Goodrich Petroleum Announces Third Quarter 2012 Financial and
Operational Results
HOUSTON, Nov. 6, 2012 /PRNewswire/ -- Goodrich Petroleum
Corporation (NYSE: GDP) today announced financial and operating
results for the third quarter ended September 30, 2012.
CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and
administrative expenses and exploration ("Adjusted EBITDAX")
increased 6% sequentially and decreased 2% over the prior year
period to $48.0 million in the
quarter, compared to $45.2 million in
the second quarter of 2012 and $49.1
million in the prior year period.
Discretionary cash flow ("DCF"), defined as net cash provided by
operating activities before changes in working capital, increased
by 6% sequentially and decreased 5% over the prior year period to
$36.9 million in the quarter,
compared to $34.8 million in the
second quarter of 2012 and $39.0
million in the prior year period.
(See accompanying tables at the end of this press release
that reconcile Adjusted EBITDAX and DCF, each of which are non-GAAP
financial measures, to their most directly comparable GAAP
financial measure.)
NET INCOME
The Company announced net income applicable to common stock of
$10.9 million for the quarter, or
$0.30 per basic share, versus net
income applicable to common stock of $12.1
million, or $0.34 per basic
share in the prior year period. The Company had an adjusted
net loss applicable to common stock of $8.3
million, or an adjusted net loss of $0.23 per basic share, when adjusted for the gain
on sale of assets of $44.2 million
and unrealized loss on derivatives of $24.9
million for the quarter.
(See accompanying tables at the end of this press release
that reconcile adjusted net loss applicable to common stock, a
non-GAAP measure, to its most directly comparable GAAP financial
measure.)
PRODUCTION
Net production volumes for the quarter were 7.8 billion cubic
feet equivalent ("Bcfe"), or an average of 84,400 thousand cubic
feet equivalent ("Mcfe") per day, versus 10.7 Bcfe, or an average
of 116,200 Mcfe per day in the prior year period. Despite a
17% sequential increase in oil production volumes in the quarter,
total average net daily production volumes on a Mcfe basis for the
quarter decreased 7% sequentially, as a result of a 11% decline in
natural gas production volumes due to the Company's drilling and
completion capital expenditures being allocated exclusively to oil
directed activity. Oil production volumes averaged
approximately 3,200 barrels of oil per day for the quarter and
natural gas liquids averaged 1,400 per day for the quarter.
Production for the fourth quarter of 2012 is expected to average
between 71,600 – 80,200 Mcfe per day, with oil production expected
to average between 3,600 – 4,200 barrels of oil per day, or 27 –
35% of total production, with an additional 8 gross (5 net) wells
expected to be completed and added to production in the fourth
quarter of 2012. The oil production exit rate is now expected
to be approximately 4,500 barrels of oil per day, down from the
previously announced guidance of 5,000 barrels per day, due to the
sale of the South Henderson field
and expected production delays from two Tuscaloosa Marine Shale
wells.
REVENUES
Revenues for the quarter were $46.0
million versus $55.5 million
in the prior year period. Revenues, including realized gain
on derivatives not designated as hedges of $18.8 million for the quarter, would have been
$64.8 million. Average realized
price per unit for the quarter was $2.87 per Mcf and $97.43 per barrel of oil, or $5.92 per Mcfe, versus $5.20 per Mcfe in the prior year period.
Including the realized gain on derivatives of $18.8 million for the quarter, the average
realized price per unit was $5.60 per
Mcf and $105.63 per barrel of oil, or
$8.34 per Mcfe, versus $5.97 per Mcfe in the prior year period.
OPERATING EXPENSES
Lease operating expense ("LOE") decreased
sequentially to $6.2 million in the
quarter, or $0.80 per Mcfe, versus
$6.7 million, or $0.81 per Mcfe in the prior quarter. LOE in the
prior year period was $5.4 million,
or $0.51 per Mcfe. The increase
in LOE expense versus the prior year period was primarily due to
increased oil-focused drilling and production activity in the Eagle
Ford Shale Trend, which has higher LOE than most of the Company's
dry gas assets. LOE, excluding workovers, was $5.8 million, or $0.75 per Mcfe, for the quarter.
