Exhibit 99.1
REDEFINED
BUILDING VALUE IN UNCONVENTIONAL RESOURCES
Rosetta Resources Inc.
February 2013 Investor Presentation
2012 Highlights
4
Includes capitalized interest and other corporate costs
By Region
By Region
By Category
By Category
2013 Plans and Capital Program ($640-700 Million1)
• Run five- to six-rig program in Eagle Ford area
• Continued focus on liquids-rich development
• Drill 75-80 wells and complete approximately 60-65 in
2013
2013
• About half in Gates Ranch with remainder in Karnes Trough,
Briscoe Ranch and Central Dimmit areas
Briscoe Ranch and Central Dimmit areas
• Allocate 10 percent to new ventures opportunities
• Fund base capital program from internally-generated
cash flow supplemented by borrowings under current
credit facility, if necessary
cash flow supplemented by borrowings under current
credit facility, if necessary
• Generate approximately 30 percent production growth
over 2012
over 2012
5
1. 2013 Guidance, February 25, 2013
• Leverage high-graded asset base
• Maintain position as a leading Eagle Ford player
• Develop inventory of approximately 500 MMBoe with 15 years of drilling opportunities
• Expand production base with about 12 percent of inventory developed
• Successfully execute business plan
• Grow total production and liquids volumes
• Lower overall cost structure and improve margins
• Capture firm transportation and processing capacity
• Test future growth opportunities
• Evaluate previously untested Eagle Ford acreage
• Continue testing optimal Eagle Ford well spacing
• Pursue new growth targets through blend of acquisitions and new ventures
• Maintain financial strength and flexibility
• Low leverage
• Sizable liquidity
• Active hedging program
Company Strategy
6
LEVERAGE HIGH-GRADED ASSET BASE
7
• Since 2009, proved reserves more than tripled;
total risked resources nearly tripled
total risked resources nearly tripled
• Total project inventory, including PUDs,
grew from 150 MMBoe to 496 MMBoe
• About 12 percent of inventory developed
and on production
• Growth driven by Eagle Ford Shale
• Transformed total proved liquids mix
2009: 15% 2011: 54%
2010: 40% 2012: 58%
• From 2009 through 2012, divested 36 MMBoe
of proved reserves for properties that no
longer fit operating model
of proved reserves for properties that no
longer fit operating model
• Divested 11 MMBoe in 2012
• Strong reserve replacement in 2012
• 482 percent from the drill-bit
• 472 percent from all sources
Significant Growth in Asset Net Resources
8
Divested 11 MMBoe
Quarterly Production Performance
9
% Liquids | 14 | 19 | 24 | 29 | 33 | 46 | 51 | 49 | 52 | 59 | 60 | 62 | 62 - | 63 | |
% Oil | 5 | 7 | 10 | 12 | 15 | 18 | 19 | 22 | 22 | 24 | 30 | 26 | 30 |
52 - 56
47 - 51
Eagle Ford Growth Profile
10
Eagle Ford production averaged
44.2 MBoe/d during 4Q 2012
44.2 MBoe/d during 4Q 2012
• 62% total liquids
• 26% oil / 36% NGLs
MBoe/d
Exit Rate Guidance
(As of 12/10/2012)
Reaffirmed 2/25/2013
52 - 56 MBoe/d
2012 Program
62 wells
62 wells
January Average
Production
Production
47.4 MBoe/d
29% Oil / 34% NGLs
SUCCESSFULLY EXECUTE BUSINESS PLAN
11
Top 20 Eagle Ford Operators
12
Top 20 Eagle Ford Operators include APC, BHP, CHK, COP, CRK, CRZO, EP, EOG, GeoSouthern, Hunt, Lewis, MRO, MTDR, MUR, PXD, PXP, RDS, ROSE, SM, TLM.
