Attached files
| file | filename |
|---|---|
| 8-K - ROSE UPDATED PRESENTATION - NBL Texas, LLC | roseupdatedpres.htm |
1
Rosetta Resources Inc.
Credit Suisse Energy Summit
February 9, 2011
Exhibit 99.1
2
All statements, other than statements of historical fact, included in this presentation are forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are statements
that are not historical facts, such as expectations regarding drilling plans, changes in acreage positions, and expected
capital expenditures. 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; 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; pipeline capacity availability and pipeline construction difficulties; climatic
conditions; availability and cost of material and equipment; the risks associated with operating in a limited number of
geographic areas; availability of capital; timing of planned divestitures; regulatory developments; environmental risks;
general economic and business conditions (including the effects of the worldwide economic recession); the amount and
expected benefit of hedging arrangements; industry trends; and other factors detailed in the Company's most recent
Form 10-K 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 change), 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.
within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are statements
that are not historical facts, such as expectations regarding drilling plans, changes in acreage positions, and expected
capital expenditures. 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; 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; pipeline capacity availability and pipeline construction difficulties; climatic
conditions; availability and cost of material and equipment; the risks associated with operating in a limited number of
geographic areas; availability of capital; timing of planned divestitures; regulatory developments; environmental risks;
general economic and business conditions (including the effects of the worldwide economic recession); the amount and
expected benefit of hedging arrangements; industry trends; and other factors detailed in the Company's most recent
Form 10-K 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 change), 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.
Forward-Looking Statements
3
Cautionary Statement Concerning Resources
The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to
disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and
legally producible by application of development projects to known accumulations. We may use certain terms in this
presentation, such as “Risked Project Inventory,” “Project Counts,” “Net Risked Resources,” “Total Resources,” “Unrisked
Potential,” “Unrisked Original Resources in Place,” and “Unrisked EUR Potential” that the SEC's guidelines strictly prohibit
us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved
reserves and accordingly are subject to substantially greater risk of actually being realized.
disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and
legally producible by application of development projects to known accumulations. We may use certain terms in this
presentation, such as “Risked Project Inventory,” “Project Counts,” “Net Risked Resources,” “Total Resources,” “Unrisked
Potential,” “Unrisked Original Resources in Place,” and “Unrisked EUR Potential” that the SEC's guidelines strictly prohibit
us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved
reserves and accordingly are subject to substantially greater risk of actually being realized.
For filings reporting year-end 2009 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 reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery
techniques. Estimates of unproved 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 unproved
resources may change significantly as development provides additional data, and actual quantities that are ultimately
recovered may differ substantially from prior estimates.
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 reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery
techniques. Estimates of unproved 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 unproved
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.
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.
Forward-Looking Statements (Cont.)
4
Rosetta Resources - 2010 Highlights
• Capital spending focused on Eagle Ford
