- Record Net Income Applicable to Common Stock of $195 Million - Company Exits the Quarter with $224 Million in Cash and Zero Outstanding Borrowings Under Bank Revolving Credit Facility. Net Debt to Cap Ratio of Approximately 4%
HOUSTON, Nov. 5 /PRNewswire-FirstCall/ -- Goodrich Petroleum Corporation
(NYSE: GDP) today announced its financial and operating results for the third
quarter ended September 30, 2008.
Net Income applicable to common stock for the quarter was $194.9 million
versus a net loss applicable to common stock of $23.7 million for the third
quarter of 2007. Net income applicable to common stock for the quarter was
$5.50 per basic share ($4.68 per diluted share) compared to net loss
applicable to common stock for the third quarter of 2007 of $0.94 per basic
and diluted share. Net income for the quarter was positively impacted by a
$146 million pre tax gain primarily on the sale of undeveloped leasehold
rights associated with a portion of the Company's deep rights in North
Louisiana, which closed in July of this year, as well as an $83.5 million gain
on derivatives not designated as hedges. Last year's third quarter was
negatively impacted by a non-cash adjustment of $14.8 million for an increase
in the valuation allowance relative to the Company's deferred tax asset, as
required by SFAS No. 109 "Accounting for Income Taxes" ("SFAS 109").
Earnings before interest, taxes, DD&A and exploration ("EBITDAX") for the
quarter, increased by 114% to $41.1 million (excluding the $146 million gain
on the sale of undeveloped leasehold rights) compared to $19.2 million in the
third quarter of 2007 (see accompanying table for a reconciliation of EBITDAX,
a non-GAAP measure, to net cash provided by operating activities). For
purposes of calculating EBITDAX, we use earnings including realized gains
(losses) from derivatives not qualifying for hedge accounting, but excluding
unrealized gains (losses) from derivatives not qualifying for hedge
accounting. Price realizations for natural gas during the current quarter
equaled $9.14 per Mcf before the impact of settled derivative contracts, or
approximately $0.08 above the average Henry Hub price, which is calculated on
an MMbtu basis. When taking into account the impact of settled derivatives
during the quarter, the realized price for natural gas was $8.88 per Mcf. For
crude oil, the realized price during the quarter was $117.65 per barrel (the
Company had no derivative contracts outstanding on crude oil during the
quarter).
Discretionary cash flow ("DCF"), defined as net cash provided by operating
activities before changes in working capital, increased to $26.0 million in
the quarter (excluding the $146 million gain on the sale of undeveloped
leasehold rights), up 51% from $17.2 million for the third quarter of 2007.
It should be noted that while the gain on sale of certain deep rights in North
Louisiana has been excluded from the calculation of DCF, the taxes provided
for (due primarily to this sale) are only partially recovered in the DCF
calculation. Specifically, the standard DCF calculation only adds back to cash
flow the portion of the tax provision related to deferred taxes. In this
case, however, there are approximately $12.7 million of current taxes, all of
which are due to the previously mentioned sale transaction, which have had the
impact of reducing DCF by $12.7 million. If one attempts to calculate a cash
flow measure which completely excludes all impacts of the sale transaction,
this $12.7 million should be added back to the above DCF number (see
accompanying table for a reconciliation of discretionary cash flow, a non-GAAP
measure, to net cash provided by operating activities).
Operating income (loss) (defined as revenues less lease operating
expenses, production taxes, transportation, DD&A, exploration and general and
administrative expenses), without including realized gains or losses on
derivatives and income from discontinued operations, was a total of $158.0
million for the quarter, versus an operating loss of $8.5 million in the third
quarter of 2007. It should be noted that Operating Income for the quarter
includes the $146 million gain on sale of deep interests in North Louisiana.
Excluding the gain on sale of deep rights, the Company would have had
operating income of $12 million.
Gain (loss) on derivatives not designated as hedges. The Company had a
gain on derivatives not designated as hedges for the quarter of $83.5 million,
which includes a realized loss of $1.6 million and an $85.3 million unrealized
gain on the Company's portfolio of gas hedges, versus a gain of $2.4 million
during the prior year's quarter.