Gates Ranch
13
Summary
• 26,500 net acres in Webb County
• 96 completions as of 12/31/2012
• 1Q - 3Q 2012: 28 completions
• 4Q 2012: 12 completions
• 332 well locations remaining under current
55-acre spacing assumptions
55-acre spacing assumptions
• 20 wells drilled awaiting completion
Average Well Characteristics
• Well Costs: $6.5 - $7.0 million
• Spacing: 475 feet apart or 55 acres
• Composite EUR: 1.67 MMBoe
• F&D Costs: $4.05/Boe
• Condensate Yield = 65 Bbls/MMcf
• NGL Yield = 110 Bbls/MMcf
• Shrinkage = 23%
Well Performance on 55 acres
Compared to similar offsetting wells spaced at 100 acres
Compared to similar offsetting wells spaced at 100 acres
These 9 wells are our largest
continuous group of producing wells
spaced on 55 acres
continuous group of producing wells
spaced on 55 acres
These 9 wells are performing in
line with comparable offsetting
wells drilled and completed early
in the development of the area
and spaced on 100 acres …
line with comparable offsetting
wells drilled and completed early
in the development of the area
and spaced on 100 acres …
Composite Type Curve - 1.7 MMBoe
(23% Oil / 32% NGLs)
South Type Curve - 1.9 MMBoe
North Type Curve - 1.4 MMBoe
Gates Ranch Well Performance - North and South Areas
15
Discovery well:
Shortest lateral at
3,500’ and only
3,500’ and only
10 frac stages
Eagle Ford Multiple Takeaway Options
16
Gas Transportation Capacity
Firm gross wellhead gas takeaway
• 245 MMcf/d today
Four processing options - Gathering (Plant)
• Regency (Enterprise Plants)
• Energy Transfer “ETC” Dos Hermanas (King Ranch)
• Eagle Ford Gathering (Copano Houston Central)
• ETC Rich Eagle Ford Mainline (LaGrange/Jackson)
Net 3-stream takeaway increases with higher
contribution of oil-weighted volumes
contribution of oil-weighted volumes
Oil Transportation Capacity
Gates Ranch, Briscoe Ranch and Central Dimmit Co.
• Plains Crude Gathering - Firm gathering capacity of
25,000 Bbls/d to Gardendale hub with up to 60,000 Bbls
storage; operating since April 2012
25,000 Bbls/d to Gardendale hub with up to 60,000 Bbls
storage; operating since April 2012
• Access to truck and rail loading and pipeline
connections
connections
Karnes Trough
• Rosetta-owned oil truck-loading facility operating since
late July 2012
late July 2012
• Trucking readily available
Pricing assumptions included in Appendix
Well-positioned to move
new production to
market with access to
multiple midstream
service providers
new production to
market with access to
multiple midstream
service providers
TEST FUTURE GROWTH OPPORTUNITIES
17
19
Briscoe Ranch
Summary
• 3,545 net acres in southern Dimmit County
• 4 completions as of 12/31/2012
• 3Q 2012: 3 completions
• 64 well locations remaining
• 3 wells drilled awaiting completion
Average Well Characteristics
• Well Costs: $6.5 - $7.0 million
• Spacing: 425 feet apart or 50 acres
• Condensate Yield: 80 Bbls/MMcf
• NGL Yield: 130 Bbls/MMcf
• Shrinkage: 23%
Future Activity
• Planned full development activity will last
well into 2016
well into 2016
*Seven-day stabilized rate
Discovery Well Initial Rate* - 10/2011
1,990 Boe/d, 68% Liquids
(850 Bo/d, 490 B/d NGLs, 3,900 Mcf/d)
