2013 CREDIT SUISSE ENERGY SUMMIT - Bill Barrett Corporation
2013 CREDIT SUISSE ENERGY SUMMIT - Bill Barrett Corporation
2013 CREDIT SUISSE ENERGY SUMMIT - Bill Barrett Corporation
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<strong>2013</strong> <strong>CREDIT</strong> <strong>SUISSE</strong> <strong>ENERGY</strong> <strong>SUMMIT</strong><br />
FEBRUARY <strong>2013</strong>
Forward-Looking & Other Cautionary Statements<br />
Please reference the last two pages of this presentation for important<br />
disclosures on:<br />
• Forward-looking statements<br />
• NGL Calculations<br />
• Non-GAAP measures<br />
• Reserves<br />
• Risked Resources<br />
Current production represents 4Q12<br />
2
Who We Are<br />
Growth & profit oriented E & P company focused in the Rocky Mountain region<br />
• $750MM market capitalization<br />
$1.9B enterprise value<br />
• Proved reserves 1.04 Tcfe 2012<br />
• 75% reserve growth in active oil programs<br />
• 29% oil<br />
• January <strong>2013</strong> projected production:<br />
• Daily net production 220 MMcfe<br />
• 70% gas<br />
• 22% oil<br />
• 8% NGLs<br />
• Large, low-risk drilling inventory<br />
• Competitive advantage in Rocky<br />
Mountain Region<br />
• Excellent liquidity<br />
Oil Producing Area<br />
Gas Producing Area<br />
BBG Oil Development<br />
BBG Gas Development<br />
BBG NGLs Development<br />
BBG Oil Exploration<br />
3
Why Invest in <strong>Bill</strong> <strong>Barrett</strong> <strong>Corporation</strong>?<br />
Excellent people, long-term profitable growth, quality assets, upside potential<br />
• Successfully transitioning to higher oil-weighted production profile and resource<br />
base<br />
• 2012 oil production increased 80%<br />
• 2012 proved oil reserves increased 66%<br />
• Low-risk, visible growth from 2 core development assets<br />
• Year-over-year exit rate oil production growth of 90% in the Uinta Oil Program*<br />
• Year-over-year exit rate oil production growth of 320% in the DJ Basin*<br />
• Optionality: large undeveloped natural gas resource inventory<br />
• Financial strength and flexibility<br />
• Management expertise and experience in region<br />
*Exit rate production growth calculated as percent difference between Q412 and Q411 oil production<br />
4
<strong>2013</strong> Guidance and Strategy<br />
Deliver competitive growth and returns from core oil development programs<br />
• 50-55% pro forma growth in year-over-year oil production<br />
• 30% of total production to be oil (3 stream basis)<br />
• Total production: 83-87 Bcfe (2 streams); 86-90 Bcfe (3 streams)<br />
• 4 rig program in the Uinta Oil Program; 2 rig program in the DJ Basin<br />
• NGLs expected to be 6-8% of production assuming full-year ethane rejection<br />
• At least 5 low-risk development wells in the Powder River Basin Deep oil program<br />
Large cut to capital expenditures<br />
• Total capital expenditures of $475-$525 million<br />
• Reduction of more than $400 million from 2012 level<br />
• Financed through discretionary cash flow and further non-core asset sales<br />
• Committed to maintaining total debt at current level<br />
5
<strong>2013</strong> Capital Expenditure Breakdown<br />
• $475-$525MM capital program<br />
• ~95% focused on oil development properties<br />
• ~50% reduction in capex from 2012 level<br />
<strong>2013</strong> % Capex by Area<br />
8%<br />
5%<br />
40%<br />
47%<br />
UOP<br />
DJ Basin<br />
Powder River<br />
Other<br />
6
Oil Growth: Successfully Rebalancing Portfolio<br />
Big Growth in Oil<br />
% of Production<br />
<strong>2013</strong>e<br />
Proved Oil Reserves (MMBbls)<br />
94%<br />
31.0<br />
50.0<br />
30%<br />
7.6<br />
13.0<br />
<strong>2013</strong><br />
Oil Gross Risked<br />
Resource Locations<br />
70%<br />
2008<br />
5%<br />
2009 2010 2011 2012<br />
35+%<br />
Oil Production (MMBbls)<br />
RUN OIL<br />
ONLY<br />
2.7<br />
4.0-4.2<br />
107<br />
1,082<br />
1,696<br />
UOP DJ Basin Powder River<br />
95%<br />
1.5<br />
1.1<br />
0.7<br />
2009 2010 2011 2012 <strong>2013</strong>e<br />
Oil<br />
Gas<br />
%<br />
Revenue<br />
6% 11% 15% 30% 55%<br />
7
Bbls/d<br />
Oil Production Growth<br />
10,000<br />
Oil Production by Region (Bbls/d)<br />
9,000<br />
8,000<br />
7,000<br />
6,000<br />
5,000<br />
4,000<br />
3,000<br />
2,000<br />
1,000<br />
0<br />
1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12<br />
Uinta Oil Program DJ Basin Other*<br />
*Other includes: Piceance, Powder River, West Tavaputs, Wind River, and Paradox Basins<br />
8
Quality Assets: Low-risk, Long-term Growth<br />
Capital program focused on liquids with 6 rigs targeting oil<br />
• 10% increase in pro forma risked resources<br />
• 40% increase in oil locations<br />
Proved<br />
