You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the years ended December 31, 2012, 2011 and 2010 included with this report. Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management's Discussion and Analysis relates solely to our continuing operations located in the United States, and excludes our New Zealand operations discontinued since late 2007. The following information contains forward-looking statements; see "Forward-Looking Statements" on page 39 of this report.

Overview

We are an independent oil and natural gas company formed in 1979 and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from our Texas properties as well as onshore and inland waters of Louisiana. We are one of the largest producers of crude oil in the state of Louisiana, and hold a large acreage position in Texas prospective for Eagle Ford shale and Olmos tight sands development. Oil production accounted for 32% of our 2012 production and 72% of our oil and gas sales, and combined production of both oil and natural gas liquids ("NGLs") constituted 48% of our 2012 production and 84% of our oil and gas sales. This has allowed us to benefit from better margins for oil production, as oil prices are significantly higher on a Boe basis than natural gas prices.

2012 Activities

• Production: Our production volumes increased by 11% in 2012 when compared to volumes in 2011 as NGL volumes increased by 37% and natural gas production volumes increased by 14%, while oil volumes decreased by 2%. The increase in NGL and natural gas production came from our South Texas area. Although the percentage of our total production volumes from crude oil sales has steadily decreased over the last three years, crude oil sales as a percentage of our total oil and gas sales have remained relatively stable.

• Increased Reserves: Our year-end 2012 total proved reserves increased over our year-end 2011 reserves by 20% to a Company record of 192.1 MMboe, while our oil and NGLs as a percentage of total reserves increased to 48% in 2012 from 36% in 2011. This increase was mainly due to large increases in oil and NGL reserves in our South Texas area.

• Pricing: Our weighted average sales price in 2012 decreased 17% when compared to levels in 2011 as natural gas prices declined 35%, NGL prices declined 33% and oil prices declined 1%.

• Cash provided by operating activities: Decreased by $58.5 million or 16%, when compared to 2011, due to the decline in prices received during the period.

• Revenues and Earnings: Our oil and gas sales of $554.2 million declined 8% in 2012 when compared to levels in 2011, due to the decrease in natural gas and NGL prices discussed above. When combined with an increase in total costs and expenses of $56.7 million or 12%, and $14.2 million of income from discontinued operations recognized in 2011, our 2012 net income fell 79% to $20.9 million.

• 2012 debt issuance and available liquidity: In October 2012, we issued $150.0 million of 7.875% senior notes due 2022 at a premium of $7.5 million which equates to an effective yield of 7%. These notes were an add-on to the original $250.0 million of 7.875% senior notes due 2022 that were issued in November 2011. We also extended our credit facility through 2017 and increased the borrowing base and commitment amount to $450.0 million.

• 2012 capital expenditures: Our capital expenditures on a cash flow basis were $757.8 million in 2012 compared to $505.3 million spent in 2011. The increase of $252.4 million was mainly due to additional drilling and completion activity during 2012 in our South Texas core region as we drilled 22 wells in our Artesia Wells Eagle Ford field, 22 wells in our AWP Eagle Ford field, nine wells in our AWP Olmos field and two wells in our Fasken Eagle Ford field, which helped us evaluate Eagle Ford and Olmos acreage positions in those areas. We also drilled 11 wells in our Southeast Louisiana area and five wells in our Central Louisiana/East Texas area, including four non-operated wells. These 2012 expenditures were primarily funded by $314.6 million of cash provided by operating activities, the remaining cash proceeds from our 2011 and 2012 note issuances and our credit facility.

• 2012 operating efficiencies: Our South Texas drilling activities have benefited from optimized well design, improved operational efficiencies, and applied lessons learned from our experience in this area, all of which have resulted in a reduction of drilling days per well. Consequently, we are currently able to drill more wells per rig than previously expected. We have also experienced efficiency gains in our hydraulic fracturing activities which enables us to perform more frac stages per month and lower the overall frac cost per stage.

2013 Strategy and Outlook

• Focus on oil and liquids properties with expanded capital budget: Our inventory of drilling locations allows us to be flexible in scheduling upcoming wells in South Texas to focus on oil and natural gas liquids. Having fulfilled our near-term obligations on most of our acreage prospective for dry natural gas production, we are concentrating on our higher return, liquids rich acreage almost exclusively in 2013. Our 2013 capital expenditures are currently estimated to be $440 to $480 million focused on continued development of oil and liquid rich properties. We plan to fund these expenditures through operating cash flow, availability under our credit facility and potential non-core property dispositions.

