected to be reinstated, although the lease is
not a near-term focus of future drilling plans.
As we approach the end of 2013, we believe that we have
identified the various operating conditions that challenged our
operating performance early in the year and have taken steps to
remedy those conditions, whether it be third party handling or line
pressure issues that are being address with our investment in Main
Pass 25 facilities upgrades or lack of adequate gas lift which has
contributed to production levels being lower than anticipated. We
are optimistic that our efforts in those regards along with our
ongoing field study efforts which have yielded a number of
attractive horizontal and other drilling prospects will allow us to
drive improving results going forward.”
About Saratoga Resources
Saratoga Resources is an independent exploration and production
company with offices in Houston, Texas and Covington, Louisiana.
Principal holdings cover 51,890 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 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.
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 September 30,
2013 2012 Net income (loss) as reported
$ (5,725,360) $ (475,003) Depreciation, depletion and amortization
4,919,418 3,658,002 Deferred income tax expense (benefit)
(2,716,024) (169,832) Exploration expense 462,994 213,733 Loss on
plugging and abandonment 727,039 - Impairment 2,179,075 44,276
Accretion expense 638,097 555,504 Stock-based compensation 233,133
204,933 Debt issuance and discount 473,905 325,423
Unrealized
loss (gain) on hedges 592,063 6,490 Discretionary
Cash Flow $ 1,784,340 $ 4,363,526
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 September 30,
2013 2012 Net income (loss) as reported
$ (5,725,360) $ (475,003) Depreciation, depletion and amortization
4,919,418 3,658,002 Deferred income tax expense (benefit)
(2,683,382) (48,062) Exploration expense 462,994 213,733 Loss on
plugging and abandonment 727,039 - Impairment expense 2,179,075
44,276 Accretion expense 638,097 555,504 Stock-based compensation
233,133 204,933 Interest expense, net 5,359,828 4,323,185
Reorganization costs - 43,287
Unrealized loss (gain) on
hedges 592,063 6,490 EBITDAX $ 6,702,905 $
8,526,345
Saratoga Resources, Inc.Brad Holmes, 713-654-4009Investor
RelationsAndrew Clifford, 713-458-1560PresidentMichael Aldridge,
713-458-1560CFOwww.saratogaresources.com