Income tax expense for the quarter totaled $42.1 million versus $11.6
million in the third quarter of 2007. During the third quarter of 2008, as
previously mentioned, the Company recognized a $146 million gain on the sale
of undeveloped leasehold costs by virtue of its sale of certain deep interests
in North Louisiana. As a result of the taxable income generated by this sale,
in addition to the Company's normal operations, it is now more likely than not
that the Company will be in a position to utilize the majority of its net
operating loss ("NOL") carryforwards when filing its 2008 Federal income tax
return. As such the Company is releasing an appropriate amount of the
valuation allowance previously booked against the deferred tax assets
resulting from the NOL carryforwards. The chart below details the components
of the Company's income tax provision for the nine months ended 9/30/2008 (in
$ 000's):
Income before taxes 176,905
Estimated taxes using the 35% FIT rate $ 61,917
Estimated prorated state taxes due for FY 2008 $ 5,740
Impact of release of valuation allowance ($ 25,528)(1)
Income tax expense $ 42,129
Income from continuing operations $ 134,776
Current Taxes $ 12,679
Deferred Taxes$ 29,450
(1) The amount of the valuation allowance released is approximately equal
to the estimated Federal income tax rate of 35% multiplied by the
amount of the NOL carryforwards estimated to be used or useable in the
future, including the current fiscal year.
LIQUIDITY AND LEVERAGE POSITION
The Company finished the quarter with $224 million in cash and cash
equivalents and zero outstanding on its bank revolving credit facility. Based
on current commodity prices, the Company's existing natural gas hedges and
expected production levels over the next twelve months (assuming no shut in
production as a result of external issues such as hurricanes or infrastructure
delays), the Company anticipates that it can accomplish the following :
1) grow 2009 production volumes by approximately 30 - 40% over 2008
levels with a preliminary 2009 capital expenditure budget of
$300 million,
2) fund the capital expenditure budget with cash flow from operations and
available cash, and
3) exit 2009 with zero outstanding on its bank revolving credit facility.
As a result of our strong liquidity position, the Company elected to
maintain the Borrowing Base at the existing level of $175 million even though
a majority of the bank group indicated that under their customary engineering,
pricing and lending policies and practices in effect in October of 2008, GDP's
proved reserves would likely result in a Borrowing Base in excess of $200
million. Given expected growth in the Borrowing Base due to the Company's
ongoing development drilling program, the Company anticipates that the
combination of unused borrowing availability and short term investments will
approximate $275 to $300 million as the Company enters 2010.
As of September 30, 2008, the Company's ratio of net debt to total capital
(total outstanding debt, net of cash and cash equivalents divided by total
outstanding debt, net of cash and cash equivalents, plus total stockholders
equity) stood at 3.9%.
OPERATING EXPENSES
Lease operating expense ("LOE") for the quarter was $8.2 million, or $1.29
per Mcfe, compared to $5.2 million, or $1.22 per Mcfe for the third quarter of
2007. LOE increased on a per unit basis by 6% per Mcfe from the third quarter
of 2007, and by 57% in absolute terms over the prior year period. Per unit
LOE was negatively impacted during the quarter by reduced volumes due to the
majority of the Company's production being shut-in during Hurricane Ike
(approximately 300 MMcfe during the month of September). The absolute dollar
increase was driven largely by an increase in the number of producing wells
and the 48% increase in production, with the per unit increase due primarily
to higher salt water disposal ("SWD") and compressor costs on a per unit
basis. As the Company still has additional SWD cost reduction projects in
process at several major fields, we expect to see continued improvement in
this expense category.
Depreciation, depletion and amortization ("DD&A") expense. The Company
utilizes the successful efforts method of accounting, whereby the majority of
DD&A expense is represented by capitalized drilling and completion costs
divided by proved developed reserves only, based on the most recent reserve
report prepared by the Company's third party independent engineering firm.
For the third quarter of 2008 the Company's mid year reserve report resulted
in a decrease in the per unit DD&A rate to $4.17 per Mcfe, which represented a
$0.60 per Mcfe decrease from the $4.77 per Mcfe rate in the third quarter of
last year, and a 13% decrease from the second quarter of 2008. On an absolute
dollar basis, the DD&A expense of $26.4 million in the third quarter compared
to $20.4 million recognized in the third quarter of 2007, with the increase
due solely to the increased level of production.
General and administrative ("G&A") expense decreased by approximately 17%
on a per unit basis from $1.18 per Mcfe in the third quarter of 2007 to $0.98
per Mcfe in the third quarter of 2008. The increase in total G&A expense from
$5.1 million in the prior year period to $6.2 million in the current quarter
was driven largely by an 18% increase in employee headcount over the same
period. Stock based compensation, which is a non-cash item included in G&A,
amounted to approximately 23% of total G&A, or $1.4 million in the current
quarter, versus $1.6 million for the prior year period.
Production and other taxes for the quarter were up slightly on a per unit
basis from the prior year period, at $0.33 per Mcfe this quarter versus $0.30
in the prior year. Net production and other tax expense in the quarter was
$2.1 million versus $1.3 million in the third quarter of 2007. Production and
other taxes for the quarter consisted of $1.6 million of production taxes and
$0.5 million of ad valorem taxes. Production taxes are net of $0.9 million of
accrued tight gas sands credits for the Company's wells in the state of Texas.
During the third quarter of 2007, production and ad valorem taxes totaled $0.6
million and $0.7 million, respectively.
Exploration expense per unit decreased by 20% to $0.33 per Mcfe during the
quarter from $0.41 per Mcfe during the prior year period, due largely to the
spreading of this primarily fixed cost category over a larger production base.
The total dollar exploration expense increased from $1.8 million in the third
quarter of 2007 to $2.1 million in the current quarter due primarily to an
increase in non-cash undeveloped leasehold amortization, which increased from
$1.5 million to $1.7 million over the period.
Impairment of oil and gas properties for the quarter totaled $1.1 million
based upon a re-evaluation of all of the Company's properties upon receipt of
the independent engineer's mid-year report on reserves. All of the expense
relates to two non-core fields located in Louisiana and Texas.
CAPITAL EXPENDITURES
Capital expenditures for the quarter totaled $103.0 million compared to
$81.3 million in the third quarter of 2007. Of the $103.0 million, $87.4
million was incurred on the drilling and completion of Cotton Valley Trend
wells during the quarter, $13.3 million was incurred on leasehold acquisitions
and $2.3 million was incurred on infrastructure and other costs. Although the
Company conducted drilling and/or completion operations on 38 gross wells
during the quarter, capital expenditures in excess of $0.25 million per well
were recorded on over 70 wells during this period. The Company funded its
capital expenditures in the quarter through a combination of cash flow from
operations and available cash.
The Company has established a preliminary capital expenditure budget for
2009 of $300 million, down approximately 15% from the $350 million capital
expenditure budget for 2008. Approximately 60% of the budget is currently
estimated to be spent drilling Haynesville Shale horizontal wells, with the
majority of the remaining 40% allocated to drilling James Lime horizontal
wells, Cotton Valley Taylor sand horizontal wells and vertical Travis Peak
wells. The Company expects to fund the 2009 capital expenditure budget from
cash flow from operations and available cash, which is currently $224 million.
OPERATIONS
Production for the quarter from continuing operations was 6.3 Bcfe, or
approximately 69,000 Mcfe per day, representing a 48% increase over the prior
year period volumes of 4.3 Bcfe or 47,000 Mcfe per day. The Company completed
26 wells during the quarter (down from 35 wells completed in the second
quarter of 2008), and production for the quarter was negatively impacted by
Hurricane Ike, which caused the Company to shut in approximately 300 million
cubic feet equivalent of cumulative production over an approximate ten day
period. Natural gas comprised 96% of the Company's production for the
quarter. All of the Company's production volume increases were achieved from
organic drill bit growth in the Cotton Valley Trend. The Company anticipates
production for the fourth quarter to average 72,000 to 75,000 Mcfe per day, or
approximately 4% - 9% sequential growth over the third quarter. The Company's
fourth quarter guidance is impacted by delays resulting from (1) longer cycle
times associated with the drilling of Haynesville Shale horizontal wells; (2)
pipeline and infrastructure installation for the Company's initial four
discovery wells drilled on its Surprise prospect at Angelina River Trend; and
(3) third party pipeline and gathering system maintenance in the Beckville and
Minden areas, all of which will contribute to an estimated number of fourth
quarter completions ranging from 18 to 22 wells. For 2009, the Company
anticipates growing production volumes by 30 - 40% over average 2008 levels
with its preliminary capital expenditure budget of $300 million.
Drilling operations continued at an aggressive pace in the Cotton Valley
Trend, with the Company conducting drilling operations on 38 wells in the
quarter. The Company completed and added to production 23 wells in five
fields during the quarter, with an average gross initial production rate of
approximately 2,500 Mcfe per day.
Year to date, the Company has completed 89 wells, with an average initial
production rate of approximately 2,600 Mcfe per day, with 11 wells in
completion stage but not producing on September 30, 2008. Field by field
initial production rates for the wells completed in 2008 through the third
quarter, are as follows:
Field No. of Wells Initial Production Rate
* Minden 21 1,850 Mcfe/day
* Beckville5 1,900 Mcfe/day
* Bethany-Longstreet 17 1,525 Mcfe/day
* South Henderson 10 2,200 Mcfe/day
* Angelina River 35 3,800 Mcfe/day
* Other1 2,000 Mcfe/day
At September 30, 2008, the Company had 366 wells producing in the Cotton
Valley Trend and 11 being completed, with a success rate with in the Trend of
over 99%. At September 30, 2008 the Company had 389 wells that were drilled
and logged at the following fields:
FieldNo. of Wells
* Minden110
* Beckville 73
* Bethany Longstreet 50
* South Henderson33
* Angelina River Trend 79
* Others 44
Cotton Valley Trend acreage at September 30, 2008 was approximately
200,000 gross and 127,000 net acres.
BETHANY-LONGSTREET AND LONGWOOD FIELDS, CADDO AND DESOTO PARISHES,
LOUISIANA
The Company has three non-operated rigs currently drilling horizontal
Haynesville Shale wells on the Chesapeake joint venture acreage in the
Bethany-Longstreet and Longwood fields. At Bethany-Longstreet, the Chesapeake
-- Holland 17H-1 (50% WI) was spud on September 22nd and the Chesapeake --
Dorothy Branch 11H-1 (50% WI) was spud on October 29th. Both wells have an
estimated length of lateral of approximately 4,000 feet. At Longwood, the
Chesapeake -- Percy Sharp 7H-1 (50% WI) was spud on October 18th, with an
expected lateral of approximately 4,000 feet. The Company has also drilled
its Lona Johnson 21-1 (50% WI), an additional vertical well at Longwood.
CADDO PINE ISLAND FIELD, CADDO PARISH, LOUISIANA
The Company has drilled and logged its Lanier 16-1 (50% WI) on the Matador
joint venture acreage in the Caddo Pine Island field. The well encountered
287 feet of pay in the Haynesville Shale and is currently scheduled to be
re-entered and drilled horizontally in the first quarter of 2009. The Company
has two non-operated rigs currently running in the field. The Hall 5H-1
(50% WI), which was initially drilled as a vertical test, was re-entered and
commenced horizontal drilling operations on October 15th. Results from the
well are expected around the end of the year. The Company is also
participating in the Ballco Farms 7 No. 1 (41% WI), the fifth vertical well
drilled in the field, which spud on October 12th. It is anticipated that each
of the five vertical wells drilled in the field to date will be re-entered and
drilled horizontally in the fourth quarter of 2008 or first quarter of 2009.
BECKVILLE AND MINDEN FIELDS, PANOLA AND RUSK COUNTIES, TEXAS
The Company has drilled five vertical Haynesville Shale wells in the area,
and expects to commence operations on its initial horizontal well, the
Lutheran Church 5H-1 (100% WI) in November. The Company has commenced
operations on its initial Cotton Valley Taylor sand horizontal well in
Beckville, the GW Waldrop 3H -1 (100% WI), with an expected lateral of
approximately 3,000 feet.
SOUTH HENDERSON, RUSK COUNTY, TEXAS
The Company drilled and completed its Robert Youngblood No. 8 (100% WI), a
vertical Haynesville Lime well, with an initial production rate of 1,000 Mcfe
per day. The Company has plans to drill a horizontal Haynesville Lime well in
the field in 2009.
ANGELINA RIVER TREND, ANGELINA AND NACOGDOCHES COUNTIES, TEXAS
The Company completed three James Lime horizontal wells in the quarter.
