samson powerpoint · 2013-09-17 · snapshot significant upside potential in existing resource base...

MAY 2013

2012 2013 2014+

The Path to Future Growth

Focused on building a solid foundation for future growth and value creation

Enhanced rigor applied to capital allocation – return based approach

Cost control initiatives

Improved liquidity with Term Loan

Initiated Enterprise Resource Planning (SAP)

Divested non-core assets

New leadership

Operational excellence

Focusing on core areas

Testing new plays in core areas

Divesting non-core assets

Monitoring M&A market for acquisition opportunities

Focus on returns, growth and portfolio optimization

Transition new play testing to development

Achieve balanced commodity mix

Delever balance sheet and maintain significant financial flexibility

2

Extensive Acreage Inventory Positions

Company for Operational

Flexibility

Focus on Cash Returns

Over 90% of capex focused on drilling oil / liquids-weighted drilling projects

Maintaining ~ 50% liquids target by 2016

Implementing company wide initiatives to enhance well economics through lower cost model

Large, Diversified Asset Base

Significant operational scale in core areas – Rockies, Mid-Continent and East Texas

Extensive current drilling inventory of 4,594 identified locations provides visibility to future growth

opportunities ~82% of which are oil and liquids rich – over 1,750 additional locations in a higher natural gas

price environment

Diversified production across multiple regions – ownership interests in 7,640 gross wells (3,380 net wells)

Over 2.7 million(1) net acres concentrated in our three core areas with ~60% HBP

Diversity of the asset base and significant HBP position in several of our core areas provides flexibility

to focus on highest rate of return projects

Operate 67% of net production which allows more effective management of timing and costs

Company Highlights

Experienced Management and

Technical Team

Senior management team has extensive expertise in the oil and natural gas industry – senior

management has on average 25+ years of industry experience

Technical professionals have an average of 20+ years industry experience

Solid Financial Flexibility

As of 4/1/2013, over $1.3 billion of liquidity with access to equity for growth focused initiatives

Proactively hedge to protect cash flows and capital program

3 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres

Significant Upside Potential in Existing Resource Base Snapshot

Headquarters: Tulsa, OK

Total net acres: ~2.74 million (1)

Gross Identified Drilling Locations: 4,594

Sept 2012 Avg Daily Production

12/31/12 Reserves

616 Mmcfe/d

Large, Diverse E&P Portfolio

(1) Pro forma 2012 Bakken divestiture of 147,000 net acres

PDNP 1%

PDP 63%

PUD 36%

2,047 Bcfe

Rockies (oil, liquids & gas plays) Net acreage: ~1,180,000(1)

Targets: Ft. Union, Sussex, Shannon, Frontier, Three Forks, Middle Bakken

Permian (oil plays) Net acreage: ~115,000 (includes ~75,000 net mineral acres) Targets: Horizontal Wolfcamp, Cline Shale

Mid-Continent (liquids rich gas plays) Net acreage: ~680,000 Targets: Hogshooter, Cottage Grove, Marmaton

East Texas/ N. Louisiana (oil, liquids & gas plays) Net acreage: 450,000 Targets: Cotton Valley, Haynesville

Gas 77%

Oil 12%

NGLs 11%

4

OIL 37%

NGL 21%

GAS 42%

5

Reserve Summary

NSAI SEC Reserve Report – 12/31/2012

Oil

(MMBbl) NGL

(MMBbl) Gas (Bcf)

Total (Bcfe)

PV-10 ($MM) % Liquids

PDP 24 22 1,021 1,297 $1,874 21% PDNP 0 0 9 11 15 16% PUD 45 26 313 739 871 58% Total 69 48 1,343 2,047 $2,760 34%

OIL 20%

NGL 14% GAS 66%

PDP Reserves – by Product Total Proved Reserves – by Product PUD Reserves – by Product

2,047 Bcfe 34% Liquids

OIL 11%

NGL 10%

GAS 79%

1,308 Bcfe 21% Liquids

739 Bcfe 58% Liquids

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

NSAI 6.30.12 Production Price Variance

Drilling Acquisitions & Divestitures

(1)

LOE/Prod. Tax Changes

Proved Dev. Reserve Adds

Proved Undev.

