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| 8-K - FORM 8K HOWARD WEIL PRESENTATION - NBL Texas, LLC | rosehwpresentation.htm |
REDEFINED
BUILDING VALUE IN UNCONVENTIONAL RESOURCES
Exhibit 99.1
40th ANNUAL HOWARD
WEIL CONFERENCE
WEIL CONFERENCE
Randy L. Limbacher
Chairman, CEO & President
March 28, 2012
This presentation 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; availability and limitations of capacity in midstream
marketing facilities, including processing plant and pipeline construction difficulties and operational upsets; climatic
conditions; availability and cost of material, supplies, 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; 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.
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; availability and limitations of capacity in midstream
marketing facilities, including processing plant and pipeline construction difficulties and operational upsets; climatic
conditions; availability and cost of material, supplies, 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; 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.
Forward-Looking Statements and Terminology Used
2
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 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.
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.
Forward-Looking Statements and Terminology Used (cont.)
3
• 2012 Plans
• Quality Asset Base
• Business Plan Execution
• Growth Catalysts
• Financial Strength
Agenda
4
• $640 million of capital; more than 90 percent allocated to Eagle Ford
• Four to five-rig program in Eagle Ford Area; 60 completions per year
• Continued liquids-rich development
• Additional focus on Briscoe Ranch and Karnes Trough area
• Completion of seven-well horizontal drilling program in Southern Alberta
Basin
Basin
• Test new stimulation methodology
• Maintain and high-grade acreage position
• Base capital program funded from internally-generated cash flow
supplemented by borrowings under current credit facility and
divestitures
supplemented by borrowings under current credit facility and
divestitures
• Eagle Ford program self-funding by year-end
• Complete Lobo and Olmos divestiture
• Debt-to-Capitalization ratio approximately 30%
• Approximately 40% production growth over 2011
2012 Plans
5
Includes capitalized interest and other corporate costs.
Excludes New Ventures and A&D.
2012E
2012E
2011
2011
Capital Expenditures
Total: $640MM
Total: $480MM
6
Quarterly Production Performance
% Liquids: 14 19 24 29 33 46 51 49 57 58
7
QUALITY ASSET BASE
8
Alberta Basin
300,000 net acres
6 BBOE hydrocarbon resource in place
1500 potential locations
Exploration underway
11 delineation wells completed
4 horizontal wells drilled
Horizontal completions underway
Eagle Ford Liquids
50,000 net acres
20 TCFE hydrocarbon resource in place
628 potential remaining locations
61 horizontal wells completed*
28.8 Mboe/d net*
Eagle Ford Dry Gas
15,000 net acres
5 TCFE hydrocarbon resource in place
171 potential locations
4 horizontal wells completed*
0.4 Mboe/d net*
South Texas
(Non-Eagle Ford)
60,000 net acres
Numerous stacked reservoirs
3.3 Mboe/d net*
* End of 4Q 2011
Asset Base High-Graded
On February 15, 2012,
Rosetta entered into
purchase and sale
agreement for its Lobo
assets and a portion of its
Olmos assets in S. Texas
Rosetta entered into
purchase and sale
agreement for its Lobo
assets and a portion of its
Olmos assets in S. Texas
9
BUSINESS PLAN EXECUTION
10
Proved Reserves - Doubled Since YE 2010
58 MMboe
80 MMboe
161 MMboe
11
Original 65-Acre
Test Areas
Test Areas
1700 feet
+/- 1700 feet
+/- 1700 feet
850 feet
425 feet
ORIGINAL CASE
Area = 195 acres
OHIP = 15.5 MMboe
98-acre well spacing
Well EUR = 1.7 MMboe
Total 195 acre EUR = 3.4 MMboe
RF = 22%
565 feet
283 feet
BEST CASE
Area = 195 acres
OHIP = 15.5 MMboe
65-acre well spacing
Assumed 100% incremental reserves
Total 195 acre EUR = 5.0 MMboe
Well EUR = 1.7 MMboe
RF = 32%
565 feet
283 feet
WORST CASE
Area = 195 acres
OHIP = 15.5 MMboe
65-acre well spacing
Assumed 100% acceleration of reserves
Total 195 acre EUR = 3.4 MMboe
Well EUR = 1.1 MMboe
RF = 22%
Gates Ranch - Well Spacing Illustration
13
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
14
6 Gates Ranch North wells spaced 425 to 565 feet apart (50 to 65 acres per well).
21 Gates Ranch North wells spaced roughly 850 feet apart (100 acres per well).
Note: In order to compare like well performance, the well population
chosen was all of our down-spaced wells with production history and
all of the non down-spaced wells offsetting them on the same row
where similar depths and liquids ratios exist.
chosen was all of our down-spaced wells with production history and
all of the non down-spaced wells offsetting them on the same row
where similar depths and liquids ratios exist.