The USA LB 2H (57% WI) had an initial production rate of 12,900 Mcfe per day,
the West Esparza 1H (57% WI) had an initial production rate of 5,300 Mcfe per
day and the Bob Sessions 4H (100% WI) had an initial production rate of 4,400
Mcfe per day. The Company is currently drilling its Estes 4H-1 (100% WI), a
horizontal James Lime well in the middle of its Cotton South prospect area.
The Company has drilled and logged two discoveries on its Surprise
prospect, the Grigsby No. 1 (50% WI) and Lilly No. 1 (50% WI). Both wells,
which are awaiting completion, encountered pay in the James Lime and Travis
Peak formations. The Company is currently drilling a third well, the Tucker
No. 1 (50% WI) which will test the Haynesville Shale and the Hill No. 1 (50%
WI), which is planned to test the James Lime and Travis Peak, and may be taken
deeper to the Haynesville Shale. Completion of the first two wells is
anticipated by the end of November, the Tucker No. 1 is scheduled to be
completed in December and the Hill No. 1 in January. The Company owns a 50%
interest in 6,000 acres in the prospect area. Total acreage in the Angelina
River Trend is currently approximately 81,000 gross, 41,000 net acres.
Commenting on the quarter, Vice Chairman and CEO, Gil Goodrich, stated
"The third quarter results of $195 million of net income illustrate the
positive benefits of the actions taken during the quarter, the value of our
assets and the benefits of our core strategy to hedge future production. Due
to the proactive steps taken early in the third quarter, including our
previously announced joint venture in the Haynesville Shale play and our
follow on equity offering, we ended the quarter with approximately $224
million in cash and short term investments, no borrowings under our senior
credit facility and a net debt to capital ratio of just under 4%. With
approximately $400 million in available capital and liquidity, we believe we
are uniquely positioned to adjust the amount and timing of our 2009 capital
expenditure plans based on prevailing market conditions. While we hope and
expect conditions to improve over the course of 2009, we believe current
market conditions call for a cautious approach. As such, our board has
approved a preliminary capital expenditure budget for next year which would
reduce our investments by approximately 15% compared to 2008 to approximately
$300 million. While this level of investment is designed to preserve cash, we
are also extremely excited about the potential for the Haynesville Shale play
and believe it will have a significant positive impact on both production and
reserve growth in 2009. Our preliminary plan calls for approximately 60% of
the budget to be earmarked for horizontal development of the Haynesville Shale
and net production volumes to grow by approximately 30% to 40% over 2008. We
are currently drilling four horizontal Haynesville wells in northwest
Louisiana and while these longer cycle time wells may limit fourth quarter
sequential production growth, we believe they will provide an excellent jump
start on horizontal Haynesville activity and first quarter 2009 production.
Our strong balance sheet and the wonderful mix within our project inventory
provide us the opportunity to both emphasize Haynesville Shale development and
fund our entire 2009 investments from anticipated cash flow and cash on hand
and likely enter 2010 with cash remaining on the balance sheet and no
borrowings under our senior credit facility."
OTHER INFORMATION
In this press release, the Company refers to two non-GAAP financial
measures, EBITDAX and discretionary cash flow, because of management's belief
that these measures are financial indicators of the Company's ability to
internally generate operating funds. Management also believes that these non-
GAAP financial measures of operating income and cash flow are useful
information to investors because they are widely used by professional research
analysts in the valuation and investment recommendations of companies within
the oil and gas exploration and production industry. EBITDAX and
discretionary cash flow should not be considered as alternatives to operating
income or net cash provided by operating activities, as defined by GAAP.
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, 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 and
other 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.
Initial production rates stated in this release are expected to differ
substantially from longer term average production rates. Forward looking
estimates of production growth assume drilling results comparable to recent
priorperiods, which may not be realized.
Goodrich Petroleum is an independent oil and gas exploration and
production company listed on the New York Stock Exchange. The majority of its
properties are in Louisiana and Texas.
GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
Total Revenues $60,376 $27,280 $171,902 $78,828
Operating Expenses
Lease operating expense8,165$5,21522,931 $15,500
Production and other taxes 2,110 1,292 5,699 996
Transportation 2,224 1,715 6,480 4,230
Depreciation, depletion and
amortization 26,41420,43480,53257,603
Exploration2,062 1,754 5,841 5,847
Impairment of oil and gas
properties1,059 282 1,059 282
General and administrative 6,207 5,05417,56715,892
Gain on sale of assets (145,868) -(145,868) -
Operating income (loss) 158,003(8,466) 177,661 (21,522)
Other income (expense)
Interest expense (3,886) (3,086) (12,059) (7,932)
Interest income1,260 - 1,260 -
Gain (Loss) on derivatives
not designated as hedges 83,477 2,37810,043(3,475)
80,851 (708) (756) (11,407)
Income (loss) from continuing
operations before income taxes 238,854(9,174) 176,905 (32,929)
Income tax expense (42,129) (11,641) (42,129) (3,379)
Income (loss) from continuing
operations 196,725 (20,815) 134,776 (36,308)
Discontinued operations:
Gain (loss) on disposal,
net of tax (252) (928) 28 9,823
Income (loss) from
discontinued operations,
net of tax (44) (401) 240 2,078
(296) (1,329) 26811,901
Net income (loss) 196,429 (22,144) 135,044 (24,407)
Preferred stock dividends 1,512 1,511 4,535 4,535
Net income (loss) applicable to
common stock $194,917 $(23,655) $130,509 $(28,942)
Income (loss) per common share
from continuing operations
Basic $5.51$(0.83)$3.93$(1.44)
Diluted$4.69$(0.83)$3.47$(1.44)
Income (loss) per common share
from discontinued operations
Basic $(0.01) $(0.05)$0.01 $0.47
Diluted $(0.01) $(0.05)$0.01 $0.47
Net income (loss) per common share
applicable to common stock
Basic $5.50$(0.94)$3.94$(1.15)
Diluted$4.68$(0.94)$3.48$(1.15)
Weighted average common shares
outstanding:
Basic 35,44025,20433,09825,177
Diluted 42,18525,20439,75625,177
GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
Three Months Nine Months
EndedEnded
September 30,September 30,
2008 20072008 2007
Calculation of EBITDAX:
Revenue 60,376 27,280 171,902 78,828
Lease operating expense (8,165) (5,215) (22,931) (15,500)
Production and other taxes (2,110) (1,292) (5,699)(996)
Transportation (2,224) (1,715) (6,480) (4,230)
G&A - cash portion only (4,904) (3,485) (13,557) (11,642)
Realized gain (loss) on
derivatives not designated as
hedges(1,854) 3,672 (3,436) 8,499
EBITDAX 41,119 19,245 119,799 54,959
Reconciliation of EBITDAX to Net Cash
Provided by Operating Activities:
EBITDAX 41,119 19,245 119,799 54,959
EBITDAX - Discontinued Operations 85 302 3695,746
Exploration (2,062) (1,754) (5,841) (5,847)
Prospect amortization1,720 1,6634,1695,095
Interest expense(3,886) (3,086) (12,059) (7,932)
Interest income 1,260 - 1,260 -
Current Income taxes (12,679)-(12,679) -
Other non-cash items 409 8051,365 400
Net changes in working capital 15,159 4,4971,8389,167
Net cash provided by operating
activities (GAAP) 41,125 21,672 98,221 61,588
Reconciliation of Discretionary Cash
Flow to Net Cash Provided by Operating
Activities:
Discretionary cash flow 25,966 17,175 96,383 52,421
Net changes in working capital 15,159 4,4971,8389,167
Net cash provided by operating
activities (GAAP) 41,125 21,672 98,221 61,588
Selected Operating Data:
Three Months Nine Months
EndedEnded
September 30,September 30,
2008 20072008 2007
Production - Continuing Operations:
Natural gas (MMcf) 6,088 4,101 16,962 10,846
Oil and condensate (MBbls) 40 30 123 84
Total (Mmcfe)6,328 4,281 17,700 11,350
Average sales price per unit:
Natural gas (per Mcf)$9.14 $6.09$9.29$6.73
Oil (per Bbl) 117.65 73.32 112.2864.12
Natural gas and oil (per Mcfe)9.546.34 9.68 6.90
Expenses per Mcfe:
Lease operating expense $1.29 $1.22$1.30$1.37
Production and other taxes0.330.30 0.32 0.09
Transportation0.350.40 0.37 0.37
DD&A 4.174.77 4.55 5.08
Exploration 0.330.41 0.33 0.52
Impairment expense0.170.07 0.06 0.03
General and administrative0.981.18 0.99 1.40
SOURCE Goodrich Petroleum Corporation