Briscoe Ranch Type Curve
21
Karnes Trough Area
SUMMARY
• 1,900 net acres; located in oil window
• 17 total completions as of 12/31/2012
• 1Q & 2Q 2012: 9 completions
• 4Q 2012: 7 completions
• 8 well locations remaining to be completed
• 5 wells drilled awaiting completion
• Well Costs: $7.5 - $8.0 million
• Activity planned through mid-2013
Klotzman (Dewitt County)
• 15 total completions as of 12/31/2012
• 1Q & 2Q 2012: 7 completions
• 4Q 2012: 7 completions
• Rosetta-owned oil truck terminal operating
since late July 2012
since late July 2012
Reilly (Gonzales County)
• 2 completions as of 12/31/2012
• 1Q 2012: 1 completion
• 2Q 2012: 1 completion
• 5 wells drilled awaiting completion
*Seven-day stabilized rate
Klotzman 1H
Discovery Well Initial Rate* - 11/2011
3,033 Boe/d, 81% Oil
(2,450 Bo/d, 250 B/d NGLs, 2,000 Mcf/d)
Adele Dubose 1H
Delineation Well Initial Rate* - 2/2012
1,463 Boe/d, 76% Oil
(1,109 Bo/d, 153 B/d NGLs, 1,200 Mcf/d)
Klotzman Type Curve
23
Central Dimmit County Area
Summary
• 8,100 net acres in Dimmit County
• 5 completions as of 12/31/2012
• 2Q 2012: 2 completions
• 3Q 2012: 1 completion
• 122 well locations remaining
• 4 wells drilled awaiting completion
• Average Well Costs:
• L&E $6.5 - $7.0 million
• Vivion & Light Ranch $5.5 - $6.0 million
*Seven-day stabilized rate
Light Ranch 1H
Discovery Well Initial Rate* - 10/2010
987 Boe/d, 78% Liquids
(510 Bo/d, 260 B/d NGLs, 1,300 Mcf/d)
Vivion 1H
Discovery Well Initial Rate* - 9/2011
680 Boe/d, 89% Liquids
(506 Bo/d, 102 B/d NGLs, 436 Mcf/d)
Lasseter & Eppright 1
Discovery Well Initial Rate* - 9/2012
1,228 Boe/d, 76% Liquids
(667 Bo/d, 262 B/d NGLs, 1,792 Mcf/d)
Light Ranch
• 3 total completions as of 12/31/2012
• 2Q 2012: 2 completions
Vivion
• 1 completion as of 12/31/2012
Lasseter & Eppright
• 1 completion as of 12/31/2012
• 3Q 2012: 1 completion (discovery)
24
Lopez Farm-In
Summary
• 505 net acres in Live Oak County
• Farm-In from Killam Oil
• BPO: 100% WI, 75% NRI
• APO: 65% WI, 48.75% NRI
Average Well Characteristics
• Well Costs: $7.5 - $8.0 million
• Spacing: 60 acres
Future Activity
• 1 well planned in 1Q 2013
Eagle Ford Inventory
+/- 900 net wells remaining as of 12/31/2012
+/- 900 net wells remaining as of 12/31/2012
* Denotes roughly 12,000 net acres in the liquids window of the play.
25
FINANCIAL STRENGTH
AND FLEXIBILITY
AND FLEXIBILITY
26
Margin Expansion
27
1. Total cash costs (a non-GAAP measure) calculated as the sum of all average costs per Boe, excluding DD&A and stock-based compensation representing average cash costs
incurred by oil, NGL and natural gas producing activities. Not intended to replace GAAP statistics but to provide additional information helpful in evaluating trends and
performance.
incurred by oil, NGL and natural gas producing activities. Not intended to replace GAAP statistics but to provide additional information helpful in evaluating trends and
performance.
Commodity Derivatives Position - February 25, 2013
$40.64**
$41.96**
$81.52
X
$117.07
$83.33
X
$109.63
$94.15
$92.10
28
Debt and Capital Structure
350
250
883
879
29
410
1,214
Note: As of February 25, 2013, total debt is $425 million.