• High return/high value programs received vast majority of funding
• Capital exceeded internal cash flows, but balanced with asset sales
and beginning cash
and beginning cash
• 2010 asset sales are approximately $90MM
• Production growth
• Annual production rate of 135-140 MMcfe/d
• Exit rate of 159 MMcfe/d
• Eagle Ford exit rate of 86 MMcfe/d
• Reserve growth
• Double digit reserve growth rate
5
• $360 MM Capital Budget in 2011
• Focus on Eagle Ford
• 90% of 2011 capital allocated to Eagle Ford
• 40 wells planned
• Fracture stimulation services agreement in place
• Gates Ranch EUR revised upward
• Light Ranch discovery announced
• Pipeline and processing capacity expanded
• Inventory in excess of 1 TCFE
• Shift to liquids accelerates
• Southern Alberta Basin evaluation continues
• Six wells drilled
• Additional five wells to be drilled by early 2011
• Completions planned for 2011
• Additional asset sales scheduled
• DJ Basin
• Sacramento Basin
• Strong alignment with stakeholders remains fundamental driver
Taking it Up a Notch
6
Rosetta Asset Portfolio Status
7
• EOY 2007
• Rosetta has 5,000 net acres under lease with Eagle Ford potential
• EOY 2008
• Rosetta has 25,000 net acres under lease with Eagle Ford potential
• Rosetta completes vertical pilot drilling program to understand resource potential
• EOY 2009
• Rosetta has 61,000 net acres under lease with Eagle Ford potential
• Rosetta drills its successful horizontal discovery well in Springer Ranch (14,000 net acres)
• Rosetta drills its successful horizontal discovery well in Gates Ranch Area (29,500 net acres)
• EOY 2010
• Rosetta has 65,000 net acres under lease with Eagle Ford potential
• Rosetta completes full delineation of Gates Ranch
• Gates Ranch EUR revised to 7.2 Bcfe
• Rosetta has drilled its 22nd horizontal well at Gates Ranch with 100% success rate
• Dos Hermanas Pipeline in service
• 2010 exit rate of 86 MMcfe/d
Eagle Ford
8
Rosetta’s drilling focus has been primarily on the Gates Ranch Area, however, we
have embarked on the delineation of our other liquids-rich areas…
have embarked on the delineation of our other liquids-rich areas…
|
Area
|
Hydrocarbon Window
|
Net Acres
|
|
Gates Ranch Area
|
Condensate
|
29,960
|
|
Central Dimmit
|
Oil
|
7,450
|
|
Encinal Area
|
Dry Gas
|
14,500
|
|
Gonzales Area
|
Oil
|
6,500
|
|
NE LaSalle Area
|
Oil
|
3,450
|
|
Western Webb
|
Condensate
|
3,000
|
|
Total
|
77% Liquids
|
64,860
|
9
Eagle Ford - Gates Ranch
10
Gates Ranch Area
11
4-19
9-5
1-2
3-19
13-1287
B #2-24
BVP #1
BVP #2
7-15
6-12
6-6A
B #2-23
P
P
P
P
B #1-23
B #1-26
571#1
P
P
P
P
P
Gates Ranch Delineation
Initial horizontal wells were strategically located to delineate the asset
7-7A
Delineation Wells
• Gates 05D 9-5
• Gates 05D 3-19
• Gates 05D 4-19
• Gates 05D 13-1287
• Gates 05D 7-7A
• Gates 05D 6-6A
• Gates 09 Rose B 1-23
• Gates 05D 1-2
• Gates 09 Rose B 2-24
• Gates 05D 6-12
• Gates 09 Rose A BVP-2
• Gates 05D 7-15
• Gates 09 Rose A BVP-1
• Gates 09 Rose B 1-26
• Gates 10 Rose A 571-1
12
Delineation Wells
• Gates 05D 9-5
• Gates 05D 3-19
• Gates 05D 4-19
• Gates 05D 13-1287
• Gates 05D 7-7A
• Gates 05D 6-6A
• Gates 09 Rose B 1-23
• Gates 05D 1-2
• Gates 09 Rose B 2-24
• Gates 05D 6-12
• Gates 09 Rose A BVP-2
• Gates 05D 7-15
• Gates 09 Rose A BVP-1
• Gates 09 Rose B 1-26
• Gates 10 Rose A 571-1
Development Wells (Drilled by YE 2010)
• Gates 05D 6-8
• Gates 05D 2-20
• Gates 09 Rose B 1-1
• Gates 09 Rose B 2-23
• Gates 09 Rose A BVP-3
• Gates 05D 1-8A
• Gates 10 Rose A 1000-1
• Gates 05D 2-8A
• Gates 05D 8-15
• Gates 09 Rose B 2-1
• Gates 09 Rose B 2-26
Including our initial Gates Ranch discovery well, we have drilled 26 horizontal wells in the
field to date…averaging roughly 5,000 feet of horizontal length per well…
field to date…averaging roughly 5,000 feet of horizontal length per well…
4-19
9-5
1-2
3-19
13-1287
B #2-24
BVP #1
BVP #2
7-15
6-12
B #1-1
6-6A
B #2-23
2-20
B #1-23
B #1-26
571#1
7-7A
BVP #3
6-8
1000 #1
1-8A
2-8A
8-15
2-1
2-26
13
Gates Ranch New Type Curve
Based on actual well performance, the average EUR has been revised from 4.0 BCFE to 7.2 BCF
Previous 4.0 BCFE EUR
Current 7.2 BCFE EUR
Actual Well Performances (13 wells)
14
|
Area
|
Initial
Gas Rate
(mmcfpd)
|
Initial
Oil Rate
(bopd)
|
EUR
(bcfe)
|
NPV Per
Well BFIT10
($MM)
|
Discounted
Payout
(years)
|
Post 2010
Inventory
(Net Wells)
|
NPV Per Area
BFIT10
($)
|
|
Gates North Type Curve
|
5.0
|
450
|
6.7
|
13.0
|
1.6
|
150
|
