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CRZO > SEC Filings for CRZO > Form 10-Q on 8-Nov-2012All Recent SEC Filings

Show all filings for CARRIZO OIL & GAS INC

Form 10-Q for CARRIZO OIL & GAS INC


8-Nov-2012

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following is management's discussion and analysis of the significant factors that affected the Company's financial position and results of operations during the periods included in the accompanying unaudited consolidated financial statements. You should read this in conjunction with the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011, and the unaudited consolidated financial statements included in this quarterly report.

General Overview
Our third quarter 2012 included oil and gas revenues of $96.2 million and production of 2,354 Mboe. The key drivers to our results for the three months ended September 30, 2012 included the following:
Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended September 30, 2012, we drilled
(a) 16 gross wells (12.3 net) in the Eagle Ford Shale, (b) 6 gross wells (3.4 net) in the Niobrara Formation and (c) 3 gross wells (0.8 net) in the Marcellus Shale. Production. Our third quarter 2012 production of 2,354 Mboe increased 26% from the third quarter 2011 production of 1,875 Mboe. The increase in production from the third quarter of 2011 to the third quarter of 2012 was primarily due to increased production from new wells primarily in the Eagle Ford Shale and the Niobrara Formation, partially offset by normal production decline and the sale of a significant portion of our remaining Barnett Shale properties to Atlas Resource Partners, L.P. ("Atlas") in April 2012. Commodity prices. Our average realized oil price during the third quarter of 2012 was $96.66 per barrel, or 8% higher than the price during the third quarter of 2011. Our average realized gas price during the third quarter of 2012 was $1.92 per Mcf, or 37% lower than the price during the third quarter of 2011. Sale of Gulf Coast Properties. During the third quarter of 2012, we completed the divestiture of substantially all of our legacy producing properties along the onshore Gulf of Mexico located primarily in Texas and Louisiana for an agreed upon price of $19.3 million, subject to final post-closing adjustments. Net proceeds received from the sale were approximately $14.3 million as of September 30, 2012 and we expect to receive up to an additional $3.5 million in the fourth quarter of 2012. Purchase price adjustments primarily relate to proceeds received by the Company for sales of hydrocarbons from such properties between the effective date of July 1, 2012 and the closing date of September 27, 2012. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.

Outlook
While the market for natural gas remains challenging due to low spot and future prices, we are insulated from a portion of their effect by our hedging of 4,876,000 MMbtus of natural gas (approximately 66% of expected fourth quarter 2012 production) at September 30, 2012 for the remainder of 2012 and 10,950,000 MMbtus of natural gas (approximately 38% of expected 2013 production) hedged for 2013. The Atlas sale and our rapidly growing oil production, further serve to reduce our exposure to the natural gas market. The current market and outlook for crude oil is much more attractive and we are aggressively locking in these prices by increasing our hedge positions as our oil production grows. At September 30, 2012, we had hedges in place for 671,600 bbls of oil (approximately 84% of expected fourth quarter 2012 production) for the remainder of 2012 and 2,591,500 bbls of oil (approximately 86% of expected 2013 production) hedged for 2013. Production growth and commodity prices that permit us to drill, develop and produce at a profit are key to our future success. Based upon the success of our drilling results since late 2010, we continue to focus on developing our oil rich resource plays in the Eagle Ford Shale and the Niobrara Formation and have reallocated capital from development of Barnett Shale and Marcellus Shale gas to Eagle Ford and Niobrara oil.
Eagle Ford Shale. During the third quarter of 2012, we brought on production 13 gross (10.1 net) wells. As of September 30, 2012, we had 58 wells producing in the Eagle Ford Shale and were operating three rigs on our Eagle Ford properties. Niobrara Formation. During the third quarter of 2012, we brought on production 4 gross (2.4 net) wells. As of September 30, 2012, we had 24 wells producing in the Niobrara Formation and were operating one rig on our Niobrara properties. In October 2012, we entered into a joint venture agreement with subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd., both international energy companies based in Delhi, India. Under the terms of the joint venture, we sold an undivided 30% non-operated interest in substantially all of our assets and operations prospective for Niobrara Formation oil development located primarily in Weld and Adams Counties, Colorado for total consideration of approximately $82.5 million, comprised of $41.25 million in cash and the assumption of an additional $41.25 million of our future drilling and development costs, subject to final post-closing adjustments.. The joint venture agreements are effective October 1, 2012 and contemplate an area of mutual interest agreement

