From Earlier: Goodrich Petroleum Offers 2013 CapEx Budget, Operational Update
Goodrich Petroleum Corporation (NYSE: GDP) today announced its preliminary capital expenditure budget for 2013, along with production and cash flow guidance for the year.
2013 CAPITAL EXPENDITURE BUDGET
The Company today announced a preliminary capital expenditure budget for 2013 of $175 – 200 million, which includes $160 – 185 million in drilling and completion expenditures and $15 million allocated to leasehold and infrastructure expenses. The Company anticipates drilling and/or completion operations on 44 – 48 gross (24 – 26 net) wells for the year, with approximately 85% of the anticipated drilling and completion capital expenditures allocated to oil directed activity.
The Company's 2013 capital expenditure budget is designed to allow for flexibility to allocate capital within the range of the total capital expenditures in either the Eagle Ford Shale or the Tuscaloosa Marine Shale ("TMS"). Oil directed activity will be concentrated in the Eagle Ford Shale trend with $115 – 137 million allocated to 24 – 28 gross (16 – 19 net) wells, and the TMS trend, with $25 – 50 million allocated to 6 – 10 gross (2 – 4 net) wells. The gas directed capital expenditure budget is $22 million, which is allocated to the completion of 13 gross (6 net) Haynesville Shale wells that have been previously drilled.
Capital expenditures for 2012 are expected to be approximately $250 million, which is consistent with the Company's previously disclosed budget.
2013 PRODUCTION GUIDANCE
The Company estimates oil volumes to grow by 40 – 60% in 2013 versus 2012, natural gas volumes to grow by 10 – 15% from the previously issued guidance for the fourth quarter of 2012 to the fourth quarter of 2013, yet be down year over year by approximately 10%, and overall production on a Mcfe basis is expected to be relatively flat year over year. Oil volumes are estimated to comprise approximately 30 – 35% of total production and 65 – 70% of revenue for the year.
The Company recently added crude oil swaps for 2013 on 2,000 barrels of oil per day and currently has 3,500 barrels of oil per day, or approximately 70% of 2013 estimated volumes hedged at NYMEX West Texas Intermediate ("WTI") price of approximately $94.50 per barrel. Current oil price differential to WTI is approximately + $12.00 per barrel for the Company's Eagle Ford Shale production and +$18.00 per barrel in the TMS. The Company is currently unhedged on natural gas.
2013 ESTIMATED CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") is expected to be $165 – $185 million for the year factoring in the Company's production forecasts, hedges and based on NYMEX pricing of $90.00 per barrel of oil (WTI) and $3.50 per Mcf of natural gas. Commodity price differentials were estimated at a $10.00 per barrel premium to WTI on oil and Henry Hub pricing less $0.24 per Mcf on natural gas.
Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital is expected to be $125 – $140 million under the same production, hedging and commodity price assumptions.
Adjusted EBITDAX and DCF are non-GAAP financial measures. Please see "Other Information" below.
The Company exited 2012 with $95 million drawn on its senior credit facility with a current borrowing base of $210 million, providing approximately $115 million of liquidity at year-end. The Company expects its borrowing base will increase incrementally in 2013 due to continued oil volume production and reserve growth and assuming no change in the bank group's commodity price assumptions, with its first redetermination due in March. Based on estimated capital expenditures and cash flow for 2013, the Company expects to finance approximately 70% of its capital expenditure budget with cash flow from operations and the balance with borrowings under its senior credit facility. The Company may seek additional liquidity through the joint venture of its TMS acreage or other monetizations, and if completed, will consider acceleration of its Eagle Ford and/or TMS drilling program in the second half of the year.
Eagle Ford Shale
Average drilling days per well deceased by 40 percent sequentially in the quarter to 11 days for an average 6,000 foot lateral. Gross well costs for 2013 are projected to average $7.0 – $7.5 million for an average 6,000 foot lateral, which incorporates the lower well costs due to the faster drilling and cycle times achieved in the second half of 2012, as well as the reduced pressure pumping agreements in place for 2013. The Company currently plans to spud its initial Pearsall Shale test well in the first quarter.
Tuscaloosa Marine Shale ("TMS")
The Company was unable to repair the parted casing connection in the Denkmann 33H-1 (75% WI) and is currently working on plans to sidetrack the well at a later date. The Company has drilled its Crosby 12H-1 (50% WI) and is scheduled to commence fracking operations in January. The Crosby 12H-1 is an approximate 7,000 foot lateral with 23 planned frac stages. The Company has participated in the drilling of two non-operated wells, the Ash 31H-1 (12% WI) and Ash 31H-2 (12% WI), which are also expected to be fracked during January. The Ash 31H-1 is a 6,500 foot lateral and the Ash 31H-2 is currently drilling with a planned 7,000 foot lateral. Current plans for 2013 include participating as a non-operator in 4 – 6 gross (1.0 – 1.25 net) wells and drilling 2 – 4 gross (1.0 – 2.75 net) operated wells, with the potential to accelerate in the second half of the year.
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