Eagle Ford Well Performance
Gates Ranch down-spaced well performance plotted against offsetting non down-spaced wells
Gates Ranch down-spaced well performance plotted against offsetting non down-spaced wells
Gates Ranch Differential Well Performance
Wet Gas/Condensate Window
ROSETTA RESOURCES
Eagle Ford Production
16
¹ Net equivalent oil production
(Mboe/d) equals gross wet
wellhead gas (MMcf/d)
adjusted for shrinkage, NGL
yield, condensate yield, and
average royalty at a 6
Mcf/Bbl conversion ratio
(Mboe/d) equals gross wet
wellhead gas (MMcf/d)
adjusted for shrinkage, NGL
yield, condensate yield, and
average royalty at a 6
Mcf/Bbl conversion ratio
Eagle Ford - Firm Gas Transportation Capacity
Gross Wet
Takeaway
MMcf/d
Net Production
Mboe/d
17
Ratio Net Mboe/d1 to Gross Wet Gas MMcf/d = 0.30 (Illustrative Weighted Average)
Gates Ranch = 0.225 ratio (assume 80%)
Briscoe Ranch = 0.30 ratio (assume 10%)
Karnes Trough = 0.92 ratio (assume 10%)
Eagle Ford - Oil Marketing
Gates Ranch / Dimmit County Properties
• Plains Crude Gathering (formerly Velocity) - Gathering capacity of
25,000 Bbls/d to Gardendale Hub with up to 60,000 Bbls storage
25,000 Bbls/d to Gardendale Hub with up to 60,000 Bbls storage
• Long Term Crude Purchase Agreements
• 5,000 Bbls/d @ Gardendale, Pipeline Mid-2012
• Pricing based on Louisiana Light Sweet price less transportation
• Crude Oil Pricing Mix expected for 2012
• Gates Ranch, Briscoe Ranch and Central Dimmit County Properties
• 5,000 Bbls/d priced based on Louisiana Light Sweet (LLS) price less gravity and
transportation adjustments starting in mid-2012
transportation adjustments starting in mid-2012
• All other Condensate prices based on West Texas Intermediate (WTI) less gravity and
transportation adjustments
transportation adjustments
Karnes Trough Properties
• WTI-based price (currently with premium), currently no gravity or
transportation adjustment
transportation adjustment
• Trucking readily available
18
GROWTH CATALYSTS
19
|
Area
|
Window
|
Net
Acreage |
|
Gates Ranch
|
Liquids
|
26,500
|
|
Non-Gates Ranch
|
Liquids
|
23,500
|
|
Encinal Area
|
Dry Gas
|
15,000
|
|
TOTAL
|
|
65,000
|
Other Eagle Ford Areas
20
Discovery Well Test
• Southern Dimmit County Area
• 3,545 net acres
• 47 well locations remaining
• Initial Rate
• 850 bpd Oil
• 490 bpd NGL’s
• 3,900 mcfpd
• 1,990 BOEPD
21
Eagle Ford Well Performance
Briscoe Ranch well performance with Gates Ranch well performance and Gates Ranch average Type Curves
Briscoe Ranch well performance with Gates Ranch well performance and Gates Ranch average Type Curves
Composite Type Curve P90 (1.2 MMBOE) Composite Type Curve P50 (1.7 MMBOE)
22
Discovery Well Test
• Southern Gonzales County Area
• 1,900 net acres
• 21 well locations remaining
• Initial Rate
• 2,450 bpd Oil
• 250 bpd NGL’s
• 2,000 mcfpd
• 3,033 BOEPD
Delineation Well Test
• 1,109 bpd Oil
• 153 bpd NGL’s
• 1,200 mcfpd
• 1,463 BOEPD
Karnes Trough Area
2 rig activity ongoing and activity planned through 2013
2 rig activity ongoing and activity planned through 2013
23
Eagle Ford Inventory
+/- 800 net wells remaining
+/- 800 net wells remaining
* Denotes roughly 10,000 net acres in the liquids window of the play in Webb, LaSalle, and Gonzales counties.