($MM)
($MM)
Adequate liquidity available to fund 2013
$640-$700 million capital program
$640-$700 million capital program
• Borrowing base raised in April, 2012
based on performance
• $400 million of $625 million borrowing
base available as of February 25th
Liquidity
30
Developing High-Graded Asset Base
• Focused on liquids-rich targets in Eagle Ford with significant project inventory
• Completed divestiture of South Texas legacy natural gas assets; redeployed proceeds
Executing Business Plan
• Grew proved reserves 25 percent versus 12/31/2011; more than double year-end 2010
• Increased Gates Ranch recoveries
• Ensured sufficient firm take-away capacity
• Recorded strong 2012 production growth and exit rates
Testing Growth Opportunities
• Increased Gates Ranch inventory
• Added discovery in another Eagle Ford area
• Pursuing new growth targets through blend of acquisitions and new ventures
Maintaining Financial Strength and Flexibility
• Debt-to-capitalization ratio in the 30 percent range
• Approximately $440 million in liquidity as of late February 2013
Summary
31
REDEFINED
BUILDING VALUE IN UNCONVENTIONAL RESOURCES
APPENDIX
33
2013 | |||||
$/BOE | |||||
Direct Lease Operating Expense | $ 2.15 | - | $ 2.40 | ||
Insurance | 0.07 | - | 0.08 | ||
Ad Valorem Tax | 0.65 | - | 0.75 | ||
Treating and Transportation | 4.20 | - | 4.65 | ||
Production Taxes | 1.50 | - | 1.65 | ||
DD&A | 11.75 | - | 12.90 | ||
G&A, excluding Stock-Based Compensation | 3.20 | - | 3.55 | ||
Interest Expense | 1.30 | - | 1.40 | ||
34
2013 Expense Guidance
As of December 10, 2012 (Reaffirmed February 25, 2013)
As of December 10, 2012 (Reaffirmed February 25, 2013)
• Volumes and Product Mix
• 2013 exit rate 52 - 56 MBoe/d; 62%-63% total liquids
• Averaged 47.4 MBoe/d in January 2013 (Oil 29%, NGLs 34%)
• 2013 oil percentage approximately 30%
• 2013 production on an overall upward trend; back-end loaded
• Treating & Transportation fees impacted by mix changes
• Crude Oil Pricing
• Average realized price continues to approximate WTI
• NGL pricing (Mont Belvieu Benchmark)
• Firm fractionation capacity
• Adjust for fractionation fees approximately $3 to $4 per barrel
• Adjust for reported 2013 derivative activity, including ethane
• Pricing estimates based on % of WTI not as correlative
Annual Guidance - Framing For Quarterly Models
35
4Q 2012 | 2012 | 2011 | 2010 | |
Daily rate (MBoe/d) | 44.3 | 37.2 | 27.6 | 22.9 |
Oil% / NGLs% | 26% / 36% | 26% / 33% | 18% / 26% | 9% / 13% |
$/Boe | $/Boe | $/Boe | $/Boe | |
Average realized price (without realized derivatives) | $42.58 | $42.10 | $42.45 | $32.98 |
Average realized price (with realized derivatives) | $43.57 | $43.63 | $44.18 | $36.85 |
Direct lease operating expense | $2.46 | $2.42 | $2.72 | $4.52 |
Workovers / Insurance / Ad valorem tax | 0.72 | 0.70 | 0.75 | 1.58 |
Lease operating expense | $3.18 | $3.12 | $3.47 | $6.10 |
Treating and transportation | 3.55 | 3.81 | 2.22 | 0.83 |
Production taxes | 1.27 | 1.23 | 1.20 | 0.71 |
General and administrative costs¹ | 3.38 | 3.69 | 4.59 | 5.04 |
Interest expense | 1.47 | 1.79 | 2.11 | 3.23 |
Total cash costs2 | $12.85 | $13.64 | $13.59 | $15.91 |
Cash Margin2 (without realized derivatives) | $29.73 | $28.46 | $28.86 | $17.07 |
Cash Margin2 (with realized derivatives) | $30.72 | $29.99 | $30.59 | $20.94 |
Margin Improvement
36
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.
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.