Production and other taxes decreased sequentially
to $1.7 million in the quarter, or
$0.22 per Mcfe, versus $2.1 million, or $0.25 per Mcfe in the prior quarter. Production
and other taxes in the prior year period was $1.6 million, or $0.15 per Mcfe. The increase in production
and other taxes from the prior year period was driven by higher oil
production volumes, which carry higher production tax
rates.
Transportation and processing expense decreased
sequentially to $3.4 million in the
quarter, or $0.44 per Mcfe, versus
$3.5 million, or $0.43 per Mcfe in the prior quarter.
Transportation and processing expense in the prior year period was
$2.8 million, or $0.26 per Mcfe. Transportation and
processing expense for the quarter as compared to the prior year
period was impacted by increased processing costs under the
previously disclosed East Texas
processing agreement for the Minden, Beckville and South
Henderson fields.
Depreciation, depletion and amortization
("DD&A") expense was $37.3
million in the quarter, or $4.80 per Mcfe, versus $37.3 million, or $3.49 per Mcfe in the prior year period.
Increased DD&A expense per unit of production was primarily due
to higher oil production levels coming from the Company's Eagle
Ford Shale Trend, which carries a higher DD&A rate on a volume
equivalent basis, and lower production levels coming from the
Haynesville Shale Trend, which carries a lower DD&A rate on a
volume equivalent basis. The Company adjusted its DD&A rate for
the second half of the year upon receipt of its mid-year reserve
report.
Exploration expense was $2.5 million in the quarter, or $0.32 per Mcfe, versus $2.0 million, or $0.24 per Mcfe in the prior quarter and
$1.6 million, or $0.15 per Mcfe in the prior year period.
The increase in exploration expense compared to the prior
quarter was due to seismic expenditures of $0.6 million, or $0.08 per Mcfe. Approximately $1.3 million ($0.17
per Mcfe), or 52% of exploration expense for the quarter, was a
non-cash expense associated with the amortization of the Company's
undeveloped leasehold.
General and Administrative ("G&A") expense was
$7.1 million in the quarter, or
$0.92 per Mcfe, versus $6.7 million, or $0.81 per Mcfe in the prior quarter and
$6.3 million, or $0.58 per Mcfe in the prior year period.
For the quarter, the Company recorded non-cash general and
administrative expenses related to stock based compensation for its
officers and employees of $1.7
million, or $0.22 per Mcfe,
versus $1.3 million, or $0.13 per Mcfe in the prior year
period.
OPERATING INCOME
Operating income, defined as revenues less operating expenses,
was $31.9 million in the quarter,
versus operating income of $0.2
million in the prior year period. When adding in
realized gain on derivatives not designated as hedges of
$18.8 million, adjusted operating
income increased by 604% sequentially to $50.7 million for the quarter, versus
$7.2 million in the second quarter of
2012. When adjusting for the gain on sale of asset for the quarter
of $44.2 million, adjusted operating
income was $6.5 million for the
quarter.
(See accompanying tables at the end of this press release
that reconcile adjusted operating income, a non-GAAP financial
measure to its most directly comparable GAAP financial
measure.)
INTEREST EXPENSE
Interest expense for the quarter was $13.3 million, or $1.71 per Mcfe, versus $13.0 million, or $1.22 per Mcfe in the prior year period.
Non-cash interest expense associated with the amortization of debt
issuance cost and discount on the Company's long term debt
comprised 24% of the total, or $3.1
million ($0.40 per Mcfe).
CRUDE OIL AND NATURAL GAS DERIVATIVES
The Company realized a gain of $18.8
million on its derivatives not designated as hedges and an
unrealized loss of $24.9 million, for
a net loss on derivatives of $6.1
million for the quarter.