Reserves Adds

NSAI 12.31.12 NYMEX 4/1/2013

Strip

6

Reserves Bridge - PV10 ~$1.2 billion of incremental value in current natural gas price environment

Total Proved Reserves: 6/30/2012 vs. 12/31/2012

($ in millions)

PV10 by Category

PV10 by Division

PDP 68%

PDNP 1%

PUD 31%

EAST TEXAS 20%

$2,760 MM

(1) Acquisitions of $79 million; Divestitures of $715 million

MID-CONTINENT 29%

ROCKY MOUNTAINS

51% SEC Realized Pricing: Oil: $84.72 at Dec. 31 compared to $86.23 at June 30

Gas: $2.272 at Dec. 31 compared to $2.658 at June 30

NGLs: $38.12 at Dec. 31 compared to $44.70 at June 30

($241)

$3,907

($370)

$210

$6 $44 $2,760 ($636)

($160)

$3,954

~$1.2 billion

Extensive Drilling Inventory

Net Acreage by Core Area (000s)

Gross Identified Drilling Locations by Core Area

Extensive drilling inventory provides visibility to future growth

ETX 943

Mid-Con 1,215

Rockies 2,312

Other 124

4,594 Locations

Emerging Oil and Liquids Opportunities

ETX 450

Mid-Con 684

Rockies 1,183

Other 420

2,737 Acres (1)


Targeted Play Area Commentary

Shannon Powder River Largely de-risked, planning full phase

development and infrastructure

Sussex Powder River Combination of development and testing across

multiple fields

Frontier Powder River Play already being tested/proven

Muddy Powder River Initial test wells encouraging

Middle Bakken Williston Initial stages of development

Marmaton Mid-Continent Industry results validate play

Granite Wash Mid-Continent Liquids rich gas

Cotton Valley Sands East Texas Liquids stream supports horizontal

development

Returns Focused Development Approach

Ft. Union Bakken Sussex Shannon Upper GW Hogshooter

/Cottage Grove

Cotton Valley B & C Sands

Marmaton

EURs (MBOE)

1,357 425 346 353 735 357 1,218 720

% Liquids 55% 87% 94% 91% 32% 67% 33% 42%

D&C Cost ($mm)

$13.5 $7.4 $6.5 $7.4 $6.8 $7.3 $6.5 $9.2

F&D Cost ($/Boe)

$9.95 $17.38 $18.79 $20.95 $9.25 $20.47 $5.34 $12.78

IRRs ~30% >20% >20% >20% >20% >20% ~33% >20%

Development Well Economics

8

Total Drilling &

Completions 83%

Leasehold, Geological & Geophysical

9%

Facilities 8%

Liquids-Focused Capital Budget Allocating over 90% of 2013 capital budget to oil / liquids-focused drilling projects

Plan to drill ~150 gross operated wells in 2013 Budget for 10-13 rigs operating in our core areas – Rocky Mountains, Mid-Con and East Texas

Focus areas include the Powder River Basin (2 rigs), Green River (4 rigs)(1), Bakken (2 rigs), Mid-Con (4 rigs) and East Texas (1 rig)

Capital program driven by unlevered cash flows from business – funded from operating cash flows, allowing us to maintain financial flexibility while growing existing reserves and production

ETX 13%

Mid-Con 40%

Rockies 47%

2013 Capital Budget 2013 D&C Budget by Region

Focused capital program to leverage scale in core areas, transition to greater liquids production profile and accelerate NAV

9

$758 million $628 million

(1) 2013 Plan is to operate four rigs in Green River, but drilling currently limited to August to February period each year.

