Rosetta Resources Inc. Announces 2011 Financial and Operational Results and Provides 2012 Outlook

• Doubled proved reserves to 161 MMBoe or 1,039 percent production replacement
• Raised total project inventory by 46 percent to 520 MMBoe
• Increased production by 20 percent with 146 percent growth in total liquids
• Achieved quarterly and annual all-time production records
• Improved operating margin performance
• Established three new productive Eagle Ford areas outside of Gates Ranch

HOUSTON, Feb. 27, 2012 (GLOBE NEWSWIRE) -- Rosetta Resources Inc. (Nasdaq:ROSE) ("Rosetta" or the "Company") today reported fourth quarter 2011 net income of $32.2 million, or $0.61 per diluted share, versus a net loss of $(1.4) million, or $(0.02) per diluted share, for the same period in 2010. For the year ended December 31, 2011, Rosetta reported net income of $100.5 million, or $1.91 per diluted share, versus a net income of $19.0 million, or $0.37 per diluted share, for the same period in 2010. The growth in net income is primarily due to higher realized prices, increased production and a more favorable product mix. Fourth quarter earnings per diluted share were impacted by $0.17 due to higher stock-based compensation expense primarily reflecting increases in the Company's share price.

"Rosetta's 2011 performance reflects our ongoing success in the Eagle Ford shale where we continue to significantly increase our production volumes, lower our operating cost structure and expand our inventory of future growth opportunities," said Randy Limbacher, Rosetta's chairman, CEO and president. "Our total production levels from a more balanced commodity mix are the highest in Rosetta's history and on track to move even higher. We have shifted to oil equivalent reporting as liquids production and revenues now account for more than half of our business. As we enter 2012, we are on course to generate even more favorable returns as we expand into new producing areas of the Eagle Ford shale."

2011 Fourth Quarter and Full Year Results

Production for the quarter averaged a record 32.0 thousand barrels of oil equivalent per day ("MBoe/d"), an increase of 31 percent from the same period in 2010 and 25 percent from the prior quarter. Production for the year averaged an all-time annual record of 27.6 MBoe/d, up 20 percent from 2010. The year-over-year increase for both periods was primarily driven by strong production growth from the Eagle Ford shale, which averaged approximately 27.4 MBoe/d for the fourth quarter of 2011 and 21.4 MBoe/d for the year. Total liquids production also reached all-time high levels for the periods ending December 31, 2011, averaging 15.6 MBbls/d for the quarter and 12.3 MBbls/d for the year.

Revenues for the fourth quarter of 2011 were $136.3 million compared to $89.4 million for the same period in 2010. For the quarter, 75 percent of revenue was generated from oil, condensate and NGL sales including the effects of hedging, as compared to 42 percent a year ago. Revenues for full-year 2011 were $446.2 million compared to $308.4 million for the same period in 2010. For the year, 63 percent of revenue was generated from oil, condensate and NGL sales including the effects of hedging, as compared to 32 percent a year ago.

Operating margins in full-year 2011 improved significantly versus the prior year as the result of the successful development of Eagle Ford shale assets and the sale of legacy natural gas properties. As compared to 2010, equivalent average sales price improved by 20 percent, the depreciation, depletion, and amortization rate declined by 12 percent and other average costs decreased an additional 15 percent. The most notable change in overall costs was a 43 percent drop in total lease operating expense ("LOE") on a per unit basis, including direct LOE, workovers, insurance, and ad valorem tax. A summary of the results on a per unit basis is included in the attached "Summary of Operating Data" table.

2011 Reserves and Inventory

Proved reserves as of December 31, 2011 grew by 101 percent to 161 million barrels of oil equivalent ("MMBoe") comprised of 36.4 million barrels of crude oil and condensate, 50.2 million barrels of natural gas liquids and 446 Bcf of natural gas. Included in the total is 82.4 MMBoe of reserves additions and 22.2 MMBoe in positive revisions primarily from success in the Eagle Ford shale offset by 13.5 MMBoe of reserves divested during the year. Revisions were primarily associated with improved recoveries from producing wells as well as anticipated higher recoveries from undeveloped wells. Of total proved reserves, 54 percent are liquids and 36 percent are classified as proved developed. Rosetta replaced 1,039 percent of production from all sources at a reserve replacement cost of $4.58 per Boe. Total reserve replacement metrics include net reserve additions from drilling activity, price and performance revisions.

For year-end 2011 reserve reporting, proved reserve estimates were based on the 12-month first day of the month historical average West Texas Intermediate and Henry Hub oil and gas prices adjusted for basis and quality differentials. The average prices for 2011 were $92.71 per barrel ("Bbl") for oil and $4.12 per million British thermal units ("MMBtu") for gas compared to the previous year's $75.96 per Bbl and $4.38 per MMBtu, respectively.