During the quarter, the Company hedged an additional 500 barrels
of oil per day for the remainder of 2012 and 2013 at $92.50 per barrel, bringing the total hedged oil
volumes for the fourth quarter of 2012 to 3,500 barrels of oil per
day at a blended average price of $100.14 per barrel. The Company hedged an
additional 500 barrels of oil per day for 2013 at $95.85 per barrel, bringing the total hedged oil
volumes for 2013 to 1,500 barrels of oil per day with straight
swaps at a blended average price of approximately $97.17 per barrel and 2,500 barrels of oil per
day committed under a swaption, to be exercised at the
counterparty's option, at $100.82 per
barrel.
CAPITAL EXPENDITURES
Capital expenditures for the quarter were down 22% sequentially
to $57.8 million, of which
$51.3 million was spent on drilling
and completion costs, $3.3 million on
acreage acquisitions, $1.8 million on
facility costs and $1.4 million on
other expenditures. Capital expenditures for the first nine
months of the year were $193.5
million, of which $164.7
million was spent on drilling and completion costs,
$21.3 million on acreage
acquisitions, $4.2 million on
facility costs and $3.3 million on
other expenditures.
For the quarter, the Company spent approximately $44.3 million, or 77% of its capital, in the
Eagle Ford Shale Trend where the Company had two rigs running
during the quarter, and $10.9
million, or 19%, in the Tuscaloosa Marine Shale Trend, for a
total of $55.2 million, or 96%, of
its total capital on oil-directed activity. Of the
$10.9 million spent in the Tuscaloosa
Marine Shale Trend, approximately $1.4
million was spent on leasehold, which was accounted for in
our previously disclosed $27.5
million leasehold and infrastructure budget.
For the quarter, the Company conducted drilling operations on 13
gross (8 net) wells, added 6 gross (4 net) wells to production and
had 18 gross (9 net) wells waiting on completion at the end of the
quarter. The Company added 6 gross (4 net) wells to production from
the Eagle Ford Shale Trend, with 5 gross (3 net) wells waiting on
completion.
LIQUIDITY
The Company exited the quarter with $1.6
million in cash and $99.0
million drawn on its senior bank revolving credit facility,
under which the Company currently has a borrowing base of
$210 million, yielding approximately
$113 million of liquidity.
OPERATIONAL UPDATE
Tuscaloosa Marine Shale
Trend ("TMS")
The Company has fraced its initial operated well, the Denkmann
33 H-1, with 12 successful frac stages, but flowback has been
delayed due to the need to repair a casing connection.
Flowback will commence upon completion of the repair and
installation of tubing.
The Company has drilled, cored and logged the vertical portion
of its Crosby 12H-1 (50% WI) in
Wilkinson County, MS, with plans
for a 7,000 foot lateral. In addition, the Company has
participated in two additional non-operated wells, the Joe Jackson
4H-2 (25% WI) in Wilkinson County,
MS, which is currently flowing back, and the Ash 31 H-1 (19%
WI) in Amite County, MS, which is
in completion phase. The Ash 31 H-1 is the first well in
which the lateral was landed just above the zone that has caused
wellbore instability, with a very favorable outcome, which if
repeatable should materially reduce drilling costs going
forward.
The Company anticipates running one rig in the TMS into the
first quarter of 2013, and potentially adding or reallocating a
second rig to the play in 2013 pending continued success.
Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas
In the Eagle Ford Shale Trend, the Company conducted drilling
operations on 10 gross (7 net) wells in the quarter, and expects to
conduct drilling operations on approximately 12 gross (8 net) wells
in the fourth quarter of 2012, which would bring the total to 32
gross (21 net) wells drilled for the year. The Company has
reduced its drill time on recent wells by approximately 40%
to 11 days for an average 6,400 foot lateral, which has
increased the well count for the year. The Company added 6
gross (4 net) wells to production for the quarter, and expects to
add 8 gross (5 net) wells to production in the fourth quarter of
2012, which would bring the yearly total to 26 gross (17 net) wells
added to production. The Company expects to have
approximately 7 gross (5 net) wells waiting on completion at year
end due primarily to timing issues related to its pad drilling.