Total Risked Resources (2012)<br />
Proved<br />
Bcfe<br />
Proved +<br />
Risked Gross<br />
Resouces Drilling<br />
Bcfe Locations<br />
Uinta Oil<br />
Program (oil)<br />
282 967 1,696<br />
West Tavaputs,<br />
Uinta 1<br />
265 885 588<br />
Denver Julesburg<br />
(oil/NGLs)<br />
75 532 1,082*<br />
Gibson Gulch,<br />
Piceance 1 (NGLs)<br />
401 511 528<br />
Powder River<br />
Deep<br />
21 40 107<br />
0 200 400 600 800 1,000 1,200<br />
Bcfe<br />
*DJ risked resources included between 3-8 wells per section<br />
across the majority of Northeast Wattenberg, Core Wattenberg<br />
and Chalk Bluffs acreage positions<br />
TOTAL 1,044 2,935 4,001<br />
PERCENT OIL 29% 40%<br />
9
Financial Strength & Flexibility<br />
Strong balance sheet offers substantial liquidity<br />
• Liquidity: $825 million borrowing base with $0 drawn (as of 12/31/12)<br />
• Debt metrics: In line with peers, debt/EBITDAX 2.4X (as of 12/31/12)<br />
• Committed to keep debt levels flat at YE <strong>2013</strong><br />
• Hedging to reduce volatility and support cash flow for capital program<br />
• 60-65% of <strong>2013</strong> oil production hedged at $98.00/Bbl<br />
• ~75% of <strong>2013</strong> natural gas production hedged at $3.70/MMcf<br />
Monetizing lower-growth assets for financial strength<br />
• $335 million sale of natural gas assets closed December 31, 2012<br />
• Excellent Business Decision<br />
• Sold lower growth/lower return assets to reinvest in oil development inventory<br />
• Places market value of Gibson Gulch at ~$1 <strong>Bill</strong>ion, or 7.8x operating cash flow<br />
• Proceeds applied to pay down credit line and to fund <strong>2013</strong> capital expenditures<br />
• Continue portfolio management in <strong>2013</strong><br />
10
Volume (Bcfe)<br />
Price($/Mcfe)<br />
Hedging Provides Price Predictability<br />
• Solid hedge position for <strong>2013</strong><br />
• Opportunistically add to positions over time<br />
• <strong>2013</strong> hedges: ~46 Bcf of natural gas production, ~2,550 Mbbls of oil production and<br />
~320 Mbbls of NGLs<br />
• 2014 hedges: ~25 Bcf of natural gas production and ~1,168 Mbbls of oil production<br />
<strong>2013</strong>: 62.5 Bcfe at $7.38/Mcfe<br />
2014: 31.9 Bcfe at $6.81/Mcfe<br />
Floor/Swap<br />
25<br />
Volume (Bcfe)<br />
Price ($/Mcfe)<br />
$8<br />
20<br />
$7<br />
15<br />
10<br />
5<br />
$6<br />
$5<br />
0<br />
1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14<br />
$4<br />
Notes: As of January 25, <strong>2013</strong>. Average swap price is for illustrative purposes only and does not represent formal guidance.<br />
11
PROPERTY DESCRIPTIONS:<br />
TWO CORE OIL PROGRAMS
2 Core Oil Development Programs<br />
Uinta Oil Program, Uinta Basin<br />
• 2012 year-end reserves: 47 MMBoe<br />
• Year-over-year exit rate oil production<br />
growth: 90%<br />
• Added 23,685 net acres in 2012<br />
• 1,696 gross locations (year-end 2012)<br />
• Significant upside potential through<br />
expanded acreage position,<br />
downspacing and increased<br />
recoveries<br />
DJ Basin, Northeast Wattenberg Focus<br />
• 2012 year-end reserves:12.5 MMBoe<br />
• Year-over-year exit rate oil production<br />
growth: 320%<br />
• Added 34,314 net acres in 2012<br />
• 1,082 gross locations (year-end 2012)<br />
• Significant upside potential through<br />
expanded acreage position,<br />
downspacing, larger laterals and<br />
increased operating efficiencies<br />
Rapidly building these scalable programs to<br />
deliver growth in production and cash flow<br />
13
Premier Assets Based on IRR’s<br />
60%<br />
Basin IRR’s – Futures strip of 1/28/13<br />
30%<br />
56%<br />
54%<br />
53%<br />
51%<br />
44% 43%<br />
37% 36% 36% 35% 34%<br />
31% 31%<br />
28%<br />
26%<br />
23% 22% 22% 21%<br />
19%<br />
18% 18%<br />
17%<br />
16% 16%<br />
13% 12% 12%<br />
9% 9%<br />
50%<br />
40%<br />
20%<br />
10%<br />
6% 5%<br />
0%<br />
*Source: Credit Suisse Exploration and Production – 2/1/13<br />
14
Per bbl<br />
Low-cost Operations<br />
$120<br />
Oil Price to Generate 25% IRR<br />
$100<br />
$80<br />
$60<br />
$60.21<br />
$66.16<br />
$40<br />
$20<br />
$0<br />
Niobrara -<br />
Wattenberg<br />
Extension<br />
Niobrara -<br />
Wattenberg<br />
*Source: Industry data, Global Hunter Securities<br />
15
DJ Basin<br />
Built sizable position since July 2011, 2 rig program in <strong>2013</strong><br />
Niobrara Formation<br />
3,000<br />
2,500<br />
Net Production (Boe/d)<br />
2,570<br />
Silo<br />
Field<br />
Chalk Bluffs<br />
2,000<br />
1,500<br />
1,000<br />
500<br />
Hereford Area<br />
Northeast<br />
Wattenberg<br />
0<br />
3Q11 4Q11 1Q12 2Q12 3Q12 4Q12<br />
• Northeast Wattenberg: 39,730 net acres<br />
• Wattenberg interior: 13,560 net acres<br />
• