Goodrich Petroleum Announces Year End and Fourth Quarter Financial Results
- Company Completes Strategic Shift from Predominately Vertical to Horizontal Drilling
- Horizontal Drilling Success Leads to Annual Production Growth of 24% and Proved Reserve Growth of 4.5%
- Discretionary Cash Flow Increases 23% to a Record $140 Million
- Company Ends Year with Liquidity of $300 Million, Including Cash and Short Term Investments of $125 Million
- Per Unit Lease Operating Expense for the Fourth Quarter Decreases by 38% from the Prior Year Period to $0.86 per Mcfe
- Provides Lower DD&A Guidance for First Half of 2010 Following Non-Cash Impairment Charge
HOUSTON, Feb. 24 /PRNewswire-FirstCall/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the year and quarter ended December 31, 2009.
The Company announced a net loss applicable to common stock of $257.0 million for the year ended December 31, 2009, or ($7.17) per basic share, versus net income applicable to common stock of $115.7 million, or $3.42 per basic share, $3.23 per diluted share for the year ended December 31, 2008. The primary reason for the loss in 2009 was a $185.4 million non-cash impairment charge taken in the fourth quarter relating to the Company's strategic move away from drilling predominantly vertical Cotton Valley and Travis Peak wells and the resultant removal of such well locations from the Company's reserves and inventory as discussed hereafter. The comparable period of 2008 includes a pre-tax gain on sale of assets of $145.9 million.
CHANGING BUSINESS STRATEGY
During 2009, the Company initiated a strategic change in its business strategy to transition from a company drilling predominately vertical wells to one drilling almost exclusively horizontal wells. At the end of 2009, and after evaluating the success of its horizontal drilling programs in both the Haynesville Shale and the Cotton Valley (Taylor) Sand, as well as the new reserve guidelines promulgated by the SEC, the Company decided to remove all vertical proved undeveloped and probable drilling locations from its reserves and inventory. Walter G. "Gil" Goodrich, Vice Chairman and CEO commented, "2009 was clearly a transformational year for Goodrich Petroleum. A year ago, the Haynesville Shale constituted only 1% of proved reserves and a negligible percentage of production. Today, the Haynesville Shale represents 47% of the Company's proved reserves and 42% of fourth quarter 2009 production. Consistent with the transformation we have undergone on the operating side, our financials this year reflect management's strategic decision to remove all vertical proved undeveloped and probable locations both from our proved reserves and impairment test calculation. This transition provides for a greater quality of proved reserves, with much better estimated finding and development costs on the Company's undeveloped reserves, along with more closely aligning our proved undeveloped locations with our development plans going forward. However, the current net impact of this decision was the large non-cash impairment charge in the fourth quarter, which clearly overwhelmed much of what we did financially during the year. When adjusting for this and other non-cash charges, our discretionary cash flow was an all time record of $140.0 million for the year. In addition, we are confident that our financial statements going forward will be a better reflection of this new business strategy, which is keenly focused on creating value via developing our attractive acreage position through horizontal drilling technology. As such, we are providing guidance for our reduced DD&A rate in the first half of 2010 of $3.50 to $3.90 per Mcfe or a reduction of approximately 40% from the fourth quarter of 2009. With this improved outlook, the success of our horizontal Haynesville Shale and Cotton Valley (Taylor) Sand wells drilled thus far, as well as our continued strong liquidity position of approximately $300.0 million at year end and our current hedge position, our Board has recently increased our planned 2010 capital expenditures by approximately 10% to $255.0 million, which we are confident will lead to another year of strong growth in reserves, production and cash flow."
CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX") increased 45% to approximately $39.1 million for the fourth quarter, compared to $26.9 million in the prior year period. EBITDAX for the year was down only slightly from last year's record level despite lower realized natural gas prices in 2009 versus 2008, to $141.8 million, compared to $146.7 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities).
Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, increased to $48.9 million in the quarter, a 181% increase compared to $17.4 million in the prior year period. Note that DCF for the fourth quarter of 2009 was positively impacted by approximately $15.3 million in adjustments related to tax refunds available to the Company as a result of carrying back to recoup last year's cash tax payments to state and federal taxing authorities. Even without this benefit, DCF would have exceeded last year's fourth quarter amount by 93%. Discretionary cash flow increased to $140.0 million for the year, a 23% increase over the $113.8 million in the prior year period. Again, without the $15.3 million benefit recognized in the fourth quarter of 2009, DCF for the year would have exceeded last year's amount by 9%. Net cash provided by operating activities was $115.6 million for the year, compared to $107.0 million for the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).
IMPAIRMENT CHARGE IN FOURTH QUARTER
As a successful efforts company, we are required to perform an impairment test any time conditions have changed to such extent that management feels any of its long term assets may be impaired to the extent that the Company will not ultimately be able to recover the cost at which the assets are carried on its books. In practice, the Company generally performs this test in conjunction with its receipt of the mid-year and year-end reserve reports. As impairment test economics are run, companies are allowed to consider all possible sources of revenue for each field being tested, and management has made the determination in the past to include all proved reserve categories, in addition to probable reserves reasonably expected to be drilled by the Company at some point in the future. This year, however, as the Company assessed its ongoing strategy of drilling only horizontal wells in the Haynesville Shale and Cotton Valley (Taylor) Sand, virtually all vertical locations were removed from the drilling plan, which locations had in effect served to enhance the undiscounted value of specific fields in the past. Once these locations were removed, many of the fields where the Company had historically been active drilling vertical Cotton Valley and Travis Peak wells, and had not yet been sufficiently proven up or de-risked utilizing horizontal drilling, became impaired under the definition in the test, with the end result being a total $185.4 million impairment in the fourth quarter.
YEAR END RESERVES AND PRODUCTION
As previously released, the Company's fully engineered year-end 2009 reserve report from Netherland, Sewell & Associates, Inc. (NSAI) resulted in a 4.5 % increase in total proved reserves to 421 Bcfe, and an 8.5% increase in proved developed reserves to 166 Bcfe. Both fourth quarter production volumes of 86.1 MMcfe per day and average daily 2009 production volumes of 81.6 MMcfe per day were up significantly from the prior year periods, with the fourth quarter 2009 being up by 22% over the prior year period and the full year average being up by 24% over full year 2008.
The Company reaffirms its first quarter 2010 production guidance of an average 88,000 to 91,000 Mcf per day, and full year guidance of 15 to 25% year-over-year production growth.
CAPITAL EXPENDITURES
Capital expenditures for the fourth quarter of 2009 totaled $44.0 million, of which $33.3 million was spent on drilling and completions and $10.7 million on acreage and other expenditures. For the full year 2009, total capital expenditures booked during the year totaled $237.6 million, of which $215.1 million was for drilling and completion costs, while $22.5 million was for leasehold, infrastructure, and other expenditures. As we have previously mentioned, given the Company's accelerated drilling operations at year-end 2008, a number of capital expenditures were booked during 2008 but not paid until 2009. The total of this category, which was paid during 2009, was approximately $28.6 million, which amount should be added to the $237.6 million in capital expenditures booked during the year to arrive at the cash flows from investing activities in the Company's annual report on Form 10-K for FY 2009, expected to be filed on or about February 26, 2010.
For the year 2010, the Company has preliminarily budgeted total capital expenditures of approximately $255.0 million, of which approximately 78%, or $200.0 million, is currently expected to be focused on drilling horizontal wells in the Haynesville Shale program in East Texas and Northwest Louisiana. The remainder of the budgeted amount is earmarked for several Cotton Valley (Taylor) Sand horizontal wells in East Texas, and various leasehold and infrastructure expenditures as needed across the Company's acreage block.
LIQUIDITY
The Company exited 2009 with approximately $125.0 million in cash and short term investments and no borrowings under its senior bank revolving credit facility, under which the Company currently has a borrowing base of $175.0 million. When considering the Company's strong cash and short term investment balances at year-end, and our previously stated 15 to 25% production growth forecast for 2010, we believe we will not need to draw any material amounts under our bank credit facility, nor will we need to access the capital markets during 2010 in order to fund our current capital expenditure budget of $255.0 million. Rather, we expect to finance these expenditures through a combination of cash flow from operations and cash and short term investments on hand at December 31, 2009. This is predicated upon numerous assumptions as to oil and gas prices, drilling activity and resultant production additions, and many other factors which are subject to change and are outside of the Company's control.
REVENUES
Given the 41% reduction in average gas price realizations between the fourth quarter of 2008 and the fourth quarter of 2009, total revenues for the quarter were down by 27% from the prior year period, even though production volumes were up by 22%. Similarly, for the full year, total revenues were down by 49% in 2009 from the 2008 levels, due primarily to a 59% reduction in the average gas price received over the full year period.
Total revenues and average prices do not include realized gains of $21.5 million from hedges in the fourth quarter and $96.5 million in the full year 2009, as none of our oil and gas derivatives were designated as hedges during any part of fiscal year 2009.
OPERATING INCOME
Operating income, defined as revenues minus operating expenses, was a loss of $220.5 million for the quarter versus an operating loss of $32.2 million for the prior year period, primarily due to the $185.4 million impairment charge taken during the fourth quarter of 2009, as previously discussed. Operating income for the year was a loss of $339.7 million, due to the fourth quarter impairment charge and a similar charge taken earlier in the year, as well as the higher DD&A rate experienced by the Company in 2009, versus operating income for 2008 of $145.4 million, which included a $145.9 million gain on the sale of assets.
OPERATING EXPENSES
Including the previously mentioned impairment charge, operating expenses were $252.7 million during the quarter. Lease operating expense (LOE) decreased by 24% to $6.8 million in the quarter, or $0.86 per Mcfe, versus $9.0 million, or $1.39 per Mcfe during the fourth quarter of 2008. For the year, LOE totaled $30.2 million, or $1.01 per Mcfe, versus $32.0 million, or $1.32 per Mcfe in 2008, with the decrease on a per unit basis due primarily to the increasing production contribution from our Haynesville Shale wells, which carry much lower operating costs than our heritage Cotton Valley and Travis Peak wells.
General and Administrative (G&A) expenses were $7.4 million during the quarter, or $0.93 per Mcfe, versus $6.7 million, or $1.03 per Mcfe for the prior year period. Absolute G&A expenses were higher over the prior year period due primarily to an increase in personnel and non-cash compensation. For the year, G&A expenses totaled $27.9 million, or $0.94 per Mcfe, versus $24.3 million, or $1.00 per Mcfe for the full year 2008. For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers, employees and directors of $2.0 million. For the full year, the Company recorded non-cash G&A expense related to stock based compensation of approximately $6.8 million, or approximately 24% of total G&A for the year.
Depreciation, Depletion and Amortization (DD&A) expense for the quarter totaled $48.1 million, or $6.07 per Mcfe, versus $26.6 million or $4.11 per Mcfe during the fourth quarter of 2008. While DD&A expense for the quarter was negatively impacted by an additional $4.1 million adjustment related to the first three quarters of the year, the full year DD&A expense per unit of production was up approximately 21% from $4.43 per Mcfe in 2008 to $5.38 per Mcfe in 2009. This per unit increase was primarily a function of the lower proved developed reserve balance at mid-year 2009 versus year-end 2008, due to lower effective prices. This reduced proved developed reserve balance at mid-year increased the third and fourth quarter DD&A expense rates and thus had the impact of increasing full year DD&A expenses as just described. Considering the impact of the previously discussed impairment, and based on the year-end reserve report as prepared by NSAI, the Company currently estimates that its DD&A rate for the first six months of 2010 will be in the range of $3.50 to $3.90 per Mcfe, depending on the relative production mix experienced during the first half of the year. As has been the Company's practice, the DD&A rate will be reviewed for further adjustment upon completion of its mid-year reserve report, which typically occurs before the end of the third quarter.
COMMODITY HEDGE POSITION
As of December 31, 2009, the Company had 50,000 MMbtu per day hedged for all of calendar year 2010 via a series of costless collars. The collars have floors of $6.00 per MMbtu, with various ceiling prices ranging from $6.95 to $7.40, with an average ceiling price for 2010 of $7.10 per MMbtu. For 2011 and 2012, we have 40,000 MMbtu per day hedged at floor prices of $6.00, with average ceiling prices each year of $7.09 per MMbtu. Additionally, the Company has locked in its basis on 50,000 MMbtu per day of future volumes, at a $0.37 per MMbtu deduction from Henry Hub for all of 2010.
OPERATIONAL UPDATE
Louisiana
Bethany-Longstreet Field, Caddo and DeSoto Parishes, Louisiana. The Company has completed its Goodrich Petroleum Company - Fallon 18H-1 (59% WI) in the Bethany-Longstreet field with a 24-hour peak initial production rate of 21,200 Mcf per day on a 24/64 inch choke with 6,800 psi.
Greenwood-Waskom Field, Caddo Parish, Louisiana. The Company has also completed its Goodrich Petroleum Company - Wills 14H-1 (81% WI) in the Greenwood-Waskom field with a 24-hour peak initial production rate of 12,000 Mcf per day on a 22/64 inch choke with 5,800 psi.
OTHER INFORMATION
In this press release, the Company refers to several non-GAAP financial measures, EBITDAX and discretionary cash flow. Management believes that these two measures are good financial indicators of the Company's ability to internally generate operating funds. Management also believes that these non-GAAP financial measures provide 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. Neither discretionary cash flow nor EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by GAAP.
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 gas resource plays and tight gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
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 SEC. 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 Corporation 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 Year Ended
December 31, December 31,
------------ ------------
2009 2008 2009 2008
---- ---- ---- ----
Total Revenues $32,177 $44,149 $110,426 $216,051
Operating Expenses
Lease operating expense 6,845 9,019 30,188 31,950
Production and other taxes 486 1,843 4,317 7,542
Transportation 1,980 2,165 9,459 8,645
Depreciation, depletion
and amortization 48,103 26,591 160,361 107,123
Exploration 2,488 2,563 9,292 8,404
Impairment of oil and
gas properties 185,415 27,523 208,905 28,582
General and administrative 7,351 6,687 27,923 24,254
Gain on sale of assets (2) (8) (297) (145,876)
Operating income (loss) (220,489) (32,234) (339,722) 145,427
Other income (expense)
Interest expense (8,996) (5,439) (26,148) (22,410)
Interest income 46 924 433 2,184
Gain on derivatives not
designated as hedges 9,098 41,504 47,115 51,547
148 36,989 21,400 31,321
Income (loss) from
continuing operations
before income taxes (220,341) 4,755 (318,322) 176,748
Income tax benefit (expense) 30,766 (3,854) 67,311 (54,472)
Income (loss) from
continuing operations (189,575) 901 (251,011) 122,276
Discontinued operations:
Gain on disposal, net of tax - 1 - 29
Income (loss) from
discontinued operations,
net of tax (54) (771) 25 (531)
(54) (770) 25 (502)
Net income (loss) (189,629) 131 (250,986) 121,774
Preferred stock dividends 1,511 1,512 6,047 6,047
Net income (loss)
applicable to common stock $(191,140) $(1,381) $(257,033) $115,727
Per Common Share
Income (loss) from continuing
operations - basic $(5.30) $(0.02) $(7.00) $3.61
Income (loss) from continuing
operations - diluted $(5.30) $(0.02) $(7.00) $3.24
Loss on discontinued
operations, net of tax -
basic $- $(0.02) $- $(0.01)
Loss on discontinued
operations,
net of tax - diluted $- $(0.02) $- $(0.01)
Net income (loss)
applicable to
common stock - basic $(5.34) $(0.04) $(7.17) $3.42
Net income (loss)
applicable to
common stock - diluted $(5.34) $(0.04) $(7.17) $3.23
Weighted average common
shares outstanding - basic 35,790 35,904 35,866 33,806
Weighted average common
shares outstanding - diluted 35,790 35,904 35,866 40,397
GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
Three Months Ended Year Ended
December 31, December 31,
------------- ------------
2009 2008 2009 2008
---- ---- ---- ----
Calculation of EBITDAX:
Revenue 32,177 44,149 110,426 216,051
Lease operating expense (6,845) (9,019) (30,188) (31,950)
Production and other taxes (486) (1,843) (4,317) (7,542)
Transportation (1,980) (2,165) (9,459) (8,645)
G&A - cash portion only (5,342) (5,204) (21,172) (18,761)
Realized gain (loss) on
derivatives not designated
as hedges 21,549 988 96,549 (2,448)
EBITDAX 39,073 26,906 141,839 146,705
Reconciliation of EBITDAX to Net
Cash Provided by Operating
Activities:
EBITDAX 39,073 26,906 141,839 146,705
EBITDAX - Discontinued Operations (54) 28 25 397
Exploration (2,488) (2,563) (9,292) (8,404)
Prospect amortization 1,011 1,669 4,927 5,838
Exploration non-cash - 312 219 312
Interest expense (8,996) (5,439) (26,148) (22,410)
Interest income 46 924 433 2,184
Current income taxes 15,346 (6,958) 15,452 (19,637)
Amortization debt discount
and finance cost 4,618 2,097 12,221 8,465
Other non-cash items 355 414 296 323
Net changes in working capital (13,610) (8,572) (24,402) (6,734)
Net cash provided by
operating activities (GAAP) 35,301 8,818 115,570 107,039
Reconciliation of Discretionary
Cash Flow to Net Cash Provided
by Operating Activities:
Discretionary cash flow 48,911 17,390 139,972 113,773
Net changes in working capital (13,610) (8,572) (24,402) (6,734)
Net cash provided by
operating activities (GAAP) 35,301 8,818 115,570 107,039
Selected Operating Data:
Three Months Ended Year Ended
December 31, December 31,
------------- ------------
2009 2008 2009 2008
---- ---- ---- ----
Production - Continuing Operations:
Natural gas (MMcf) 7,737 6,212 28,891 23,174
Oil and condensate (MBbls) 30 44 151 167
Total (Mmcfe) 7,919 6,476 29,796 24,176
Average sales price per unit:
Natural gas (per Mcf) $3.92 $6.68 $3.55 $8.59
Oil (per Bbl) 72.59 56.30 53.65 97.70
Natural gas and oil (per Mcfe) 4.11 6.79 3.72 8.91
Expenses per Mcfe:
Lease operating expense $0.86 $1.39 $1.01 $1.32
Production and other taxes 0.06 0.28 0.14 0.31
Transportation 0.25 0.33 0.32 0.36
DD&A 6.07 4.11 5.38 4.43
Exploration 0.31 0.40 0.31 0.35
Impairment expense 23.41 4.25 7.01 1.18
General and administrative 0.93 1.03 0.94 1.00
SOURCE Goodrich Petroleum Corporation
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