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among the parties. The properties sold to OIL and IOCL accounted for approximately 555 Boe/d of production including 414 Bbls/d of oil production as of September 27, 2012.
Later in October 2012, the Company also agreed to sell a portion of its remaining interest in the same oil and gas properties sold to OIL and IOCL in the transaction described above to Haimo Oil & Gas LLC (Haimo), a subsidiary of Lanzhou Haimo Technologies Co. Ltd., a company formed under the laws of the People's Republic of China, for a cash payment of $27.5 million. The purchase and participation agreement for this transaction provides for an ongoing joint venture between the Company, OIL and IOCL, and Haimo, with respect to the interests purchased. Following the closing of the Haimo transaction late in the fourth quarter of 2012, the Company, OIL and IOCL, collectively, and Haimo will own 60%, 30% and 10% of the joint venture acreage, respectively. This transaction will also have an effective date of October 1, 2012 and is subject to adjustment, pending completion of land and title matters, and governmental approval.
Marcellus Shale. As a result of the material decline in natural gas prices, we and our joint venture partners are carefully reviewing our drilling program and have significantly reduced our planned spending in the Marcellus Shale during 2012. We will continue to monitor prices and, consistent with our existing contractual commitments, may decrease our activity level and capital expenditures further, or may increase such activity, if natural gas prices so warrant. As of September 30, 2012, we had 14 gross (4.5 net) wells completed and waiting on pipeline connection and 17 gross (4.3 net) wells drilled and waiting on completion. As of September 30, 2012, we had 21 wells producing in the Marcellus Shale. As of October 31, 2012 we were operating one rig on our Marcellus properties.
U.K. North Sea. In the third quarter of 2012, all producer and injector wells had been completed. As of October 31, 2012, the FPSO Teekay Spirit has left the shipyard and arrived in the field. Offshore installation work has commenced and is ongoing. Weather has delayed the project and first oil is currently expected in the first quarter of 2013.
Utica Shale Joint Venture. In October 2012, we sold substantially all of our interests in oil and gas properties in the northern portion of the Utica Shale play to an unrelated third party and received net cash proceeds of $42.7 million, subject to final post-closing adjustments. Simultaneous with the closing of the Utica Shale transaction discussed above, one of the our existing joint venture partners in the Utica Shale, ACP II, an affiliate of Avista Capital Holdings, LP, sold substantially all of its interests in the same oil and gas properties. In connection with the sale transactions described above, the Company elected to exercise its option to increase its participating interest in the same oil and gas properties on a "net proceeds basis" so that the Company received net proceeds with respect to 50% of the properties rather than the 10% for which it held record title. Other assets included in the sale are an existing drilling pad and approved well drilling permits associated with the properties. The properties sold are located in Mercer and Crawford Counties in Pennsylvania and Trumbull County in Ohio. The proceeds from such sale will be recognized as a reduction of proved oil and gas properties. On October 24, 2012, we and Avista amended our Utica Shale joint venture agreement to provide that the expiration date of our remaining option to increase our participating interest in the Utica joint venture properties to January 15, 2013. We and Avista also agreed that if the option is exercised prior to such date, our participating interest in subsequently acquired properties within an area of mutual interest will continue to be 10%, and Avista's participating interest will be 90%, and we will be granted an additional option to increase our 10% ownership in such subsequently acquired properties to 50% at 8.625% above acreage cost and associated improvements after the exercise date. This additional option would expire May 31, 2013.

Results of Operations
Three Months Ended September 30, 2012, Compared to the Three Months Ended September 30, 2011
Revenues from oil and gas production for the three months ended September 30, 2012 increased 86% to $96.2 million from $51.7 million for the same period in 2011 primarily due to increased oil production and higher oil prices partially offset by lower gas production and prices. Production volumes for the three months ended September 30, 2012 and 2011 were 2,354 Mboe and 1,875 Mboe, respectively. The increase in production from the third quarter of 2011 to the third quarter of 2012 was primarily due to increased production from new wells, partially offset by normal production decline and the sale of Barnett Shale production to Atlas. Average realized oil prices increased 8% to $96.66 per barrel from $89.17 per barrel in the same period in 2011Average realized gas prices decreased 37% to $1.92 per Mcf in the third quarter of 2012 from $3.06 per Mcf in the same period in 2011.