The Company is currently running two operated rigs in the
Eagle Ford Shale Trend.
Pearsall Shale
The Company owns deep rights to approximately 10,000 net acres
prospective for the Pearsall Shale on its Eagle Ford Shale Trend
acreage. The Company is in the preliminary planning stage for
an early first quarter of 2013 Pearsall well on its acreage in
Frio County near a recently
reported well that tested at approximately 1,800 BOE per day (75%
liquids).
Haynesville Shale Trend
The Company now expects to complete 13 gross (6 net) previously
drilled Haynesville Shale wells in the first half of 2013,
comprised of 12 gross (5 net) non-operated wells in North Louisiana and 1 gross (1 net) operated
well in the Angelina River Trend. Total capital expenditures
are expected to be approximately $22
million to complete these wells. Assuming timely
completion, the Company expects to grow gas volumes during 2013
from these completions by approximately 10%. The Company
expects to give additional guidance in connection with the
disclosures of its intended 2013 capital expenditure budget in
December.
South Henderson Divestiture
On September 28, 2012, the Company
sold its interest in non-core properties in the South Henderson field in Rusk County, Texas for $95 million, with an effective date of
July 1, 2012. During the
quarter, production from the South
Henderson field averaged approximately 9,600 Mcf/d of
natural gas and 200 Bbls/d of oil net to the Company.
OTHER INFORMATION
In this press release, the Company refers to several non-GAAP
financial measures, including Adjusted EBITDAX, DCF, drilling and
completion capital expenditures, Adjusted revenues, Adjusted
operating income, Adjusted net loss applicable to common stock and
Cash operating margin. Management believes Adjusted EBITDAX,
Discretionary cash flow, Adjusted revenues, Adjusted operating
income, Adjusted net loss applicable to common stock and Cash
margin are good financial indicators of the Company's ability to
internally generate operating funds, while drilling and completion
capital expenditures are a useful measure of the Company's annual
drilling expenditures. Neither discretionary cash flow, nor
Adjusted EBITDAX, should be considered an alternative to net cash
provided by operating activities, as defined by GAAP.
Adjusted revenues should not be considered an alternative to total
revenues, as defined by GAAP. Adjusted operating income
should not be considered an alternative to operating income (loss),
as defined by GAAP. Adjusted net loss applicable to common
stock should not be considered an alternative to net loss
applicable to common stock, as defined by GAAP. Nor should
drilling and completion capital expenditures be considered an
alternative to costs incurred in oil and gas property acquisition,
exploration, and development activities, as defined by GAAP.
Management believes that all of these non-GAAP financial measures
provide useful information to investors because they are monitored
and used by Company management and widely used by professional
research analysts in the valuation and investment recommendations
of companies within the oil and gas exploration and production
industry.
Initial production rates are subject to decline over time and
should not be regarded as reflective of sustained production
levels. In particular, production from horizontal drilling in
shale oil and natural gas resource plays and tight natural gas
plays that are stimulated with extensive pressure fracturing are
typically characterized by significant early declines in production
rates.
Unless otherwise stated, oil production volumes include
condensate.
Certain statements in this news release regarding future
expectations and plans for future activities may be regarded as
"forward looking statements" within the meaning of the Securities
Litigation Reform Act. They are subject to various risks,
such as financial market conditions, changes in commodities prices
and costs of drilling and completion, operating hazards, drilling
risks, and the inherent uncertainties in interpreting engineering
data relating to underground accumulations of oil and gas, as well
as other risks discussed in detail in the Company's Annual Report
on Form 10-K for the year ended December 31,
2011 and other subsequent filings with the Securities and
Exchange Commission. Although the Company believes that the
expectations reflected in such forward looking statements are
reasonable, it can give no assurance that such expectations will
prove to be correct.
