information on our 2013 capital expenditure plan, please see "Liquidity and Capital Resources-2013 Capital Expenditure Plan and Funding Strategy." Results of Operations
Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011 Revenues from oil and gas production for 2012 increased 82% to $368.2 million compared to $202.2 million in 2011. Production volumes in 2012 were 9.4 MMBoe, an increase of 26%, compared to production of 7.5 MMBoe in 2011. The increase in production was primarily due to increased production from new wells, partially offset by normal production decline, and the Atlas and KKR sales. See "Item 1. Business-Natural Gas Plays-Barnett Shale" for additional information. Average oil prices increased 6% to $99.97 per Bbl in 2012 from $94.14 per Bbl in 2011. Average natural gas prices decreased 36% to $1.90 per Mcf in 2012 from $2.98 per Mcf in 2011. Average NGL prices decreased 31% to $34.86 per Bbl in 2012 from $50.30 per Bbl in 2011.
The following table summarizes production volumes, production volumes per day, average realized prices and oil and gas revenues for the years ended December 31, 2012 and 2011:

                                                                                2012 Period
                                                                          Compared to 2011 Period
                                             December 31,               Increase           % Increase
                                          2012           2011          (Decrease)          (Decrease)
Production volumes -
Oil and condensate (MBbls)                 2,862            802              2,060             257  %
NGLs (MBoe)                                  305            210                 95              45  %
Natural gas (MMcf)                        37,612         38,991             (1,379 )            (4 )%
Total Natural gas and NGLs (MMcfe)        39,442         40,251               (809 )            (2 )%
Total barrels of oil equivalent
(MBoe)                                     9,436          7,511              1,925              26  %

Production volumes per day -
Oil and condensate per day (Bbls/d)        7,820          2,197              5,623             256  %
NGLs per day (Boe/d)                         833            575                258              45  %
Natural gas per day (Mcf/d)              102,765        106,825             (4,060 )            (4 )%
Total Natural gas and NGLs per day
(Mcfe/d)                                 107,765        110,277             (2,512 )            (2 )%
Total barrels of oil equivalent per
day (Boe/d)                               25,781         20,578              5,203              25  %

Average realized prices -
Oil and condensate ($ per Bbl)        $    99.97     $    94.14     $         5.83               6  %
NGLs ($ per Boe)                           34.86          50.30             (15.44 )           (31 )%
Natural gas ($ per Mcf)                     1.90           2.98              (1.08 )           (36 )%
Total average realized price ($ per
Boe)                                  $    39.02     $    26.92     $        12.10              45  %

Oil and gas revenues (In thousands)
-
Oil and condensate                    $  286,119     $   75,502     $      210,617             279  %
NGLs                                      10,631         10,562                 69               1  %
Natural gas                               71,430        116,103            (44,673 )           (38 )%
Total oil and gas revenues            $  368,180     $  202,167     $      166,013              82  %