Overview

Focus on oil and liquids rich properties in four major producing basins:

Powder River Basin: Stacked oil plays targeting the oil zones: Shannon, Sussex, Muddy, and Frontier

Green River Basin: Horizontal program in the Ft. Union

Williston Basin: Three Forks and Middle Bakken development

San Juan Basin: Mature dry gas asset

Rocky Mountain Operations Asset Map

Net Acreage: ~1,180,000(1)

Proved Reserves: 781.3 Bcfe

9/2012 Average Daily Production: 210 MMcfe/d

Oil 22%; NGL 6%; Gas 72%


Current Rig Count: 4


Active Rigs as of April 2013

2013 plan sets the stage for additional development drilling in 2014

Currently, Samson has 275,000 acres across the region and plans to operate two horizontal rigs this year

Shannon well results are encouraging

Plan to drill ~10 horizontal Shannon wells in 2013

Continue infill development of our Sussex program and expand Sussex core area

Plan to drill 16 horizontal Sussex wells in 2013

Mature Muddy delineation with 3 horizontal wells

Recent industry horizontal Frontier wells have EURs of 600+ MBOE – supports testing

North Tree

Hornbuckle

Scott

Spearhead Ranch

Powder River Basin

Powder River Basin Highlights Asset Map by Field

Core Position with Multiple Oil Targets

DF Nebraska (Shannon completion) Max IP 1,000+ BOEPD

Muddy HZ Test Program

11

http://www.billbarrettcorp.com/�

Chesapeake, SM Energy, Devon, Anadarko, and Helis drilling Horizontal Niobrara

EOG, Mack, Devon, and RKI drilling horizontal Parkman

EOG, Anadarko, and Devon drilling horizontal Mowry

RKI is drilling horizontal Teapot

Samson Sussex development between Spearhead Ranch and Hornbuckle

Samson Shannon development in North Tree

Samson Frontier testing near North Tree and Hornbuckle

Samson Muddy testing with 3 horizontal wells in Hornbuckle

Recent Activity Multiple Zones of Pay

Sussex:

Activity in the Sussex has increased in recent months with Bill Barrett, Chesapeake and QEP permitting and drilling wells in vicinity of Samson’s acreage

Consistent geology across core play area indicates possibility for consistent results

Shannon:

Activity in the Shannon has increased in recent months with Bill Barrett, Anadarko, and Devon permitting and drilling wells near Samson’s acreage

Recent strong results have expanded the development area of North Tree field

Frontier:

Recent horizontal Frontier wells in the area have EURs of 600+ MBOE

Recent results from Frontier wells near Hornbuckle have opened up additional inventory of horizontal locations

Current activity by other operators helping to further confirm potential (Devon, Helis, Bill Barrett, SM, etc.)

Powder River Basin Emerging Basin with Multiple Stacked Oil Targets

Stratigraphic Column

LANCE FM. FOX HILLS SS

MES

AVER

DE LEWIS SS

TEAPOT SS.

PARKMAN SS.

SUSSEX SS.

COD

Y SH

ALE

SHANNON SS. STEELE SH.

NIOBRARA SH. "CARLILE SH." WALL CR. SS.

FRONTIER FM.

MOWRY SH. SHELL CREEK SH.

MUDDY SS. THERMOPOLIS SH.

*Strat column from USGS

12

Total acreage position of 37,500 acres between Barricade and Endurance units

Identified 93 gross horizontal locations, with potential for 2 or 3 stacked laterals per location

4 horizontals wells currently producing

Plan to operate four rigs during the Aug 2013 - Feb 2014 drilling window

Plan to drill 9 horizontal wells

Drilling window limited by wildlife stipulations which restricts year round operations

Pursuing year round drilling options

Potential for significant production from field

Green River Basin – Ft. Union

Ft. Union Highlights

Liquids Rich Gas Development

Asset Map

Horizontal Wells Drilled

Barricade 14-1H First Sales 1/2012 IP Rate 14.4 MMcfd & 286 BOPD Cum Gas 2,912 MMcf Cum Oil 80 MBO