$1.950 billion
|
|
Gates South Type Curve
|
7.0
|
350
|
8.1
|
14.1
|
1.4
|
90
|
$1.269 billion
|
|
Gates Ranch Type Curve
|
5.7
|
412
|
7.2
|
13.4
|
1.5
|
240
|
$3.219 billion
|
Notes:
• Gates Ranch proper only (26,500 net acres)
• 100 acre well spacing
• $8.25 mm total well cost
• Strip pricing effective 10/26/2010
• “Per area” values are “per well” values multiplied by post 2010 net inventory
Gates Ranch Valuation
On average, a typical well has a 7.2 BCFE EUR and a BFIT NPV of $13.4 MM…
15
Although the Gates Ranch Area offers us more than 18 rig years...we are defining
Inventory beyond Gates Ranch Area…
Inventory beyond Gates Ranch Area…
Central Dimmit Area
16
Central Dimmit Discovery Well
Initial Test
Light Ranch #1H Discovery
Vivion
Light
Ranch
Ranch
Lasseter &
Eppright
Eppright
Central Dimmit Exploration & Development Plan
17
With less than 5% of our Gates Ranch Area inventory drilled and producing, we have built a
legacy asset from scratch that is currently producing more than 80 MMcfe/d…
legacy asset from scratch that is currently producing more than 80 MMcfe/d…
18
Eagle Ford Pipeline Projects
DOS HERMANAS
To HPL
Legend
Dos Hermanas
---- Dimmit Lateral
19
• Dos Hermanas in service December 2010
• Firm gathering and processing reaches 85 MMcfe/d
• Revised agreement in place:
• Dimmit lateral in service 2nd quarter 2011
• Dos Hermanas capacity to increase by 20 MMcfe/d in 3rd
quarter 2011
quarter 2011
• Rosetta to access new gathering and processing
capacity in 4th quarter 2011
capacity in 4th quarter 2011
Eagle Ford Gathering
20
• Southern Alberta Basin specifics
• Devonian Shale oil play in NW Montana
• Williston Basin analog
• Depths ranging from 4,500’ to 7,500’ TVD
• Over-pressured reservoirs
• Rosetta’s current Southern Alberta Basin
position
position
• 300,000 undeveloped net acres
• 13 - 15 MMBoe per square mile of resource in place
• Rosetta’s assessment to date
• Drilled 6 exploratory delineation wells
• 2 wells on strike 28 miles apart (Riverbend 12-13 and
Gunsight 31-16)
Gunsight 31-16)
• 1 well 8 miles downdip (Riverbend W 7-4)
• Drilled a north east extension and encountered thickening
Banff and Bakken intervals (Big Rock 29-13)
Banff and Bakken intervals (Big Rock 29-13)
• Drilled 2 middle of area wells which established continuity
(Little Rock Coulee 27-16 and Fee Gauge 19-1)
(Little Rock Coulee 27-16 and Fee Gauge 19-1)
• Confirmed significant oil hydrocarbons in place and
over-pressured reservoirs
over-pressured reservoirs
• Conducted vertical tests in several zones
• Multi-well vertical program underway
Southern Alberta Basin Opportunity is Unique
1st of 8 WELL
PROGRAM
PROGRAM
REMAINING ROSE
PLANNED WELLS
RB 12-13
RBW 7-4
GS 31-16
LRC 27-16
FG 19-1
BR 29-13
FB 25-5
FT 7-14
BL 5-16
GSS 12-15
GF 22-12
ROSE
ORIGINAL WELLS
21
|
Acres
|
Lessor
|
Terms
|
|
200,000
|
Blackfeet Indian Nation
|
• 5 year option with 2 well per year drilling requirement for 10 well total.
• With each commercial well, Rosetta earns the right to lease 20,000 acres
surrounding that well for a 10 year term. • Continuous drilling obligation of 1 well per 9 months beginning on the 4th
year. |
|
30,000
|
WAVE Energy
|
• Terms similar to option acreage.
|
|
52,000
|
Allottee (Blackfeet Families)
|
• Typically 5 year lease terms, with option to extend term at the end of the
primary period. |
|
18,000
|
Fee Acreage
|
|
Southern Alberta Basin
Acreage Recap
Acreage Recap
22
Financial Strategy
• Bias for conservative and disciplined approach to financial
management
management
• Actively manage and monitor use of debt
• Debt to book cap < 40%
• Debt to EBITDAX < 1.75x
• Attempt to maintain high level of liquidity throughout cycles
• Asset sales to “balance” 2011 capital program
1 Adjusted for the high yield offering
23
Risk Management
• Selective hedging program:
• Gas hedges of 50,000 MMBtu/d in 2011 and 20,000 MMBtu/d in 2012
• Oil hedges of 2,700 Bbl/d in 2011 and 3,100 Bbl/d in 2012
• NGL Hedges of 1,300 Bbl/d in 2011/1,450 Bbl/d in 2012
• Fracture stimulation services/agreement in place
• 2 year term
• 3 weeks per month
• Favorable pricing
• Transportation and processing
• 35 MMcfe/d base agreement
• 50 MMcfe/d on Dos Hermanas
• Dimmit County lateral in place 2nd quarter 2011
• 20 MMcfe/d added in 3rd quarter of 2011
• Additional capacity available in 4th quarter of 2011
24
• Focus on high return Eagle Ford inventory
• Production guidance dependent on divestiture timing
