Rosetta Resources 8K Regulation FD Disclosure | SEC 1 Jun 12

Exhibit 99.1

REDEFINED

BUILDING VALUE IN UNCONVENTIONAL RESOURCES

Investor Presentation

JUNE 2012

Southern Alberta Basin

300,000 net acres

6 BBOE hydrocarbon resource in place

1500 potential locations

Exploration underway

11 delineation wells completed

7 horizontal wells drilled; 3 completed

4 horizontal well completions in progress

Eagle Ford Liquids

50,000 net acres

20 TCFE hydrocarbon resource in place

628 potential remaining locations

71 horizontal wells completed*

30.1 MBoe/d net*

Eagle Ford Dry Gas

15,000 net acres

5 TCFE hydrocarbon resource in place

171 potential locations

4 horizontal wells completed*

0.3 MBoe/d net*

* 1Q 2012 reporting

Quality Asset Base

• Since 2009, proved reserves more
than doubled; total risked resources
nearly tripled

• Total project inventory, including
PUDs, grew from 150 MMBoe to
520 MMBoe

• Less than 10% of inventory drilled
and on production

• Growth driven by Eagle Ford Shale

• Total proved liquids mix transformed

• 2009: 15%

• 2010: 40%

• 2011: 54%

• From 2009 through 2011, divested
25 MMBoe of proved reserves for
properties that no longer fit operating
model; divested another 11 MMBoe
non-core in first half 2012

Significant Growth in Asset Net Resources

Quarterly Production Performance

% Liquids: 14 19 24 29 33 46 51 49 52 60 61

% Oil: 5 7 10 12 15 18 19 22 22

SUCCESSFULLY EXECUTE BUSINESS PLAN

Includes capitalized interest and other corporate costs

Excludes New Ventures and A&D

By Region

By Category

2012E Capital - $640 Million

• Run four- to five-rig program in Eagle Ford area

• 60 completions for year

• Liquids-rich development

• Additional focus on Karnes Trough area and
Briscoe Ranch

• Complete seven-well horizontal drilling program
in Southern Alberta Basin

• Test new stimulation methodology

• Maintain and high-grade acreage position

• Fund base capital program from internally-
generated cash flow supplemented by
borrowings under current credit facility and
divestitures

Gates Ranch

Summary

• 26,500 net acres in Webb County

• 57 completions as of 12/31/2011

• 268 well locations remaining under current
spacing assumptions

• 1Q 2012: 10 completions

Average Well Characteristics

• Composite EUR: 1.67 MMBoe

• Condensate Yield = 64 Bbls/MMcf

• NGL Yield = 100 Bbls/MMcf

• Shrinkage = 20%

• Mix: Oil 21%, NGLs 34%

Evaluating further down-spacing

Composite Type Curve - 1.7 MMBoe

South Type Curve - 1.9 MMBoe

North Type Curve - 1.4 MMBoe

Gates Ranch Well Performance - North and South Areas

TEST FUTURE GROWTH OPPORTUNITIES

Karnes Trough Area

SUMMARY

• 1,900 net acres; located in oil window

• 1 completion as of 12/31/2011

• 21 well locations remaining

• 1Q 2012: 2 completions

• 7 wells in progress

• Activity planned through 2013

Klotzman (Dewitt County)

• 1 completion as of 12/31/2011

• 1Q 2012: 1 completion and 6 wells in
progress

• Constructing oil terminal to handle
10,000 - 12,000 Bbls/d with a targeted
July start-up date

Reilly (Gonzales County)

• 1Q 2012: 1 completion and 1 well in
progress

Discovery Well Initial Rate* - 11/2011

3,033 Boe/d, 81% Oil

(2,450 Bo/d, 250 B/d NGLs, 2,000 Mcf/d)

Delineation Well Initial Rate* - 2/2012

1,463 Boe/d, 76% Oil

(1,109 Bo/d, 153 B/d NGLs, 1,200 Mcf/d)

*Seven-day stabilized rate

Eagle Ford Inventory
+/- 800 net wells remaining as of 12/31/2011

* Denotes roughly 10,000 net acres in the liquids window of the play in Webb (~3,000), LaSalle (~3,500), and Gonzales (~3,000) counties.

