Saratoga Resources, Inc. (NYSE MKT: SARA; the “Company” or
“Saratoga”) today announced financial and operating results for the
quarter ended March 31, 2014.
Key Financial Results
- Oil and gas revenues of $10.6 million
for Q1 2014 compared to $19.3 million for Q1 2013;
- Discretionary cash flow of $(5.2)
million, or $(0.17) per fully diluted share, for Q1 2014 compared
to discretionary cash flow of $4.9 million, or $0.16 per fully
diluted share, for Q1 2013;
- EBITDAX of $0.1 million for Q1 2014
compared to $9.7 million for Q1 2013;
- Operating loss of $(2.2) million, or
$(0.07) per fully diluted share, for Q1 2014 compared to operating
income of $3.7 million, or $0.12 per fully diluted share, for Q1
2013; and
- Net loss of $(8.3) million, or $(0.27)
per fully diluted share, for Q1 2014 compared to net loss of ($1.1)
million, or $(0.03) per fully diluted share, for Q1 2013.
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 quarter reflects a 45% decline in oil and
gas revenues while operating expenses only declined 7.2%. The
change in revenues for the 2014 quarter reflects a decrease in
production volumes (down 48.1% in aggregate; down 39.9% for oil;
down 65.5% for natural gas) partially offset by higher average
realized commodity prices (up 6%; oil pricing down 7.2%; natural
gas pricing up 39.8%). The decline in production was attributable
to multiple field operating issues which adversely affected run
times during the first two months of the quarter – discussed more
fully below under “Operational Highlights” and “Production
Highlights” – and to the depletion of several producing sands.
Extensive changes in field operating personnel and in our Covington
office personnel were untaken during the quarter and substantially
all of the run time related issues had been resolved by quarter
end. The declines in production were partially offset by new wells
coming on line during 2013 and increases in production from several
wells that underwent recompletions and workovers during 2013 and Q1
2014.
The decrease in operating expenses for the quarter related
principally to the decrease in production volumes which resulted in
a reduction in depreciation, depletion and amortization expense
(down $2.5 million; or 47.4%) and a decline in severance taxes
(down $1.6 million; or 76%) which was partially offset by increases
in lease operating expenses (up $0.9 million; or 20.5%), workover
expense (up $1.9 million; or 739%) and lesser increases in
exploration expense and general and administrative expense. The
increase in lease operating expense was principally attributable to
increased contract labor and repairs and maintenance expenses
incurred in connection with our efforts to resolve the decline in
average run time during the quarter. The increase in workover
expense was attributable to an increase in the number of workovers
undertaken during the quarter. The decline in severance taxes for
the quarter reflects a combination of lower production volumes and
refunds of severance taxes arising from exemptions available on our
Rocky, Zeke and Mesa Verde wells drilled in prior periods.
The net loss for the quarter also reflects higher interest
expense (up $0.8 million; or 15.1%) resulting from the addition of
$27.4 million of borrowing during the fourth quarter of 2013 and an
adverse change in income tax expense/benefit ($0.5 million) as a
result of our recording a valuation allowance against our entire
net deferred tax asset at December 31, 2013 and our resulting
non-recognition of a deferred tax benefit from our current quarter
loss.
Operational Highlights
Operational highlights for first quarter 2014 included:
- 1 recompletion successfully completed
and 1 in progress at quarter end; 7 workovers successfully
completed;
- 90 gross/net wells in production at
March 31, 2014;
- Exhaustive review undertaken, personnel
changes implemented and investments in facilities repairs and
maintenance made to address run time issues;
- Secured a gas buyback agreement with an
area operator to provide for redundant gas supply for gas-lift
operations;
- 52,103 gross/net acres under lease at
March 31, 2014, including 32,289 acres in 13 fields in the
transitional coastline and protected in-bay environment on parish
and state leases in south Louisiana and 19,814 acres in the shallow
Gulf of Mexico shelf; and
- Added 4 seasoned veterans to our
professional staff.
During Q1 2014, we undertook 2 recompletions and 7 workovers.
All of the recompletions and workovers were successful other than
one recompletion that was ongoing at quarter end and that was
successfully completed after March 31, 2014. Four of the seven
workovers were undertaken on salt water disposal wells to increase
the disposal capacity of produced water associated with our oil and
gas production.
During Q1 2014, our management team, together with consultants,
undertook an exhaustive review of field operations to address run
time issues experienced in the second half of 2013 and into the
first quarter 2014. Issues evaluated included personnel,
facilities, gas lift availability, salt water disposal and other
potential causes of unexpected down time in numerous fields. As a
result of such evaluation, we made extensive changes in our field
operating personnel and in our Covington office personnel. We also
undertook extensive repairs and maintenance projects to improve
certain facilities in the field and invested in gas lift projects
and salt water disposal wells. The majority of the personnel
changes, facilities upgrades and other projects were completed in
early March 2014 with additional personnel changes and facilities
upgrades continuing following quarter end.