The following table describes Rosetta's year-end proved reserves by reserve classification:

The estimated standardized measure of discounted future net cash flows from Rosetta's proved reserves at December 31, 2011 was $1.7 billion, representing an increase of 145 percent from the prior year. 

In 2011, the Company also achieved significant growth in total project inventory with 520 MMBoe of net risked resources including proved undeveloped reserves. The amount consists of 54 percent liquids and reflects a 46 percent increase to the inventory portfolio as compared to year-end 2010.

Operational Update

During the fourth quarter of 2011, Rosetta made capital investments of $140.5 million and drilled 24 gross wells with a 100 percent success rate. Capital spending in 2011 totaled $480 million, including $408 million for activity in the Eagle Ford shale. For the year, the Company drilled 64 gross wells with a 100 percent success rate.

EAGLE FORD SHALE

Rosetta successfully completed 13 Eagle Ford wells during the fourth quarter of 2011 and 42 horizontal wells for full year 2011. As of December 31, 2011, the Company has completed a total of 64 horizontal Eagle Ford wells. During the fourth quarter, Rosetta operated four rigs in the area.

Eagle Ford shale well performance continued to surpass expectations during 2011. At mid-year based on actual Gates Ranch well performance, the Company again revised its gross estimated ultimate recovery rates to 1.7 MMBoe per well based on 100-acre spacing. Later in the year, Rosetta increased well density at its Gates Ranch development program to 65-acre spacing based on reservoir analysis of two infill pilot programs which may result in higher recoveries from the field. Currently, less than 16 percent of the Gates Ranch identified inventory is drilled and on production.

During the year, Rosetta successfully delineated three new areas outside of Gates Ranch, drilling discovery wells on Briscoe Ranch and Vivion acreage in Dimmit County and Klotzman acreage in the Karnes Trough area of DeWitt County. More than 200 potential drilling locations have been identified. In recent Karnes Trough area development, the Company completed another successful well located approximately three miles northwest of the Klotzman well. The Adele Dubose #1 is located on the 992-acre Reilly lease in Gonzales County in the oil-window of the play. The well was completed with a 5,626-foot lateral and 15 frac stages and brought on-line on February 11, 2012. The well tested at a gross stabilized rate of 1,109 Bbls/d of oil, 1.2 MMcf/d of residue gas, and 153 Bbls/d of NGLs for a total of 1,460 Boe/d.

An additional 10,000 acres remain to be evaluated in 2012. Rosetta plans to complete 60 Eagle Ford wells during 2012 and continue to operate four rigs in the area.

Total project inventory in the Eagle Ford grew 63 percent to 508 MMBoe. Rosetta has identified approximately 800 Eagle Ford drilling locations based on well spacing plans between 60 and 80 acres. At a targeted pace of approximately 60 completions per year, Rosetta expects to develop its current Eagle Ford inventory over the next 10 to 15 years.

SOUTHERN ALBERTA BASIN

During the year, Rosetta drilled four wells in its current seven-well horizontal program in the Southern Alberta Basin exploration play. The three remaining wells are scheduled to be drilled in 2012. Of the wells drilled to date, two have been completed and initial results reported in December. The third well was completed in the Middle Bakken and tested at a stabilized rate of 220 Bopd and 1.1 MMcf/d for a total of 403 Boe/d. The remaining four horizontal completions will be tested during the second half of 2012 as part of the Company's ongoing evaluation of its position in the exploratory play.

Financing and Hedging Update  

At the end of 2011, the Company had approximately $47.1 million of cash, up $5.5 million from the cash balance at year-end 2010. The borrowing base stands at $325 million with $30 million outstanding and $295 million available for borrowing at year-end under the Restated Revolver. As of February 24, 2012, cash and cash available under the revolving line of credit was approximately $300 million.

The attached hedging summary table outlines Rosetta's overall hedge position as of February 24, 2012. In the first quarter of 2012, the Company placed additional hedges for its crude oil and NGL production. Rosetta now has oil hedges in place for a total of 7,600 Bbls/d in 2012 with collars at an average floor price of $81.03 per Bbl and an average ceiling price of $117.03 per Bbl. The Company currently has hedged a total of 6,750 Bbls/d of oil in 2013 with collars at an average floor price of $81.01 per Bbl and an average ceiling price of $118.86 per Bbl. In 2014, Rosetta hedged 1,000 Bbls/d of oil with collars at an average floor price of $85.00 per Bbl and an average ceiling price of $108.80 per Bbl. For 2013 and 2014, Rosetta now has NGL hedges in place for 2,500 Bbls/d and 500 Bbls/d, respectively, with fixed price swaps at an average price of $64.48 per Bbl and $60.99 per Bbl, respectively, excluding the ethane component. Effective January 1, 2012, Rosetta discontinued hedge accounting.