Lease operating expenses for 2012 increased to $31.5 million ($3.34 per Boe) from $28.3 million ($3.77 per Boe) in 2011. Lease operating expenses increased $3.2 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 $13.5 million (or 3.7% of oil and gas revenues) in 2012 from $5.7 million (or 2.8% of oil and gas revenues) in 2011 as a result of increased oil production in 2012. 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 $9.8 million ($1.04 per Boe) in 2012 from $3.6 million ($0.48 per Boe) 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 $1.0 million of ad valorem taxes recognized during 2012 is attributable to wells drilled prior to 2012. 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, as well as the recognition of the impact fee in 2012.
Depreciation, depletion and amortization ("DD&A") expense for 2012 increased to $165.6 million ($17.55 per Boe) from $84.6 million ($11.26 per Boe) in 2011. The 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 Shale that have been added during 2011 and 2012, which have a higher finding cost per Boe than our natural gas reserves.
General and administration ("G&A") expense for 2012 increased to $48.7 million from $41.5 million in 2011. The increase was primarily due to increased compensation costs related to an increase in personnel in 2012 as compared to 2011. This was partially offset by decreased stock-based compensation expense due to a decrease in the fair value of stock appreciation rights resulting from a decrease in stock price during 2012 as compared to an increase in stock price during 2011, partially offset by higher stock-based compensation expense due to a higher number of restricted units outstanding during 2012 as compared to 2011. The net gain on derivative instruments of $31.4 million in 2012 consisted of a $9.7 million unrealized loss on derivatives and a $41.1 million realized gain on derivatives. The net gain on derivative instruments of $48.4 million in 2011 consisted of a $13.0 million unrealized gain on derivatives and a $35.4 million realized gain on derivatives. The net decrease was due to the change in fair value of our open derivative positions during those periods.
Interest expense and capitalized interest in 2012 were $73.0 million and $24.8 million, respectively, as compared to $51.0 million and $23.4 million in 2011, respectively. The net increase was primarily attributable to interest on the $200.0 million aggregate principal amount of our 8.625% Senior Notes issued in the fourth quarter of 2011 as well as interest on the $300.0 million aggregate principal amount of our 7.50% Senior Notes issued in the third quarter of 2012. Our effective income tax rate was 37.7% for 2012 and 44% for 2011. The decrease in the effective income tax rate is primarily due to the adjustments to prior state income tax provisions recorded during fourth quarter of 2011 and the income tax benefit of a capital loss associated with a prior investment. Net income from discontinued operations, net of income taxes for 2012 increased to $4.3 million from $4.1 million in 2011. The increase is primarily related to income tax benefits associated with Carrizo UK.
Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010 Revenues from oil and gas production for 2011 increased 46% to $202.2 million from $138.1 million in 2010. Production volumes for oil and gas in 2011 increased 22% to 7.5 MMBoe from 6.1 MMBoe in 2010. The increase in production for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily due to increased production from new wells, partially offset by normal production decline, the Atlas sale, and the KKR sale. Average oil prices increased 20% to $94.14 per Bbl from $78.74 per Bbl in 2010. Average natural gas prices decreased 11% to $2.98 per Mcf in 2011 from $3.33 per Mcf in 2010. Average NGL prices increased 31% to $50.30 per Boe in 2011 from $38.51 per Boe in 2010.

The following table summarizes production volumes, production volumes per day, average realized prices and oil and gas revenues for the years ended December 31, 2011 and 2010:

                                                                               2011 Period
                                                                         Compared to 2010 Period
                                             December 31,               Increase          % Increase
                                          2011           2010          (Decrease)         (Decrease)
Production volumes -
Oil and condensate (MBbls)                   802            176               626             356  %
NGLs (MBoe)                                  210            277               (67 )           (24 )%
Natural gas (MMcf)                        38,991         34,092             4,899              14  %
Total Natural gas and NGLs (MMcfe)        40,251         35,754             4,497              13  %
Total barrels of oil equivalent
(MBoe)                                     7,511          6,135             1,376              22  %

Production volumes per day -
Oil and condensate per day (Bbls/d)        2,197            482             1,715             356  %
NGLs per day (Boe/d)                         575            759              (184 )           (24 )%
Natural gas per day (Mcf/d)              106,825         93,403            13,422              14  %
Total Natural gas and NGLs per day
(Mcfe/d)                                 110,277         97,956            12,321              13  %
Total barrels of oil equivalent per
day (MBoe)                                20,578         16,808             3,770              22  %

Average realized prices -
Oil and condensate ($ per Bbl)        $    94.14     $    78.74     $       15.40              20  %
NGLs ($ per Boe)                           50.30          38.51             11.79              31  %
Natural gas ($ per Mcf)                     2.98           3.33             (0.35 )           (11 )%
Total average realized price ($ per
Boe)                                  $    26.92     $    22.51     $        4.41              20  %

Oil and gas revenues (In thousands)
-
Oil and condensate                    $   75,502     $   13,859     $      61,643             445  %
NGLs                                      10,562         10,667              (105 )            (1 )%
Natural gas                              116,103        113,597             2,506               2  %
Total oil and gas revenues            $  202,167     $  138,123     $      64,044              46  %