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The following table summarizes production volumes, average realized sales prices and oil and gas revenues for the three months ended September 30, 2012 and 2011:

                                              Three Months Ended                    2012 Period
                                                September 30,                 Compared to 2011 Period
                                                                             Increase          % Increase
                                             2012             2011          (Decrease)         (Decrease)
Production volumes-
Oil and condensate (MBbls)                     796               223               573             257  %
NGLs (Mboe)                                     78                36                42             117  %
Natural gas (MMcf)                           8,877             9,695              (818 )            (8 )%
Total Natural gas and NGLs (MMcfe)           9,345             9,911              (566 )            (6 )%
Total barrels equivalent (Mboe)              2,354             1,875               479              26  %

Production Volumes per day-
Oil and condensate per day (Bbls/d)          8,652             2,424             6,228             257  %
NGLs per day (Boe/d)                           848               391               457             117  %
Natural gas (Mcfe/d)                        96,489           105,380            (8,891 )            (8 )%
Total Natural gas and NGLs per day
(Mcfe/d)                                   101,576           107,728            (6,152 )            (6 )%
Total barrels equivalent per day
(Boe/d)                                     25,587            20,380             5,207              26  %

Average sales prices-
Oil and condensate ($ per Bbl)         $     96.66        $    89.17     $        7.49               8  %
NGLs ($ per Boe)                             28.53             57.06            (28.53 )           (50 )%
Natural gas ($ per Mcf)                       1.92              3.06             (1.14 )           (37 )%
Total average realized sales price
(per Boe)                              $     40.87        $    27.56     $       13.31              48  %

Oil and gas revenues (In thousands)
Oil and condensate                     $    76,945        $   19,924     $      57,021             286  %
NGLs                                         2,225             2,057               168               8  %
Natural gas                                 17,027            29,687           (12,660 )           (43 )%
Total oil and gas revenues             $    96,197        $   51,668     $      44,529              86  %

Lease operating expenses were $7.1 million ($3.04 per Boe) for the three months ended September 30, 2012 as compared to lease operating expenses of $7.3 million ($3.89 per Boe) for the third quarter of 2011. The $0.2 million decrease in lease operating expenses is primarily due to the Atlas sale partially offset by increased production. The decrease in operating cost per Boe is primarily due to the Atlas sale (which were higher operating cost per Boe properties compared to our remaining Barnett Shale properties) partially offset by the higher operating cost per Boe associated with oil production.
Production taxes were $3.4 million (or 3.6% of oil and gas revenues) for the three months ended September 30, 2012 as compared to $1.3 million (or 2.6% of oil and gas revenues) for the three months ended September 30, 2011. The increase in production taxes is due primarily to increased oil production. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production.
Ad valorem taxes increased to $2.3 million ($0.99 per Boe) for the three months ended September 30, 2012 from $1.0 million ($0.55 per Boe) for the same period in 2011. The increase in ad valorem taxes is due primarily to new oil wells drilled in 2011. The increase in ad valorem taxes per Boe is due primarily to new oil wells drilled in 2011, which have higher property tax valuations as compared to our natural gas wells.
Depreciation, depletion and amortization ("DD&A") expense for the third quarter of 2012 increased $26.2 million to $46.5 million ($19.76 per Boe) from the DD&A expense for the third quarter of 2011 of $20.3 million ($10.84 per Boe). The $26.2 million increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to the impact of the significant decrease in natural gas reserves in the Barnett Shale as result