In addition to extensive changes in our field level personnel,
we have strengthened and added depth to our professional staff with
hiring 4 seasoned professionals who are expected to enhance our
prospect analysis and development capabilities.
Production Highlights
- Oil and gas production of 94.2 thousand
barrels of oil (“MBO”) and 152.9 million cubic feet of gas
(“MMCFG”), or 119.7 thousand barrels of oil equivalent (“MBOE”)
(78.7% oil) in Q1 2014, down 48.1% from 230.7 MBOE (68% oil) in Q1
2013;
- Increased gross gas production to 5.9
Mmcf/d by quarter end, last seven days average, versus 4.6 Mmcf/d
and 3.9 Mmcf/d in Q3 2013 and Q4 2013, respectively; and
- Following production optimization
initiatives undertaken during Q1, average run times increased to
76% in March 2014, up from 54% in January and February 2014 and
daily production rates reached an average of 1,875 MBOE per day
(MBOEPD) over the last seven days of the quarter compared to an
average of 1,330 MBOEPD over the full quarter and 1,800 MBOEPD in
Q4 2013.
The decrease in production reflects a substantial decline in run
times during the first two months of 2014 and the depletion of
producing sands in three wells. Run times averaged 61% for the
quarter and 54% for January and February as compared to 73% in Q1
2013 and 75% for fiscal 2013.
Partially offsetting declines in production attributable to
decreased run times and depleted sands were the addition of
production from wells drilled during the final three quarters of
2013 and increased production or renewal of production from wells
that have undergone recompletions or workovers since the end of Q1
2013.
Following our exhaustive review of field operations with respect
to the decline in run times and other issues holding down our
production, we identified a number of specific issues and
implemented extensive personnel changes at the field level and in
our Covington office, invested in facilities repairs, maintenance
and upgrades, added gas lift availability, executed a gas buyback
agreement with an area operator, worked over several salt water
disposal wells, all of which were identified as adversely affecting
our run times and production. The majority of those changes were
implemented during March 2014.
Following the implementation of the various field level
initiatives, and taking into account our workover and recompletion
program, run times and production rates began to grow in March
2014, with estimated run times in March 2014 averaging 76% up from
54% in January and February 2014 and up from 73% in Q1 2013 and 75%
for fiscal 2013. Production rates had risen to an average of 1,875
MBOEPD over the last seven days of the quarter compared to 1,330
MBOEPD for the full quarter and 1,800 MBOEPD in Q4 2013.
Development Plans
- Low risk recompletions, thru-tubing
plugbacks and workovers from inventory of approximately 56 proved
developed non-producing (“PDNP”) opportunities in 7 fields;
- Development of proved undeveloped
(“PUD”) reserves from inventory of approximately 85 PUD
opportunities in 22 wellbores in 5 fields;
- Rocky 3 horizontal well with 750’
lateral in Breton Sound 32 field commenced drilling during Q2;
- Q2 and Q3 focused on targeted
recompletions and workovers with objective of further growing
legacy well production rate;
- Development drilling planned to resume
in Fall 2014; 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.
Drilling operations on our Rocky 3 horizontal well in Breton
Sound 32 field commenced in early May 2014 with drilling expected
to be completed before month end.
Our near term development plans during Q2 and Q3 2014 are
expected to be focused on workover and recompletion opportunities
to enhance production from our legacy wells.
We plan to resume our development drilling program in the Fall
of 2014 and are conducting exhaustive geological and engineering
reviews to bring forward the most promising of our available
prospects.
We have commenced marketing efforts with respect to our efforts
to secure drilling partners for our Goldeneye prospect in Grand Bay
Field and, subject to securing commitments from potential partners,
are planning to commence drilling of that prospect during 2014.
Financial Position and CAPEX Highlights
- $ 20.4 million of cash on hand at March
31, 2014, down from $32.5 million at December 31, 2013;
- Cash balance had grown to $21.0 million
by end of April 2014;
- $14.6 million of working capital at
March 31, 2014, down from $20.4 million at December 31, 2013;
- $1.3 million of CAPEX for Q1 2014;
- Working capital adjusted debt to
trailing twelve month EBITDAX of 8.6 times; and
- Net asset value per share (based on
working capital adjusted PV-10) of approximately $7.93.
Saratoga continued to fund its operations, including its
development program, from cash on hand and operating cash flows.
The 2014 CAPEX budget is expected to be fully funded from cash on
hand and operating cash flow.