Lease operating expenses for 2011 increased to $28.3 million ($3.77 per Boe) from $23.7 million ($3.86 per Boe) in 2010. Lease operating expenses increased due to increased production. We continue to experience a decrease in the operating cost per Boe of our Barnett Shale production as a result of the Atlas and KKR sales, which was partially offset by increased operating cost per Boe associated with oil production.
Production taxes increased to $5.7 million (2.8% of oil and gas revenues) in 2011 from $3.6 million (2.6% of oil and gas revenues) in 2010 as a result of higher oil prices and increased production in 2011. The increase in production taxes as a percentage of oil and gas revenues is due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.
Ad valorem taxes decreased to $3.6 million ($0.48 per Boe) in 2011 from $3.7 million ($0.60 per Boe) in 2010 due to the sale of substantially all of our non-core area Barnett Shale properties in May 2011, partially offset by new oil and gas wells drilled in 2010.
DD&A expense for 2011 increased to $84.6 million ($11.26 per Boe) from $47.0 million ($7.68 per Boe) in 2010. The increases in DD&A and the related per Boe amounts were primarily due to the increase in crude oil reserves in the Eagle Ford that were added in 2011 which have a higher finding cost per equivalent unit than our natural gas reserves.
In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full-cost ceiling test impairment of $2.7 million ($1.7 million net of income taxes) for the year ended December 31, 2010 with respect to the U.K. cost center.

G&A expense for 2011 increased to $41.5 million from $35.9 million in 2010. The increase was due primarily to (a) increased compensation costs related to an increase in personnel in 2011 as compared to 2010, (b) the expense associated with contributions to University of Texas at Arlington, (c) increased office costs related to relocating our corporate headquarters in the fourth quarter of 2011 partially offset by (d) decreased stock-based compensation expense driven by a significant decrease in the fair value of SARs that we expect to be settled in cash due to a decrease in stock price during the second half of 2011, partially offset by higher stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during 2011. The net gain on derivative instruments of $48.4 million in 2011 consisted of a $13.0 million unrealized gain on derivatives and a $35.4 million realized gain on derivatives. The net gain on derivative instruments of $47.8 million in 2010 consisted of a $14.6 million unrealized gain on derivatives and a $33.2 million realized gain on derivatives.
In January 2011, in connection with our entrance into our current revolving credit facility, we terminated our prior credit facility. As a result, we recognized a non-cash, pre-tax loss on extinguishment of debt of $0.9 million representing the deferred financing costs attributable to the commitments of two banks in the prior credit facility who did not participate in the new revolving credit facility.
In November 2010, we completed a tender offer for $300.0 million aggregate principal amount outstanding of our convertible senior notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the convertible senior notes. We recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the convertible senior notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs. Interest expense and capitalized interest in 2011 were $51.0 million and $23.4 million, respectively, as compared to $43.3 million and $20.7 million in 2010, respectively. The net increase was primarily due to interest on the $400.0 million aggregate principal amount of 8.625% Senior Notes issued in the fourth quarter of 2010 and the $200.0 million aggregate principal amount of 8.625% Senior Notes issued in the fourth quarter of 2011 partially offset by decreased interest attributable to the $300.0 million aggregate principal amount of our convertible senior notes purchased in the tender offer during the fourth quarter of 2010. This increase was partially offset by increased capitalized interest due to higher levels of unproved properties during 2011.
Our effective income tax rate was 44.0% for 2011 and 36.3% for 2010. The increase in the effective income tax rate is primarily due to prior period adjustments to state income tax provisions recorded during the fourth quarter of 2011 and the income tax benefit of a capital loss associated with a prior investment.
Net income (loss) from discontinued operations, net of income taxes for 2011 increased to $4.1 million from a loss of $1.8 million in 2010. The increase is primarily related to income tax benefits recognized in 2011 while in 2010 we had a full-cost ceiling test impairment of $2.7 million. Liquidity and Capital Resources
2013 Capital Expenditure Plan and Funding Strategy. For 2013, our Board has approved a U.S. capital expenditure plan of $624.0 million which includes $500.0 million for drilling and completion (approximately $385.0 million for the Eagle Ford Shale, $70.0 million for the Marcellus Shale, $35.0 million for the Niobrara Formation, and $10.0 million in other areas) and $124.0 million for leasehold and seismic, after giving effect to carried interests. All 2013 capital expenditures for the Huntington Field development project in the U.K. North Sea were funded by our Huntington Facility and additional capital contributions by us, all of which were reimbursed by Iona Energy in connection with the sale and purchase transaction of Carrizo UK, which closed in February 2013. We intend to finance the remainder of our 2013 U.S. 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.
Sources and Uses of Cash. Our primary use of cash is capital expenditures related to our drilling and development programs and, to a lesser extent, our lease and seismic data acquisition programs. For the year ended December 31, 2012, capital expenditures, net of proceeds from asset sales exceeded our net cash provided by operations for continuing operations. During 2012, we funded our capital expenditures with cash provided by operations, payments relating to our joint ventures with Reliance in the Marcellus Shale, Avista in the Utica Shale, GAIL in the Eagle Ford Shale, and the OIL JV Partners in the Niobrara Formation, net proceeds from the sale of assets, including the Atlas, Gulf Coast and Avista Utica divestures, the Haimo joint venture, net proceeds from the offering of our 7.50% Senior Notes, and borrowings under our revolving credit facility and the Huntington Facility. Potential sources of future liquidity include the following:

• Cash on hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oilfield services. We hedge a portion of our forecasted production to mitigate the risk of a decline in oil and gas prices.

• Borrowings under our revolving credit facility. At February 25, 2013, we had no borrowings outstanding and $0.9 million in letters of credit outstanding under the revolving credit facility, which reduce the amounts available under our revolving credit facility. The amount we are able to borrow with respect to the borrowing base of the revolving credit facility, which borrowing base is currently $365.0 million, is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility.

• Asset sales. In order to fund our U.S. capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us. On April 30, 2012, we completed the sale of a significant portion of our Barnett Shale properties to Atlas for net proceeds of approximately $187.4 million. We used substantially all of the net proceeds from this sale to reduce the outstanding borrowings under our revolving credit facility. During the third quarter of 2012, we completed the sale of substantially all of our legacy producing properties along the onshore Gulf of Mexico located primarily in Texas and Louisiana for net proceeds of approximately $17.6 million. In October 2012, we sold substantially all of our interests in oil and gas properties dedicated to the Avista Utica joint venture that were located in the northern portion of the play to a third party for net cash proceeds of approximately $51.7 million, after final post-closing adjustments. The proceeds from all the sales described above were recognized as a reduction of proved oil and gas properties. On February 22, 2013, we sold Carrizo UK, and all of its interest in the Huntington Field discovery, to Iona Energy for net proceeds of approximately $116.5 million, subject to final post-closing adjustments, which represents an agreed upon price of $184.0 million, including the assumption of $55.0 million in debt and net purchase price adjustments.

• Securities offerings. In September 2012, we issued $300.0 million in aggregate principal amount of our 7.50% Senior Notes in an underwritten public offering and received net proceeds of approximately $294.2 million. As situations or conditions arise, we may choose to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.

• Joint ventures. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both, such as our joint ventures with Reliance in the Marcellus Shale in Pennsylvania, with Avista in the Utica Shale and other parts of the Marcellus Shale, with GAIL in the Eagle Ford Shale, and with an affiliate of Sumitomo Corporation in the Barnett Shale. Effective October 1, 2012, we completed the sale of 30% of substantially all of our interest in oil and gas properties in the Niobrara Formation to the OIL JV Partners. We received cash proceeds of approximately $41.25 million, subject to final post closing adjustments, and the OIL JV Partners committed to pay a "development carry" of 50% of certain of our future exploration and development costs up to an aggregate of approximately $41.25 million. We expect the development carry to be fully utilized by early 2014. In December 2012, we completed the sale of a portion of our remaining interest in the same oil and gas properties previously sold to the OIL JV . . .