Goodrich Petroleum is an independent oil and gas exploration and
production company listed on the New York Stock Exchange.
GOODRICH
PETROLEUM CORPORATION
|
SELECTED
INCOME AND PRODUCTION DATA
|
(In
Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
Volumes
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
5,991
|
|
9,468
|
|
20,215
|
|
27,562
|
|
Oil and
condensate (MBbls)
|
|
296
|
|
204
|
|
766
|
|
418
|
|
MMcfe -
Total
|
|
7,764
|
|
10,690
|
|
24,811
|
|
30,073
|
|
|
|
|
|
|
|
|
|
|
|
Mcfe per
day
|
|
84,396
|
|
116,200
|
|
90,553
|
|
110,157
|
|
|
|
|
|
|
|
|
|
|
Total
Revenues
|
|
$
45,960
|
|
$
55,542
|
|
$
132,614
|
|
$
149,644
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
6,218
|
|
5,447
|
|
21,267
|
|
15,565
|
|
Production
and other taxes
|
|
1,672
|
|
1,599
|
|
5,752
|
|
4,194
|
|
Transportation and processing
|
|
3,410
|
|
2,795
|
|
11,060
|
|
7,482
|
|
Depreciation, depletion and amortization
|
|
37,298
|
|
37,348
|
|
104,138
|
|
93,234
|
|
Exploration
|
|
2,523
|
|
1,638
|
|
6,755
|
|
6,379
|
|
Impairment
|
|
-
|
|
142
|
|
2,662
|
|
1,192
|
|
General
and administrative
|
|
7,142
|
|
6,251
|
|
21,753
|
|
21,829
|
|
Gain on
sale of assets
|
|
(44,157)
|
|
-
|
|
(44,229)
|
|
(236)
|
|
Other
|
|
-
|
|
146
|
|
-
|
|
146
|
Operating income (loss)
|
|
31,854
|
|
176
|
|
3,456
|
|
(141)
|
|
|
|
|
|
|
|
|
|
|
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(13,314)
|
|
(13,022)
|
|
(39,316)
|
|
(36,815)
|
|
Interest
income and other
|
|
2
|
|
21
|
|
3
|
|
43
|
|
Gain
(loss) on derivatives not designated as hedges
|
|
(6,137)
|
|
26,453
|
|
27,331
|
|
27,397
|
|
Gain from
extinguishment of debt
|
|
-
|
|
4
|
|
-
|
|
62
|
|
|
|
(19,449)
|
|
13,456
|
|
(11,982)
|
|
(9,313)
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
12,405
|
|
13,632
|
|
(8,526)
|
|
(9,454)
|
Income tax
benefit
|
|
-
|
|
-
|
|
-
|
|
-
|
Net income
(loss)
|
|
12,405
|
|
13,632
|
|
(8,526)
|
|
(9,454)
|
Preferred
stock dividends
|
|
1,511
|
|
1,511
|
|
4,535
|
|
4,535
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) applicable to common stock
|
|
$
10,894
|
|
$
12,121
|
|
$
(13,061)
|
|
$
(13,989)
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
(gain) loss on derivatives not designated as hedges
|
|
24,943
|
|
(18,163)
|
|
28,696
|
|
(5,995)
|
|
Other -
Hoover Tree Farm ruling litigation
|
|
-
|
|
146
|
|
-
|
|
146
|
|
Gain on
sale of assets
|
|
(44,157)
|
|
-
|
|
(44,229)
|
|
(236)
|
|
Gain on
extinguishment of debt
|
|
-
|
|
(4)
|
|
-
|
|
(62)
|
|
Impairment
|
|
-
|
|
142
|
|
2,662
|
|
1,192
|
|
|
|
|
|
|
|
|
|
|
Adjusted
net loss applicable to common stock (1)
|
|
$
(8,320)
|
|
$
(5,758)
|
|
$
(25,932)
|
|
$
(18,944)
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary cash flow (see non-GAAP reconciliation)
(2)
|
|
$
36,928
|
|
$
39,002
|
|
$
101,627
|
|
$
99,083
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX (see calculation and non-GAAP reconciliation)(3)
|
|
$
48,000
|
|
$
49,089
|
|
$
133,520
|
|
$
126,502
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding - basic
|
|
36,391
|
|
36,125
|
|
36,365
|
|
36,104
|
Weighted
average common shares outstanding - diluted (4)
|
|
36,619
|
|
36,297
|
|
36,365
|
|
36,104
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
Net income
(loss) applicable to common stock - basic
|
|
$
0.30
|