13

Sweetwater

Potential to accelerate production with third rig

Bakken – Ambrose

Bakken Highlights Asset Map: Ambrose Focus Area

Ambrose Area: ~ 75,000 acres

Currently operating two rigs

Plan to drill ~40 gross operated wells in 2013

Continued focus on cost savings through pad drilling, cycle time initiatives and optimal frac designs

Industry leading cycle times

Initial phase of the Oneok Gas Gathering System is in service

Over 730 gross identified drilling locations across our entire Bakken position

Developing Three Forks and Middle Bakken

14


4,153 gross producing wells from 25+ established productive intervals across the Anadarko, Arkoma and Ardmore basins

Current focus areas include:

Hogshooter / Cottage Grove Wash: Samson has drilled and completed several Hogshooter and Cottage Grove Wash wells with results exceeding 50% IRR’s on a program basis. Currently operating two rigs in the play

Upper Granite Wash: Drive efficiencies through multi-well pad development to increase IRR’s

Marmaton: Currently drilling several Marmaton wells adjacent to industry activity

Mississippi Lime: Completed first two Mississippi Lime wells which exceeded expectations. Samson will further delineate this play and expects future activity in this play along with other oil plays across the Mid- Continent Division

Mid-Continent Operations

Overview Asset Map

Net Acreage: ~684,000



Oil 12%; NGL 19%; Gas 69%



15


Davis 65-21H (GW Purple) IP24: 11.5 MMcfd, 550 BOPD

16

Anadarko Shelf Team

Huff 32-8H Hogshooter IP 24: 5.0 MMcfd, 2,700 BOPD

2012 Key Wells

Approximately 70,000 net acres in Roberts, Hemphill, and Wheeler Counties

90% of the acreage HPB

Continuous 2 rig drilling program with plans for additional rigs starting in 2014

Upper Granite Wash, Hogshooter and Cottage Grove Oil and Liquid Rich Gas Plays

Drill stacked laterals from multi-well pads in Upper Granite Wash Pay of the Buffalo Wallow Field

3 to 4 wells per pad Reduce well cost ~ 10% Expand play to other Granite Wash

Expand Hogshooter / Cottage Grove play to newly acquired acreage closer to the mountain front

Test and delineate a Pennsylvanian Douglas Horizontal Play on existing HBP Acreage

Samson Rigs

2013 Activity

Overview

Active Rigs

Balanced approach of acreage optimization, cost initiatives and exploration creates a visible runway

Davis 64 Cottage Grove and Hogshooter 64-5H IP 24: 7.0 MMcfd + 2,300 BOPD

64-9H IP 24: 2.6 MMcfd + 1,900 BOPD 64-10H IP 24: 2.7 MMcfd + 2,000 BOPD

Asset Map

17

Horizontal Oil Play

Operate 2 rigs through 2013 drilling Marmaton horizontals

Legacy acreage position provides broad exposure to stacked pay across the region

Identified numerous horizontal oil drilling opportunities including: Tonkawa, Cleveland, Marmaton and Mississippian target horizons

Recent drilling results include two horizontal Cleveland wells that had an average 30-day IP of 1,250 boepd Samson Rigs

Active Rigs

Chesapeake Roark Trust 1-14H IP30: 2,765 BOEPD

Samson Maxon 2-13H Currently completing

Apache Skyy 2-33H EUR 209 MBO 5.2 BCF

Apache Galileo 2-4H EUR 128 MBO 3.7 BCF

Apache Screaming Eagle 1-16H EUR 160 MBO 2.3 BCF

2013 Planned Drilling

Overview Asset Map - Marmaton Activity

Continue optimizing HBP acreage by drilling horizontal oil targets – Expand adjacent leasehold to core up position