FINANCIAL STRENGTH

AND FLEXIBILITY

Commodity Derivatives

Note: Derivatives position as of March 31, 2012. NGL derivatives exclude the Ethane component.

$63.77

$63.00

$64.48

$81.03

$117.03

$81.01

$118.86

$82.50

$111.95

Debt and Capital Structure

350

250

883

879

250

905

Note: As of May 4, 2012, total debt is $250 million.

($MM)

Adequate liquidity available to fund 2012
$640 million capital program

• Borrowing base raised in April, 2012 based
on performance

• $595 million of $625 million borrowing base
available as of May 4th

• Lobo and Olmos divestiture ($95 million,
before purchase price adjustments)

In low-price environment, $250 million in
capital required to maintain 2012
production level flat versus 2011 exit
rate

Liquidity

342

237

348

620

Asset Base High-Graded

• Focused on liquids-rich targets in Eagle Ford with significant project inventory

• Completed divestiture program; redeployed proceeds

• Continued to evaluate Southern Alberta Basin option

Executing Business Plan

• Doubled proved reserves since 12/31/2010

• Increased Gates Ranch recoveries

• Increased firm take-away capacity

• Projected strong 2012 growth and exit rates

Testing Growth Opportunities

• Increased Gates Ranch well density; testing further down-spacing

• Three discoveries in other Eagle Ford areas

• Complete and evaluate results of Southern Alberta Basin horizontal program

• Pursue new growth targets through blend of acquisitions and new ventures

Financial Strength and Flexibility

• Debt-to-capitalization ratio less than 30%

• Approximately $620 million in liquidity as of early May 2012

Summary

APPENDIX

	2012 Full Year

Production, MBoe/d (60% liquids)	35	-	38
Exit Rate, MBoe/d (61% liquids)	39	-	44

$/BOE
Direct Lease Operating Expense	$ 1.30	-	$ 1.45
Workover Expenses		-
Insurance	0.10	-	0.11
Ad Valorem Tax	0.75	-	0.85
Treating and Transportation	3.85	-	4.25
Production Taxes	1.50	-	1.65
DD&A	11.30	-	12.00
G&A, excluding Stock-Based Compensation	3.60	-	4.00
Interest Expense	1.55	-	1.70

Annual Guidance

	1Q 2012	4Q 2011	2011	2010
Daily rate (MBoe/d)	33.8	32.0	27.6	22.9
Oil% / NGLs%	22% / 30%	22% / 27%	18% / 26%	9% / 13%
	$/Boe	$/Boe	$/Boe	$/Boe
Average realized price (without realized derivatives)	$42.37	$42.69	$42.45	$32.98
Average realized price (with realized derivatives)	$43.01	$43.57	$44.18	$36.85
Direct lease operating expense	$1.89	$1.98	$2.72	$4.52
Workovers / Insurance / Ad valorem tax	0.87	0.37	0.75	1.58
Lease operating expense	$2.76	$2.35	$3.47	$6.10
Treating and transportation	3.90	2.89	2.22	0.83
Production taxes	1.05	1.81	1.20	0.71
General and administrative costs¹	3.86	5.02	4.59	5.04
Interest expense	1.77	1.57	2.11	3.23
Total cash costs2	$13.34	$13.64	$13.59	$15.91
Cash Margin2 (without realized derivatives)	$29.03	$29.05	$28.86	$17.07
Cash Margin2 (with realized derivatives)	$29.67	$29.93	$30.59	$20.94

Margin Improvement

1. Excludes stock-based compensation expense

2. Total cash costs (a non-GAAP measure) is calculated as the sum of all average costs per Boe, excluding DD&A and stock-based compensation. Cash Margin (a non-GAAP measure) is
calculated as the difference between average realized equivalent price and total cash costs. Management believes this presentation may be helpful to investors as it represents average
cash costs incurred by our oil, NGL and natural gas producing activities as compared to average realized price based on revenue generated. These measures are not intended to replace
GAAP statistics but rather to provide additional information that may be helpful in evaluating trends and performance.

REDEFINED

BUILDING VALUE IN UNCONVENTIONAL RESOURCES

Rosetta Resources Inactive 8-KRegulation FD Disclosure