|
$
0.34
|
|
$
(0.36)
|
|
$
(0.39)
|
|
Net income
(loss) applicable to common stock - diluted
|
|
$
0.30
|
|
$
0.33
|
|
$
(0.36)
|
|
$
(0.39)
|
|
|
|
|
|
|
|
|
|
|
Adjusted
earnings per share
|
|
|
|
|
|
|
|
|
|
Adjusted
net loss applicable to common stock - basic (1)
|
|
$
(0.23)
|
|
$
(0.16)
|
|
$
(0.71)
|
|
$
(0.52)
|
|
Adjusted
net loss applicable to common stock - fully diluted (1)
|
|
$
(0.23)
|
|
$
(0.16)
|
|
$
(0.71)
|
|
$
(0.52)
|
|
|
|
|
|
|
|
|
|
|
(1)
Adjusted net income applicable to common stock is defined as net
income (loss) applicable to common stock adjusted to exclude
certain charges or amounts in order to provide users of this
financial information with additional meaningful comparisons
between current results and the results of prior periods.
Management presents this measure because (i) it is consistent with
the manner in which the company's performance is measured relative
to the performance of its peers, (ii) this measure is more
comparable to earnings estimates provided by securities analysts,
and (iii) charges or amounts excluded cannot be reasonably
estimated and guidance provided by the company excludes information
regarding these types of items. These adjusted amounts are not a
measure of financial performance under GAAP.
|
|
|
|
|
|
|
|
|
|
|
(2)
Discretionary cash flow is defined as net cash provided by
operating activities before changes in operating assets and
liabilities. Management believes that the non-GAAP measure of
operating cash flow is useful as an indicator of an oil and gas
exploration and production company's ability to internally fund
exploration and development activities and to service or incur
additional debt. The company has also included this information
because changes in operating assets and liabilities relate to the
timing of cash receipts and disbursements which the company may not
control and may not relate to the period in which the operating
activities occurred. Operating cash flow should not be considered
in isolation or as a substitute for net cash provided by operating
activities prepared in accordance with GAAP.
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(3)
Adjusted EBITDAX is earnings before interest expense, income tax,
DD&A, exploration expense and impairment of oil and gas
properties. In calculating EBITDAX for this purpose, earnings
include realized gains (losses) from derivatives but exclude
unrealized gains (losses) from derivatives. Other excluded items
include Interest income and other, Gain on sale of assets, Gain on
early extinguishment of debt and Other expense.
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|
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(4) Fully
diluted shares excludesapproximately 9.9 million and 10.1 million
potentially dilutive instruments that were anti-dilutive due to the
net income (loss) applicable to common stock for the three and nine
months ended September 30, 2012, respectively. We report our
financial results in accordance with accounting principles
generally accepted in the United States of America ("GAAP").
However, management believes certain non-GAAP performance measures
may provide users of this financial information with additional
meaningful comparisons between current results and the results of
our peers and of prior periods.