• Increase reserves with stable production: For 2013, The Company is targeting production up to 3% over 2012 levels and proved reserves to increase 7% to 12%, over year-end 2012 quantities with a focus on oil and liquid rich opportunities.

• Added midstream capacity and securing transportation capacity: Additional dedicated transportation and processing through a newly constructed third-party pipeline of a midstream provider (handling natural gas production from our AWP Eagle Ford and Olmos areas) became operational at the beginning of October 2011. In our Fasken area, we also secured capacity on a pipeline built in late 2010 by a midstream provider, and in both the AWP and Fasken areas we have secondary transportation outlets available if capacity is restricted on our primary outlets. In June 2012, we entered into an agreement for natural gas gathering and processing for our Artesia Wells Eagle Ford field.

• Capital cost saving measures: We have realized significant capital cost savings in South Texas related to pad drilling, well construction & completion re-design, sourcing & transportation of proppants as well as increased productivity of our dedicated frac spread and crew. Our supply chain program continues to be extremely important and the relationships that we have developed with our service providers are critical to our 2013 program execution.

• Strategic Growth Initiatives: During 2013, the Company intends to devote 5% to 10% of its budget to strategic growth initiatives in Louisiana, including a horizontal well to test the Wilcox formation in our South Bearhead Creek field and a well to test the Niobrara oil formation in La Plata County, Colorado.

• Prospective Joint Venture: In order to leverage the number of wells that can be drilled and our pace of drilling, the Company is currently exploring opportunities to create a joint venture covering portions of the Company's highest value acreage in the Eagle Ford shale.

2013 Known Trends and Uncertainties Affecting our Business

• Flattened production and cash flows: In 2013, we plan to reduce our capital expenditures by approximately 30% to 40% from 2012 levels, in order to live within the limits of reduced cash flow. This is due to a lower commodity price environment, increased water production in Lake Washington leading to reduced anticipated base production during 2013, and the dedication of up to 25% of the year's budget to long-term strategic initiatives, facilities, gathering systems and other infrastructure.

• Recent declines in natural gas and natural gas liquids prices: Several factors such as increases in shale and tight sands production, mild winter weather, and relatively high natural gas storage levels have led to declining natural gas prices in the fourth quarter of 2011 through 2012, with noted improvement in the later half of 2012. Natural gas liquids prices have also declined recently due to many of the same reasons that natural gas prices have declined. Lower natural gas and natural gas liquids prices equate to lower revenue and cash flows and might lead to reductions in our borrowing capacity. As natural gas makes up 52% of our reserves base on a Boe basis, lower natural gas prices in the future could lead to potential reserves reductions which could result in full-cost ceiling write-downs.

• Oilfield services shortages and delays: During periods of increased levels of exploration and production in particular areas, such as we are currently experiencing in the South Texas area, there is increased demand for drilling rigs, equipment, supplies, oilfield services, and trained and experienced personnel. The high demand in these areas has caused shortages and delays, which has raised costs and often delayed field development. In South Texas we have seen improvement in the availability of services as additional equipment has moved into this area.

• Employee retention: As our competitors expand their workforce, we must focus more attention on keeping our highly-skilled employees. There has been and will be constant cost pressure to retain and hire these employees, and these costs do not decline as rapidly and significantly as hydrocarbon prices.

Results of Operations

Revenues - Years Ended December 31, 2012, 2011 and 2010

2012 - Our revenues in 2012 decreased by 7% compared to revenues in 2011, due to lower NGL and natural gas pricing, partially offset by higher natural gas and NGL production. Average oil prices we received were 1% lower than those received during 2011, while natural gas prices were 35% lower, and NGL prices were 33% lower.

2011 - Our revenues in 2011 increased by 37% compared to revenues in 2010, due to higher oil and NGL prices as well as higher NGL and natural gas production. Average oil prices we received were 35% higher than those received during 2010, while natural gas prices were 6% lower, and NGL prices were 23% higher.

Crude oil production was 32%, 37% and 47% of our production volumes in the years ended December 31, 2012, 2011 and 2010, respectively. Crude oil sales were 72%, 69% and 71% of oil and gas sales in the years ended December 31, 2012, 2011 and 2010, respectively. Natural gas production was 52%, 50% and 39% of our production volumes in the years ended December 31, 2012, 2011 and 2010, respectively. Natural gas sales were 16%, 20% and 18% of oil and gas sales in the years ended December 31, 2012, 2011 and 2010, respectively. The remaining production in each year was from NGLs.