24
Delineation wells
Remaining Horizontal Wells
Southern Alberta Basin
3 of 7 horizontal wells tested with 4 more scheduled in 2nd quarter
3 of 7 horizontal wells tested with 4 more scheduled in 2nd quarter
Tribal Riverbend 07-04H
q Drilled +/- 3,500’ lateral length
q Middle Bakken interval
q Tested 154 BOEPD
Fee Simonson 34-01H
q Drilled +/- 3,700’ lateral length
q Middle Bakken interval
q Tested 104 BOEPD
Tribal Riverbend 12-13H
q Drilled +/- 3,500’ lateral length
q Middle Bakken interval
q Tested 403 BOEPD
25
• Confirmed significant resource in place, 6 billion BOE
• Advanced the well science work needed to “crack code” of complex play
• Identified fracture azimuth and orientation
• Achieved good vertical growth in initial stimulations
• Identified fracture stimulation design improvements to utilize in three of four
remaining horizontal well completions
remaining horizontal well completions
• Improve isolation for more effective stimulations (cement liner and perf & plug)
• Targeted assumptions for well commerciality
• IP 250 Boe/d, EUR 185 MBOE, 160-acre spacing, $4 million well costs
• 21% ROR at $85 per barrel WTI
Next Steps
• Complete seven-well horizontal drilling program
• Maintain and high-grade acreage position
• Engage industry service providers to identify opportunities to expand infrastructure
and reduce costs in the basin
and reduce costs in the basin
• Monitor long-term production performance to confirm model
Southern Alberta Basin Key Learnings
26
FINANCIAL STRENGTH
27
|
|
|
2012 Full Year
|
||
|
|
|
(Guidance Range)
|
||
|
Direct Lease Operating Expense
|
|
$ 1.50
|
-
|
$ 1.65
|
|
Workover Expenses
|
|
0.06
|
-
|
0.07
|
|
Insurance
|
|
0.18
|
-
|
0.20
|
|
Ad valorem Tax
|
|
0.78
|
-
|
0.86
|
|
Treating and Transportation
|
|
3.78
|
-
|
4.14
|
|
Production Taxes
|
|
1.44
|
-
|
1.58
|
|
DD&A
|
|
11.10
|
-
|
11.70
|
|
G&A, excluding stock-based compensation
|
|
3.00
|
-
|
3.30
|
|
Interest Expense
|
|
1.50
|
-
|
1.65
|
Expense Guidance
28
Commodity Hedges
20
12,300
9,250
3,000
29
Debt and Liquidity
350
250
342
237
Note: As of February 24, 2012, total debt is $300 million and total liquidity is approximately $300 million.
30
• Adequate liquidity available to fund 2012 $640 million capital
program
program
• Strong cash flow in 2012
• $295 million of $325 million borrowing base available at year-end 2011
• Potential to raise borrowing base based on performance
• Recently announced Lobo and Olmos divestiture ($95 million purchase
price)
price)
• In low price environment, $250 million capital spend will
maintain 2012 production level flat versus 2011 exit rate
maintain 2012 production level flat versus 2011 exit rate
Liquidity
31
|
(MM)
|
4Q 2011
|
4Q 2010
|
|
Short-Term Debt
|
$ 20
|
$ 0
|
|
Long-Term Debt
|
230
|
350
|
|
Total Stockholder’s Equity
|
633
|
529
|
|
TOTAL
|
$883
|
$879
|
|
|
|
|
|
Capitalization
|
|
|
|
- Debt
|
28%
|
40%
|
|
- Capital
|
72%
|
60%
|
|
TOTAL
|
100%
|
100%
|
Capital Structure
32
• Asset Base High-Graded
• Divestiture program complete
• South Texas focus
• Alberta Basin option
• Strong Eagle Ford project inventory
• Executing Business Plan
• Proved reserves doubled since 12/31/10
• Gates Ranch recoveries increased
• Increased firm take-away capacity
• Strong 2012 growth and exit rates projected
• Testing Growth Catalysts
• Increased Gates Ranch well density
• Three discoveries in other Eagle Ford areas
• Complete and evaluate Alberta Basin horizontal program
• Financial Strength
• Active hedging program
• Approximately $300MM in liquidity as of February 2012
Summary
33
REDEFINED
BUILDING VALUE IN UNCONVENTIONAL RESOURCES