Management Comments
Thomas Cooke, Chairman and CEO, commented, “As noted in our year
end 2013 earnings call, Q1 2014 was a challenging period during
which I, and our entire management team, took a hard look at our
field operations in order to ferret our issues that continued to
plague Saratoga and result in unsatisfactory run times and
production levels below those considered acceptable by management.
As a result of our exhaustive review, we made a number of wide
ranging changes that began to go into effect in early March. Those
changes included extensive changes in field operating personnel and
in our Covington office, investments in repairs and maintenance on
our facilities in the field and a focus on adding gas lift gas and
salt water disposal capacity that have curtailed our production in
the past and, in particular, over the first two months of the
current quarter.
While the review of operations was time consuming and took us
away from our planned development operations, I am pleased to say
that the initiatives implemented as a result of that review began
to show results almost immediately with run times, and production,
growing markedly over the last month of the quarter. We intend to
continue to keep an eye on field level operations to assure that
the issues that plagued us during the first two months of the
quarter, and in prior periods, will not reoccur.
With the run time issues seemingly behind us, we are focused on
continuing to move up our production from our legacy wells and to
reinstituting our development drilling program.
Our next development well is already well along in drilling. The
SL 1227 #29 “Rocky 3” well in Breton Sound 32 field, an analog to
our successful SL 1227 #25 “Rocky 1” horizontal well, began
drilling in early May and reached a total depth of 7,178’ MD/5,818’
TVD on May 14, 2014. Based on drilling results and analysis of log
data, we are optimistic that Rocky 3 will perform as well as, or
better than, Rocky 1.
We also have a rig in Grand Bay finalizing the completion of the
SL 195 QQ #24 well, which will be followed by a non-rig wireline
recompletion in our SL 195 QQ #25 well. We expect the Rocky 3, QQ
#24 and QQ #25 wells to all be in production within the next two to
three weeks. Over the next several months we intend to focus our
efforts on increasing production from our legacy wells with a view
to growing our cash position to support renewed development
drilling in the Fall.
While we are continually reviewing our prospect inventory to
bring forward the most promising drilling prospects, we are
presently targeting drilling of our Goldeneye prospect in Grand
Bay. We have completed an exhaustive analysis of the prospect and
have begun an active marketing effort to secure partners to drill
the prospect.
I am also pleased with the additions to our professional staff
over the past quarter and since quarter end. We now have the
deepest and most experienced staff in our company’s history and
believe our newly strengthened team will pay dividends in terms of
improved prospect selection, evaluation and execution.
While the quarter was filled with challenges, including a
disappointing drop in production and revenues and the incurrence of
additional costs to address issues in the field, we believe that
the issues in question are largely behind us. We are optimistic
about our Rocky 3 well as well as our planned recompletion and
workover program and planned resumption of our development drilling
post-Rocky 3. Run times and production levels improved over the
last month of the past quarter and those improvements continue to
hold. We are now optimistic that our legacy well production can
serve its intended purpose as a platform on which we can grow
production through our development drilling program.”
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.
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
March 31,
2014 2013 Net
income (loss) as reported $ (8,289,187 ) $ (1,061,393 )
Depreciation, depletion and amortization 2,742,059 5,208,494 Income
tax expense (benefit) - (487,247 ) Exploration expense 221,352
168,284 Accretion Expense 448,466 638,097 Stock-based Compensation
6,029 163,042 Debt issuance and discount 732,433 438,788 Unrealized
(gain) loss on hedges (1,092,960 ) (166,509 )
Discretionary Cash Flow $ (5,231,808 ) $ 4,901,556
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
March 31,
2014 2013 Net
income (loss) as reported $ (8,289,187 ) $ (1,061,393 )
Depreciation, depletion and amortization 2,742,059 5,208,494 Income
tax expense (benefit) 82,066 (454,150 ) Exploration expense 221,352
168,284 Accretion expense 448,466 638,097 Stock-based compensation
6,029 163,042 Interest expense, net 5,997,312 5,216,862
Reorganization costs - 2,319 Unrealized (gain) loss on hedges
(1,092,960 ) (166,509 ) EBITDAX $ 115,037 $
9,715,046
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.
3/31/2014
In Thousands (except per share amount) PV-10 (as of December 31,
2013) $ 410,754 Working capital 14,613 Long-term Debt (179,800) Net
Asset Value 245,567 Shares Outstanding, Fully Diluted 30,981
Net Asset Value per share $ 7.93
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.Brad Holmes, 713-654-4009Investor
RelationsAndrew Clifford, 713-458-1560PresidentJohn Ebert,
985-809-9292Vice President – Finance and Business
Developmentwww.saratogaresources.com