• 160-170 MMcfe/d including divestment properties
• DJ Basin/California expected to produce approximately 35 MMcfe/d for full year
• 2011 exit rate, excluding divestment properties, to range from 155-165 MMcfe/d
• Divest additional legacy assets to fund development
• Simplify and reduce unit cost structure
• Focus on returns
• Test Southern Alberta Basin position
2011 Program
25
26
Appendix 1 of 5: 3-Stream Process Flow - Gates Ranch
Note: This example describes the 3-streams of production from the average 2010 Gates Ranch horizontal
wells (based on completions as of July, 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d.) This is important
for understanding Rosetta’s takeway capacity situation. As described, gross wellhead gas, and therefore
takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
wells (based on completions as of July, 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d.) This is important
for understanding Rosetta’s takeway capacity situation. As described, gross wellhead gas, and therefore
takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
27
Appendix 2 of 5: Converting Wellhead to Sales
|
|
Well Head
Production |
Effect of
Processing
|
Mcfe
Equivalent
|
|
Gas
|
4,430 Wet Mcf/d
|
3,100 Lean Mcf/d
|
3,100 Mcfe/d
|
|
NGL
|
--
|
500 Bbl/d
|
3,000 Mcfe/d
|
|
Condensate
|
320 Bbl/d
|
320 Bbl/d
|
1,920 Mcfe/d
|
|
Gross Production
|
8,020 Mcfe/d
|
||
|
Net Production
|
6,015 Mcfe/d
|
|
|
6,015 Net
|
|
|
|
Uplift
|
|
=
|
1.36
|
|
|
4,430 Gross
|
|
|
Note: This example describes the 3-streams of production from the average 2010 Gates Ranch horizontal
wells (based on completions as of July 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d). This is
important for understanding Rosetta’s takeaway capacity situation. As described, gross wellhead gas,
and therefore takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
wells (based on completions as of July 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d). This is
important for understanding Rosetta’s takeaway capacity situation. As described, gross wellhead gas,
and therefore takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
28
Appendix 3 of 5: Converting to Net 3-Stream Volumes
|
|
Well Head
Production |
Effect of
Processing
|
Mcfe
Equivalent
|
|
Gas
|
85,000 Wet Mcf/d
|
59,481 Lean
|
59,481 Mcfe/d
|
|
NGL
|
--
|
9,594 Bbl/d
|
57,564 Mcfe/d
|
|
Condensate
|
2,889 Bbl/d
|
6,139 Bbl/d
|
36,834 Mcfe/d
|
|
Gross Production
|
153,879 Mcfe/d
|
||
|
Net Production
|
115,409 Mcfe/d
|
|
|
115,409 Net
|
|
|
|
Uplift
|
|
=
|
1.36
|
|
|
85,000 Gross
|
|
|
Note: This example describes the 3-streams of production from the average 2010 Gates Ranch horizontal
wells (based on completions as of July 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d). This is
important for understanding Rosetta’s takeaway capacity situation. As described, gross wellhead gas,
and therefore takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
wells (based on completions as of July 2010) and also provides a “rule of thumb” factor to convert “net
Rosetta sales volumes” (measured in Mcfe/d) to “gross wellhead gas” (measured in Mcf/d). This is
important for understanding Rosetta’s takeaway capacity situation. As described, gross wellhead gas,
and therefore takeaway capacity, is multiplied by ~1.3 to determine net sales to Rosetta.
29
Natural Gasoline Use: Petrochemical and Refining
Price: 92% WTI
Note: Comprised of all remaining
components
components
Price Risk: Low
Butane Use: Primarily heating and industrial
Price: 86% of WTI Crude
Note: Butane market more robust
Price Risk: Low
Propane Use: 50% Residential and Commercial
Heating, 50% Petrochemical
Heating, 50% Petrochemical
Price: 50% of WTI Crude
Note: Propane demand is seasonal and is
subject to weather
subject to weather
Price Risk: Medium
Appendix 4 of 5: Gates Ranch NGL Breakdown
Ethane Use: Petrochemical feedstock (plastics)
Price: 25% WTI Crude
Note: May be rejected and combined with
gas sale when priced below residual
gas price
gas sale when priced below residual
gas price
Price Risk: High
C2
C5+
C4
C3
17%
25%
8%
30
Appendix 5 of 5: NGL Hedge Detail
|
Barrel Component
|
% of Bbl
|
% WTI
|
Hedged
Volume |
$/GAL
|
$/Bbl
|
|
Ethane
|
50%
|
25%
|
-
|
-
|
-
|
|
Propane
|
25%
|
50%
|
350
|
1.00
|
41.92
|
|
Butane (I&N)
|
17%
|
86%
|
210
|
1.33
|
55.50
|
|
Natural Gasoline
|
8%
|
92%
|
140
|
1.68
|
70.61
|
|
Avg. Price per Bbl
|
|
47%
|
700
|
1.23
|
51.74
|