Divestitures

On February 15, 2012, Rosetta entered into a purchase and sale agreement for its Lobo assets and a portion of its Olmos assets in South Texas. The operating area holds a total of 11 MMBoe of proved reserves and currently produces about 3.3 MBoe/d. The purchase price for the properties totals $95 million, subject to customary closing adjustments and the receipt of required consents for assignment.

2012 Outlook

The Company plans a 2012 capital program of $640 million with more than 90 percent directed toward Eagle Ford shale projects. Production guidance for the year, excluding the impact of divestitures, remains unchanged from earlier estimates with volumes projected to range from 36.7 – 40.0 MBoe/d and an anticipated exit rate between 41.7 – 46.7 MBoe/d. Rosetta is currently producing approximately 35.2 MBoe/d of which 52 percent is liquids. A summary of the Company's cost per unit expense guidance for full year 2012 is outlined in the attached table. Additionally, the necessary transportation capacity is in place to meet planned 2012 production levels with contracted firm capacity set to expand by more than 20 percent at mid-year.

Rosetta Resources Inc. is an independent exploration and production company engaged in the acquisition and development of onshore energy resources in the United States of America. The Company is one of the leading players in the Eagle Ford shale in South Texas and holds an exploratory position in the Southern Alberta Basin in northwest Montana. Rosetta is a Delaware Corporation based in Houston, Texas.

The Rosetta Resources Inc. logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=3139

(ROSE-F)

Forward-Looking Statements

This press release includes forward-looking statements, which give the Company's current expectations or forecasts of future events based on currently available information. Forward-looking statements are statements that are not historical facts, such as expectations regarding drilling plans, including the acceleration thereof, production rates and guidance, resource potential, incremental transportation capacity, exit rate guidance, net present value, development plans, progress on infrastructure projects, exposures to weak natural gas prices, changes in the Company's liquidity, changes in acreage positions, expected expenses, expected capital expenditures, and projected debt balances. The assumptions of management and the future performance of the Company are subject to a wide range of business risks and uncertainties and there is no assurance that these statements and projections will be met. Factors that could affect the Company's business include, but are not limited to: the risks associated with drilling of oil and natural gas wells; the Company's ability to find, acquire, market, develop, and produce new reserves; the risk of drilling dry holes; oil and natural gas price volatility; derivative transactions (including the costs associated therewith and the abilities of counterparties to perform thereunder); uncertainties in the estimation of proved, probable, and possible reserves and in the projection of future rates of production and reserve growth; inaccuracies in the Company's assumptions regarding items of income and expense and the level of capital expenditures; uncertainties in the timing of exploitation expenditures; operating hazards attendant to the oil and natural gas business; drilling and completion losses that are generally not recoverable from third parties or insurance; potential mechanical failure or underperformance of significant wells; midstream and pipeline construction difficulties and operational upsets; climatic conditions; availability and cost of material, equipment and services; the risks associated with operating in a limited number of geographic areas; actions or inactions of third-party operators of the Company's properties; the Company's ability to retain skilled personnel; diversion of management's attention from existing operations while pursuing acquisitions or dispositions; availability of capital; the strength and financial resources of the Company's competitors; regulatory developments; environmental risks; uncertainties in the capital markets; uncertainties with respect to asset sales; general economic and business conditions (including the effects of the worldwide economic recession); industry trends; and other factors detailed in the Company's most recent Form 10-K, Form 10-Q and other filings with the Securities and Exchange Commission. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. The Company undertakes no obligation to publicly update or revise any forward-looking statements except as required by law.

For filings reporting year-end 2011 reserves, the SEC permits the optional disclosure of probable and possible reserves. The Company has elected not to report probable and possible reserves in its filings with the SEC. We use the term "net risked resources" to describe the Company's internal estimates of volumes of natural gas and oil that are not classified as proved developed reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. Estimates of net risked resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company. Estimates of net risked resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. We use the term "BFIT NPV10" to describe the Company's estimate of before income tax net present value discounted at 10 percent resulting from project economic evaluation. The net present value of a project is calculated by summing future cash flows generated by a project, both inflows and outflows, and discounting those cash flows to arrive at a present value. Inflows primarily include revenues generated from estimated production and commodity prices at the time of the analysis. Outflows include drilling and completion capital and operating expenses. Net present value is used to analyze the profitability of a project. Estimates of net present value may change significantly as additional data becomes available, and with adjustments in prior estimates of actual quantities of production and recoverable reserves, commodity prices, capital expenditures, and/or operating expenses.