East Texas Operations

Liquids-rich and dry gas producing properties in East Texas and North Louisiana with focus on Liquids-rich gas drilling

Cotton Valley: Liquids-rich horizontal play – encouraging well results support continued development

Haynesville/Bossier: No activity currently, 75,000 net acres high graded and HBP

~750 identified locations

Overview Asset Map – E TX / NW LA

Net Acreage: ~450,000



Oil 3%; NGL 8%; Gas 89%

Gross Identified Drilling Locations: 943


18

Active Rigs as of April 2013 Adding second rig May 2013

Formation Gross Identified

Locations Avg EUR

Avg CWC ($mm)

Avg WI/NRI

CV A Sand Currently Testing Currently Testing $5.9 57%/43%

CV B Sand 21 5.9 Bcf & 44 MBO $6.5 57%/43%

CV C Sand 20 5.4 Bcf & 66 MBO $6.4 60%/47%

CV Taylor 71 4.2 Bcf & 15 MBO $7.7 94%/75%

East Texas – Cotton Valley Liquids-rich Stacked Lateral Development

Crnko Biggs Unit Recently completed 3 well pad. IP

30: 6 MMcfd Liquids Rich Gas & 110 BOPD

$5.7MM Avg CWC

Cotton Valley Highlights

Plan to operate one rig throughout 2013, adding a second rig in May 2013

Plan to drill ~ 20 CV Horizontal wells in 2013

Primary targets include B and C Sands

Testing A Sand potential

Focused on cost efficiencies

Multi-well pads; currently drilling a 4-well pad (exploring potential to expand to 6-well pads)

Zipper Fracs

Drilling stacked laterals

Bi-fuel rigs capable of using natural gas and diesel

Currently 24 Horizontal CV wells producing

Apply Southeast Carthage Field successes to CV Taylor program to drive down costs and improve economics

Focus Area - Southeast Carthage Field

Drilling Inventory

Knight Strong Recent IP 24 :

5.6 MMcfd Liquids Rich Gas and 124 BOPD

19

Cost control has led redevelopment of legacy asset

Focused on Returns Across Portfolio

Lease Operating Expense

Initiatives

Field driven, comprehensive

reviews of controllable spend areas

Over 90 identified savings opportunities

Examples:

1. SWD Costs

2. Compression

3. Chemicals

Early Results:

SWD Hauling down 10%-20%

Chemical Cost Reductions:

40% NLA & 26% in MidCon

Cost Reduction Initiatives Focused on LOE and Identified D&C Components

Supply Chain Management

Initiatives

1. Contract management of key drilling and completion products and services such as:

- Stimulation

- Cementing

- Mud & Services

2. Increase visibility across all spend

3. Expand and audit price agreements

4. Standardize equipment

5. Contractor performance management

Estimate $20MM-$40MM

in annual savings

Driving costs down in 2013 through excellence in execution and process improvements

20

Financial Strategy

Committed to a Strong and Stable Capitalization Profile

Target long-term leverage of 3.5x or below while maintaining financial flexibility to execute on capital plan objectives

Focus on maintaining solid liquidity position – ~$1.3 billion as of 4/1/13

No near-term maturities – helps mitigate liquidity risk

Capital Spending Decisions Driven by Risked Discounted Cash Flow

Minimum of 20% IRR required for all capital projects

Project level cash flow generation and sale of non-core assets will significantly fund development programs

Continue to Improve Operating Margins by Deploying Capital to Highest Return Opportunities

Over 90% of the 2013 drilling budget dedicated to oil / liquids-rich projects

Actively manage acreage positions

Hedging Strategy Focused on De-Risking Price for Substantial Portion of the Forecasted Production

Target 50% to 75% of rolling 18 to 24 month production

Maintain a diversified group of hedge counterparties

Opportunistically hedge in times of dislocation for longer periods

21

Financial Position

Capitalization (1) (as of 9/30/2012)

Debt Maturity Profile and Liquidity ($mm)