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|
GOODRICH
PETROLEUM CORPORATION
|
Per Unit
Sales Prices and Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Average
sales price per unit:
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
|
|
|
|
|
|
|
|
Including realized gain on
oil derivatives
|
|
$
105.63
|
|
$
92.19
|
|
$
105.63
|
|
$
94.51
|
|
Excluding realized gain on
oil derivatives
|
|
$
97.43
|
|
$
84.18
|
|
$
100.46
|
|
$
89.65
|
|
Natural
gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
Including realized gain on
natural gas derivatives
|
|
$
5.60
|
|
$
4.76
|
|
$
5.34
|
|
$
4.74
|
|
Excluding realized gain on
natural gas derivatives
|
|
$
2.87
|
|
$
4.05
|
|
$
2.76
|
|
$
4.04
|
|
Natural
gas and oil (per Mcfe)
|
|
|
|
|
|
|
|
|
|
Including realized gain on
oil and natural gas derivatives
|
|
$
8.34
|
|
$
5.97
|
|
$
7.61
|
|
$
5.66
|
|
Excluding realized gain on
oil and natural gas derivatives
|
|
$
5.92
|
|
$
5.20
|
|
$
5.35
|
|
$
4.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Costs Per
Mcfe
|
|
|
|
|
|
|
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|
Lease
operating expense
|
|
$
0.80
|
|
$
0.51
|
|
$
0.86
|
|
$
0.52
|
|
Production
and other taxes
|
|
$
0.22
|
|
$
0.15
|
|
$
0.23
|
|
$
0.14
|
|
Transportation and processing
|
|
$
0.44
|
|
$
0.26
|
|
$
0.45
|
|
$
0.25
|
|
Depreciation, depletion and amortization
|
|
$
4.80
|
|
$
3.49
|
|
$
4.20
|
|
$
3.10
|
|
Exploration
|
|
$
0.32
|
|
$
0.15
|
|
$
0.27
|
|
$
0.21
|
|
Impairment
|
|
$
-
|
|
$
0.01
|
|
$
0.11
|
|
$
0.04
|
|
General
and administrative
|
|
$
0.92
|
|
$
0.58
|
|
$
0.88
|
|
$
0.73
|
|
Gain on
sale of assets
|
|
$
(5.69)
|
|
$
-
|
|
$
(1.78)
|
|
$
(0.01)
|
|
Other
|
|
$
-
|
|
$
0.01
|
|
$
-
|
|
$
-
|
|
|
|
$
1.82
|
|
$
5.18
|
|
$
5.21
|
|
$
4.98
|
|
|
|
|
|
|
|
|
|
|
Note:
Amounts on a per Mcfe basis may not total due to
rounding.
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|
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|
|
GOODRICH
PETROLEUM CORPORATION
|
Selected
Cash Flow Data (In Thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Discretionary Cash Flow and Net
Cash Provided by Operating Activities (unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Net cash
provided by operating activities (GAAP)
|
$
19,643
|
|
$
42,016
|
|
$
97,573
|
|
$
109,937
|
Net
changes in working capital
|
17,285
|
|
(3,014)
|
|
4,054
|
|
(10,854)
|
Discretionary cash flow
|
$
36,928
|
|
$
39,002
|
|
$
101,627
|
|
$
99,083
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding - basic
|
36,391
|
|
36,125
|
|
36,365
|
|
36,104
|
Weighted
average common shares outstanding - diluted (4)
|
36,619
|
|
36,297
|
|
36,365
|
|
36,104
|
|
|
|
|
|
|
|
|
|
Supplemental Balance Sheet Data
|
|
|
As
of
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
|
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and
cash equivalents
|
$
1,570
|
|
$
3,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
569,953
|
|
566,126
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Net income (loss) to Adjusted
EBITDAX
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Net loss
(GAAP)
|
$
12,405
|
|
$
13,632
|
|
$
(8,526)
|
|
$
(9,454)
|
|
Exploration expense
|
2,523
|
|
1,638
|
|
6,755
|
|
6,379
|
|
Depreciation, depletion and amortization
|
37,298
|
|
37,348
|
|
104,138
|
|
93,234
|
|
Impairment
|
-
|
|
142
|
|
2,662
|
|
1,192
|
|
Stock
compensation expense
|
1,676
|
|
1,349
|
|
4,711
|
|
4,526
|
|
Interest
expense
|
13,314
|
|
13,022
|
|
39,316
|
|
36,815
|
|
Unrealized
(gain) loss on derivatives not designated as hedges
|
24,943
|
|
(18,163)
|
|
28,696
|
|
(5,995)
|
|
Other
excluded items *
|
(44,159)
|
|
121
|
|
(44,232)
|
|
(195)
|
|
Adjusted
EBITDAX
|
$
48,000
|
|
$
49,089
|
|
$
133,520
|
|
$
126,502
|
|
|
|
|
|
|
|
|
|
|
*
Other excluded items include Interest income and other, Gain on
sale of assets, Gain on early extinguishment of debt, Income taxes
and Other expense.