The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2012, 2011

and 2010:
                                          Oil and Gas Sales                 Net Oil and Gas Production
         Core Regions                       (In Millions)                         Volumes (MBoe)
                                    2012         2011         2010         2012         2011        2010
Southeast Louisiana              $  212.1     $  287.6     $  246.2         2,227       3,164       3,706
South Texas                         288.2        225.3        120.4         8,555       5,937       3,235
Central Louisiana / East Texas       53.2         86.8         67.4           898       1,375       1,329
Other                                 0.7          2.6          2.6            20          51          60
Total                            $  554.2     $  602.3     $  436.6        11,700      10,527       8,330

In 2012, our $48.1 million, or 8% decrease in oil, NGL, and natural gas sales resulted from:

• Price variances that had a $81.4 million unfavorable impact on sales, with a decrease of $46.5 million attributable to the 35% decrease in natural gas prices, a decrease of $31.8 million due to the 33% decrease in NGL prices and a decrease of $3.1 million due to the 1% decrease in oil prices received,

• Volume variances that had a $33.3 million favorable impact on sales, with a $26.0 million increase attributable to the 0.5 million Bbl increase in NGL production volumes and a $17.0 million increase due to the 4.6 Bcf increase in natural gas production volumes, partially offset by a $9.7 million decrease due to the 0.1 million Bbl decrease in oil production volumes.

In 2011, our $165.7 million, or 38% increase in oil, NGL, and natural gas sales resulted from:

• Price variances that had a $111.5 million favorable impact on sales, of which $106.4 million was attributable to the 35% increase in average oil prices received, $13.2 million was attributable to the 23% increase in NGL prices, reduced by $8.1 million due to the 6% decrease in average natural gas prices received; and

• Volume variances that had a $54.2 million favorable impact on sales, with $47.8 million of increase attributable to the 12.1 Bcf increase in natural gas production volumes, $9.5 million of increase attributable to the 0.2 million Bbl increase in NGL production volumes, reduced by $3.2 million of decreases attributable to the 0.04 million Bbl decrease in oil production volumes.

The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, by quarter, for the years ended December 31, 2012, 2011 and 2010:

                        Production Volume                 Average Price
                 Oil      NGL      Gas    Combined     Oil      NGL      Gas
                (MBbl)   (MBbl)   (Bcf)    (MBoe)     (Bbl)    (Bbl)    (Mcf)
2010
 First Quarter   945      303      4.8     2,045     $78.10    $44.71   $4.74
 Second Quarter  979      279      4.6     2,028     $77.83    $41.92   $3.72
 Third Quarter  1,005     256      4.9     2,072     $76.39    $39.88   $3.87
 Fourth Quarter  976      299      5.5     2,185     $85.52    $42.81   $3.57
  Total         3,905    1,137    19.7     8,330     $79.45    $42.44   $3.96
2011
 First Quarter   985      348      7.9     2,646     $98.61    $48.87   $3.82
 Second Quarter  994      335      7.9     2,641     $112.09   $50.41   $3.93
 Third Quarter   937      247      8.1     2,542     $105.55   $57.76   $3.68
 Fourth Quarter  950      432      7.9     2,699     $111.79   $52.86   $3.39
  Total         3,865    1,362    31.8     10,527    $107.00   $52.13   $3.70
2012
 First Quarter   884      376      9.2     2,799     $111.99   $45.30   $2.18
 Second Quarter  905      430      9.5     2,918     $108.02   $35.25   $2.01
 Third Quarter   870      512      9.0     2,875     $102.73   $31.29   $2.52

For the years ended December 31, 2012, 2011 and 2010, we recorded net gains (losses) of $2.3 million, ($0.9) million and $0.7 million, respectively, related to our derivative activities. This activity is recorded in "Price-risk management and other, net" on the accompanying consolidated statements of operations. Had these amounts been recognized in the oil and gas sales account, our average oil price would have been $106.77, $106.81 and $79.52 for the years ended December 31, 2012, 2011 and 2010, respectively, and our average natural gas price would have been $2.42, $3.70 and $3.98 for the years ended December 31, 2012, 2011 and 2010, respectively.

Costs and Expenses

Our expenses for the year ended December 31, 2012 increased $56.7 million, or 12%, compared to the prior year levels, for the reasons noted below.