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of the Atlas sale as well as the significant increase in crude oil reserves in the Eagle Ford that were added in 2011 and 2012, which have a higher finding cost per Boe than our natural gas reserves.
General and administrative expense increased to $12.4 million for the three months ended September 30, 2012 from $4.7 million for the corresponding period in 2011. The increase was primarily due to increased stock-based compensation expense which was primarily driven by an increase in the fair value of cash-settled stock appreciation rights as well as an increase in the number of cash-settled stock appreciation rights outstanding during the third quarter of 2012 as compared to the same period of 2011, partially offset by decreased compensation costs attributable to the 2011 annual bonuses to senior management, which were paid during the second quarter of 2012, while the 2010 annual bonuses to senior management were paid during the third quarter of 2011.
The net loss on derivative instruments of $14.9 million in the third quarter of 2012 consisted of a $24.2 million unrealized loss on derivatives and a $9.3 million realized gain on derivatives. The net gain on derivative instruments of $25.6 million in the third quarter of 2011 was comprised of a $17.0 million unrealized gain on derivatives and an $8.6 million realized gain on derivatives. Interest expense and capitalized interest for the three months ended September 30, 2012 were $18.9 million and $6.8 million, respectively, as compared to $13.4 million and $6.0 million, respectively, for the same period in 2011. The increase in interest expense was primarily due to interest on the $200 million aggregate principal amount of our 8.625% Senior Notes that were issued in the fourth quarter of 2011. The increase in capitalized interest was primarily related the U.K. Huntington field development project.
The estimated annual effective income tax rates for 2012 and 2011 were 38.1% and 36.4%, respectively. The benefit recognized during the third quarter of 2012 was due to the pre-tax loss incurred and the foreign tax benefit of our U.K. Huntington field development project. The actual effective income tax rate for the third quarter of 2011 was 38.6% which was higher than the estimated annual effective income tax rate due to revisions of prior period estimates of state income taxes.

Nine Months Ended September 30, 2012, Compared to the Nine Months Ended September 30, 2011

Revenues from oil and gas production for the nine months ended September 30, 2012 increased 78% to $260.7 million from $146.4 million for the same period in 2011 primarily due to increased production and higher oil prices, partially offset by lower gas prices. Production volumes for the nine months ended September 30, 2012 and 2011 were 7,056 Mboe and 5,520 Mboe, respectively. The increase in production for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 was primarily due to increased production from new wells, partially offset by normal production decline and the sales of Barnett Shale production to KKR Natural Resources ("KKR") and Atlas. Average realized oil prices increased 10% to $100.93 per barrel from $91.76 per barrel in the same period in 2011. Average realized gas prices decreased 46% to $1.70 per Mcf for the first nine months of 2012 from $3.12 per Mcf in the same period in 2011.

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The following table summarizes production volumes, average realized sales prices and oil and gas revenues for the nine months ended September 30, 2012 and 2011:

                                               Nine Months Ended                   2012 Period
                                                September 30,                Compared to 2011 Period
                                                                            Increase          % Increase
                                             2012            2011          (Decrease)         (Decrease)
Production volumes-
Oil and condensate (MBbls)                     2,030            515              1,515            294  %
NGLs (Mboe)                                      191            175                 16              9  %
Natural gas (MMcf)                            29,011         28,977                 34              -  %
Total Natural gas and NGLs (MMcfe)            30,157         30,027                130              -  %
Total barrels equivalent (Mboe)                7,056          5,520              1,536             28  %

Production volumes per day-
Oil and condensate per day (Bbls/d)            7,409          1,886              5,523            293  %
NGLs per day (Boe/d)                             697            641                 56              9  %
Natural gas and NGLs per day (Mcfe/d)        105,880        106,143               (263 )            -  %
Total Natural gas and NGLs (Mcfe/d)          110,062        109,989                 73              -  %
Total barrels equivalent (Boe/d)              25,752         20,220              5,532             27  %

Average sales prices-
Oil and condensate ($ per Bbl)           $    100.93     $    91.76     $         9.17             10  %
NGLs ($ per Boe)                               34.88          49.08             (14.20 )          (29 )%
Natural gas ($ per Mcf)                         1.70           3.12              (1.42 )          (46 )%
Total average realized sales prices
(per Boe)                                $     36.95     $    26.52     $        10.43             39  %

Oil and gas revenues (In thousands)
Oil and condensate                       $   204,890     $   47,284     $      157,606            333  %
NGLs                                           6,662          8,576             (1,914 )          (22 )%
Natural gas                                   49,178         90,538            (41,360 )          (46 )%
Total oil and gas revenues               $   260,730     $  146,398     $      114,332             78  %

Lease operating expenses were $22.6 million ($3.20 per Boe) for the nine months ended September 30, 2012 as compared to lease operating expenses of $21.4 million ($3.87 per Boe) for the nine months ended September 30, 2011. Lease operating expenses increased $1.2 million primarily due to increased production from new wells partially offset by the Atlas and KKR sales. The decrease in operating cost per Boe is due to the Atlas and KKR sales (which were higher operating cost per Boe properties as compared to our remaining Barnett Shale properties) partially offset by the higher operating cost per Boe associated with oil production.