(1) As adjusted for 2012 Bakken Divestiture (2) Revolver borrowings and availability as of 4/1/2013 (inclusive of outstanding letters of credit) (3) Book Value of cumulative preferred stock with an aggregate liquidation preference of $182.8 million

Sufficient liquidity – No near-term maturities

22

(2)

$431 $1,349

$1,000

$2,250

$0 $500 $1,000 $1,500 $2,000 $2,500

2016

2017

2018

2019

2020

Revolver - Borrowings Revolver - Availability

Second Lien Senior Notes

(3)

($ in millions)

Capitalization 9/30/2012 % of Cap

Reserved Based Credit Facility $365 4.9%

Second Lien Term Loan 1,000 13.4%

Total Secured Debt $1,365 18.3%

9.75% Senior Notes $2,250 30.1%

Preferred Stock 171 2.3%

Total Debt $3,786 50.7%

Shareholders' Equity 3,683 49.3%

Total Capitalization $7,470 100.0%

Hedge To Protect Cash Flow As of March 28, 2013:

Hedged ~83% of forecasted 2013 volumes

Year MMBtu/day Swap Price

% of Forecast

2013 341,000 $3.76 82%

2014 309,000 $4.15

2015 92,000 $4.09

2016 86,000 $4.08

2017 40,000 $3.92

Year BOPD Swap Price % of

Forecast

2013 16,425 $92.45 99%

2014 16,500 $90.80

2015 3,500 $91.32

Year Bbls/day Swap Price % of

Forecast

2013 7,485 $36.05 60%

Gas Swaps Oil Swaps NGL Swaps

23

Key Takeaways

Execution across the Company is the focus for 2013 and beyond

Transition the production profile and asset base to a more balanced mix of oil / liquids and natural gas

Realize value of Rockies assets by delineating acreage position, demonstrating repeatable EURs, and driving down costs

Enhance returns from Mid-Con and East Texas programs through operational improvements

Optimize present value of assets through active portfolio management

Commitment to reducing leverage and maintaining / enhancing financial flexibility

24

This presentation contains forward-looking statements, which reflect our expectations regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, “anticipate,” “continue,” “estimate,” “expect,” “may,” “might,” “will,” “project,” “should,” “believe,” “intend,” “continue,” “could,” “plan,” “predict” and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this presentation are forward-looking statements. These statements are based on, but not limited to, management’s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate. All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this presentation reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results. Factors that may cause actual results to differ from expected results include, among others: fluctuations in natural gas and oil prices; uncertainties relating to the drilling of our wells; estimates of our reserves, future net revenues and PV-10; the timing and amount of future production of natural gas and oil; our financial strategy, liquidity and capital required for our development program; changes in the availability and cost of capital; proved and unproved drilling locations and future drilling plans; production rates relating to our natural gas and oil reserves; our ability to capitalize on opportunistic acquisitions of natural gas and oil reserves; write-downs and decline in value of undeveloped acreage if drilling results are unsuccessful; recording of certain non-cash asset write-downs in the future; liability claims as a result of our natural gas and oil operations; actions taken or non-performance by third parties, including other working interest owners, contractors, operators, processors, transporters and customers; competitive conditions in our industry; the use and development of new industry technologies; our ability to recruit and retain qualified personnel necessary to operate our business; our ability to consummate and successfully integrate acquisitions and our ability to realize any cost savings and other synergies from any acquisition; the performance of our information technology systems; general economic and business conditions; our hedging strategy and results; the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; the effects of derivatives reform legislation; elimination of certain natural gas and oil exploration and development federal and state tax deductions and credits; compliance with existing and future FERC regulation; the effects of existing or future litigation; and plans, objectives, expectations and intentions contained in this presentation that are not historical.

Forward Looking Statements

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital and the timing of development expenditures. Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation.

samson powerpoint · 2013-09-17 · snapshot significant upside potential in existing resource base...

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