Lease Operating Expenses ("LOE"). These expenses increased $10.7 million, or 10%, compared to the level of such expenses for the year ended December 31, 2011, due to higher workover costs in Southeast Louisiana and additional costs in our South Texas region for transportation, salt water disposal and chemical treating. Our lease operating costs per Boe produced, however were $9.87 and $9.95 for the years ended December 31, 2012 and 2011, respectively, due to higher production volumes.

Depreciation, Depletion and Amortization ("DD&A"). These expenses increased $25.9 million, or 12%, from those during the year ended December 31, 2011, due to a higher depletable base (including higher future development costs and higher production volumes), partially offset by higher reserves volumes. Our DD&A rate per Boe of production was $21.13 and $21.02 for the years ended December 31, 2012 and 2011, respectively, resulting from increases in the per unit cost of reserves additions in 2012.

General and Administrative Expenses, Net. These expenses increased $1.4 million, or 3%, compared to the level of such expenses for the year ended December 31, 2011. The increase was primarily due to higher salaries and burdens, partially offset by a lower corporate benefit accrual. For the years ended December 31, 2012 and 2011, our capitalized general and administrative costs totaled $31.1 million and $29.3 million, respectively. Our net general and administrative expenses per Boe produced were $4.00 and $4.31 for the years ended December 31, 2012 and 2011, respectively. The supervision fees recorded as a reduction to general and administrative expenses were $11.3 million and $12.9 million for the years ended December 31, 2012 and 2011, respectively.

Severance and Other Taxes. These expenses decreased $3.6 million, or 7%, from the year ended December 31, 2011. Severance and other taxes, as a percentage of oil and gas sales, were approximately 8.8% and 8.7% for the years ended December 31, 2012 and 2011, respectively.

Interest. Our gross interest cost for the year ended December 31, 2012 was $65.2 million, of which $7.9 million was capitalized. Our gross interest cost for the year ended December 31, 2011 was $43.2 million, of which $7.7 million was capitalized. The increase in interest came from the $250.0 million issuance of our senior notes due 2022 in November 2011 and the additional $150.0 million issuance of our senior notes due 2022 in October 2012.

Income Taxes. Our effective income tax rate was 42.8% and 37.4% for the years ended December 31, 2012 and 2011, respectively. The increase was due to an increase in the ratio of non-deductible expenses to net income, along with an increase in provision for state taxes, partially offset by a favorable adjustment to reverse a liability for an uncertain tax position for which the statutory audit period expired.

Final Recognition of New Zealand Sales Proceeds. In August 2008, we completed the sale of our remaining New Zealand permit for $15.0 million; with three $5.0 million payments spread over a 30 month period. The Company initially deferred the gain on the sale due to legal claims around the transfer of this property. In July 2011, a settlement was reached and all legal claims were dismissed. As a result, in the second quarter of 2011 the Company recognized sale proceeds of $15.0 million, net of $0.6 million in capitalized costs in assets held for sale, relating to our remaining New Zealand permit. As of December 31, 2011, all payments under this sale agreement had been received and thus 100% of the Company's oil and gas operations were in the United States of America.

Liquidity and Capital Resources

Net Cash Provided by Operating Activities. For the year ended December 31, 2012, our net cash provided by operating activities was $314.6 million, representing a 16% decrease compared to $373.1 million generated during 2011. The $58.5 million change was mainly due to the decline in commodity prices received during the year.

Existing Credit Facility. After the regularly scheduled review of our credit facility on October 31, 2012, the Company's borrowing base and commitment amount were increased to $450.0 million from the previous borrowing base and commitment amounts of $375.0 million and $300.0 million, respectively. The maturity of the credit facility was also extended to November 1, 2017 from May 12, 2016. At December 31, 2012, we had $39.4 million in outstanding borrowings under our credit facility. Our available borrowings under our credit facility provide us liquidity. In light of credit market volatility in recent years, which caused many financial institutions to experience liquidity issues, we periodically review the creditworthiness of the banks that fund our credit facility.

2012 Debt Issuance. On October 3, 2012, we issued an additional $150.0 million of 7.875% senior notes due on March 1, 2022. The notes were issued at 105% of par, which equates to a yield to worst of 6.993%. The proceeds from this debt issuance were used to pay down the balance on our credit facility, which increased our available liquidity.