Production taxes increased to $9.7 million (3.7% of oil and gas revenues) for the nine months ended September 30, 2012 from $3.7 million (2.5% of oil and gas revenues) for the nine months ended September 30, 2011. The increase in production taxes is due primarily to increased oil production. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher effective production tax rate as compared to our natural gas production.

Ad valorem taxes increased to $8.2 million ($1.17 per Boe) for the nine months ended September 30, 2012 from $2.7 million ($0.49 per Boe) for the same period in 2011. The increase in ad valorem taxes is due primarily to new oil wells drilled in 2011 and the Commonwealth of Pennsylvania's February 2012 enactment of an "impact fee" on the drilling of unconventional natural gas wells. Because of the retroactive nature of the impact fee, approximately $1.2 million of ad valorem taxes recognized during the first nine months of 2012 is attributable to wells drilled prior to 2012. The increase in ad valorem taxes per unit is due primarily to new oil wells drilled in 2011, which have higher property tax valuations as compared to our natural gas wells, as well as the recognition of the impact fee in 2012.

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DD&A expense for the nine months ended September 30, 2012 increased $63.9 million to $121.5 million ($17.21 per Boe) from $57.6 million ($10.43 per Boe) for the same period in 2011. The $63.9 million increase in DD&A is attributable to both the increase in production and an increase in the DD&A rate per Boe. The increase in the DD&A rate per Boe is largely due to the impact of the significant decrease in natural gas reserves in the Barnett Shale as a result of the Atlas and KKR sales as well as the increase in crude oil reserves in the Eagle Ford that were added in 2011 and 2012, which have a higher finding cost per Boe than our natural gas reserves.

General and administrative expense increased to $37.0 million for the nine months ended September 30, 2012 from $28.1 million for the corresponding period in 2011. The increase was primarily due to increased compensation costs related to an increase in personnel in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 and higher stock-based compensation expense due to a higher number of restricted stock awards outstanding at higher prices during 2012 as compared to the same period of 2011.

The net gain on derivative instruments of $26.4 million in the first nine months of 2012 consisted of a $3.9 million unrealized loss on derivatives and a $30.3 million realized gain on derivatives. The net gain on derivative instruments of $37.5 million in the first nine months of 2011 was comprised of a $23.5 million realized gain on derivatives and a $14.0 million unrealized gain on derivatives.

Interest expense and capitalized interest for the nine months ended September 30, 2012 were $54.0 million and $20.6 million, respectively, as compared to $38.0 million and $16.9 million, respectively, for the same period in 2011. The increase in interest expense was primarily due to interest on the $200 million aggregate principal amount of our 8.625% Senior Notes that were issued in the fourth quarter of 2011. The increase in capitalized interest was primarily related the U.K. Huntington field development project.

The estimated annual effective income tax rates for 2012 and 2011 were 38.1% and 36.4%, respectively. The actual effective income tax rate for the nine months ended September 30, 2012 was 31.4%, which was lower than the estimated annual effective income tax rates due to the foreign tax benefit of our U.K. Huntington field development project. The actual effective income tax rate for the nine months ended September 30, 2011 was 37.7%, which was higher than the estimated annual effective income tax rate due to revisions of prior period estimates of state income taxes.

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Liquidity and Capital Resources
2012 Capital Expenditure Plan and Funding Strategy. In August 2012, our Board approved a revised U.S. capital expenditure plan of $600.0 million which includes approximately $378.0 million for the Eagle Ford Shale, $61.0 million for the Niobrara Formation, $54.0 million for the Marcellus Shale, $29.0 million for the Barnett Shale, and $78.0 million for land, seismic and other activities, inclusive of carries. Planned capital expenditures for the Huntington Field development project in the U.K. North Sea are $35.0 million, all of which is expected to be funded by our Huntington Facility. We intend to finance the remainder of our 2012 capital expenditure plan primarily from the sources described below under " - Sources and Uses of Cash." Our capital program could vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. We are currently updating our U.S. capital expenditure plan to reflect the impact of the recently announced transactions on fourth quarter activity. Below is a summary of year to date U.S. capital expenditures through September 30, 2012.

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