|
|
|
|
|
|
|
|
|
|
Other
Information
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Interest
expense - cash
|
$
10,178
|
|
$
9,545
|
|
$
29,909
|
|
$
25,138
|
|
Interest
expense - noncash
|
3,136
|
|
3,477
|
|
9,407
|
|
11,677
|
|
Total
Interest
|
13,314
|
|
13,022
|
|
39,316
|
|
36,815
|
|
|
|
|
|
|
|
|
|
|
Unrealized
(gain) loss on derivatives not designated as hedges
|
24,943
|
|
(18,163)
|
|
28,696
|
|
(5,995)
|
|
Realized
gain on derivatives not designated as hedges
|
(18,806)
|
|
(8,290)
|
|
(56,027)
|
|
(21,402)
|
|
Total
(gain) loss on derivatives not designated as hedges
|
6,137
|
|
(26,453)
|
|
(27,331)
|
|
(27,397)
|
|
|
|
|
|
|
|
|
|
|
General
and Administrative expense - cash
|
5,466
|
|
4,902
|
|
17,042
|
|
17,303
|
|
General
and Administrative expense - noncash
|
1,676
|
|
1,349
|
|
4,711
|
|
4,526
|
|
Total
General and Administrative expense
|
7,142
|
|
6,251
|
|
21,753
|
|
21,829
|
GOODRICH
PETROLEUM CORPORATION
|
Selected
Cash Flow Data continued (In Thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted Revenues and Total
Revenues (unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Total
Revenues (GAAP)
|
$
45,960
|
|
$
55,542
|
|
$
132,614
|
|
$
149,644
|
Realized
gain on derivatives not designated as hedges
|
18,806
|
|
8,290
|
|
56,027
|
|
21,402
|
Adjusted
Revenues
|
$
64,766
|
|
$
63,832
|
|
$
188,641
|
|
$
171,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted Operating Income and
Operating Income (unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Operating
income (loss) (GAAP)
|
$
31,854
|
|
$
176
|
|
$
3,456
|
|
$
(141)
|
Realized
gain on derivatives not designated as hedges
|
18,806
|
|
8,290
|
|
56,027
|
|
21,402
|
Adjusted
Operating Income
|
$
50,660
|
|
$
8,466
|
|
$
59,483
|
|
$
21,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation of Cash operating margin
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX (see calculation and non-GAAP reconciliation)
(3)
|
$
48,000
|
|
$
49,089
|
|
$
133,520
|
|
$
126,502
|
Adjusted
Revenues (see non-GAAP reconciliation)
|
$
64,766
|
|
$
63,832
|
|
$
188,641
|
|
$
171,046
|
Cash
operating margin
|
74%
|
|
77%
|
|
71%
|
|
74%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SOURCE Goodrich Petroleum Corporation