2011 Debt Issuance. We issued $250.0 million of 7.875% senior notes due in 2022 in November 2011 at 99.156% of face value. The proceeds from this debt issuance were recorded in "Cash and cash equivalents" on the accompanying consolidated balance sheet at December 31, 2011 and were used to fund capital expenditures in 2012.

Financial Ratios

Working Capital and Debt to Capitalization Ratio. Our working capital decreased from a surplus of $116.4 million at December 31, 2011, to a deficit of $96.9 million at December 31, 2012. The change primarily resulted from a decrease in cash and cash equivalents as we used cash received from our debt offerings in November 2011 and October 2012 to fund ongoing operations, including our 2012 capital program, and to pay down borrowings on our credit facility. Working capital, which is calculated as current assets less current liabilities, can be used to measure both a company's operational efficiency and short-term financial health. The Company uses this measure to track our short-term financial position. Our working capital ratio does not include available liquidity through our credit facility. Our debt to capitalization ratio was 47% and 42% at December 31, 2012 and December 31, 2011, respectively.

Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter as of
December 31, 2012 were as follows (in thousands):
                            2013        2014       2015       2016       2017       Thereafter       Total
Non-cancelable operating
leases (1)               $   8,330   $  6,534   $  1,080   $      -   $       -   $          -   $    15,944
Asset retirement
obligation (2)               7,134      4,765      4,244      2,694       2,749         65,191        86,777
Drilling rigs and
completion services         20,684          -          -          -           -              -        20,684
Geoscience data services     1,777      1,301          -          -           -              -         3,078
Gas transportation and
Processing (3)               9,963     10,890      7,752      6,456       3,723          8,385        47,169
7-1/8% senior notes due
2017                             -          -          -          -     250,000              -       250,000
8-7/8% senior notes due
2020                             -          -          -          -           -        225,000       225,000
7-7/8% senior notes due
2022                             -          -          -          -           -        400,000       400,000
Interest Cost               69,281     69,281     69,281     69,281      60,375        191,672       529,171
Credit facility (4)              -          -          -          -      39,400              -        39,400
Total                    $ 117,169   $ 92,771   $ 82,357   $ 78,431   $ 356,247   $    890,248   $ 1,617,223

(1) Our most significant office lease is in Houston, Texas and it extends until 2015.
(2) Amounts shown by year are the net present value at December 31, 2012.
(3) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations.
(4) The credit facility expires in November 2017 and these amounts exclude $0.9 million standby letters of credit outstanding under this facility.

As of December 31, 2012, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

We have added proved reserves over the past three years primarily through our drilling activities, including 43.8 MMBoe added in 2012, 58.0 MMBoe added in 2011, and 36.7 MMBoe added in 2010. The 2012 proved reserves additions from drilling activities consisted primarily of additions in the Artesia Wells field in South Texas, based on the results of the horizontal drilling program conducted in this area during the year, and also included additions in the Burr Ferry field. We obtained reasonable certainty regarding these reserves additions by applying the same methodologies that have been used historically in this area. At year-end 2012, 34% of our total proved reserves were proved developed, compared with 35% at year-end 2011 and 45% at year-end 2010.

At year-end 2012, our proved reserves were 192.1 MMBoe with a PV-10 Value of $2.3 billion (PV-10 Value is a non-GAAP measure, see the section titled "Oil and Natural Gas Reserves" in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure), an increase in the PV-10 Value of approximately $366 million, or 19%, from the prior year-end levels. In 2012, our proved natural gas reserves decreased 19.2 Bcf, or 3%, while our proved oil reserves increased 12.3 MMBbl, or 40%, and our NGL reserves increased 23.4 MMBbl, or 90%, for a total equivalent increase of 32.5 MMBoe, or 20%.

We use the preceding 12-months' average price based on closing prices on the first business day of each month in calculating our average prices used in the PV-10 Value calculation. Our average natural gas price used in the PV-10 Value calculation for 2012 was $2.71 per Mcf. This average price during 2012 was a decrease from $3.89 per Mcf at year-end 2011, compared to $4.08 per Mcf at year-end 2010. Our average oil price used in the PV-10 Value calculation for 2012 was $103.64 per Bbl. This average price during 2012 was slightly lower than the average price of $103.87 per Bbl at year-end 2011, compared to $78.31 in 2010.

Critical Accounting Policies and New Accounting Pronouncements

Property and Equipment. We follow the "full-cost" method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which . . .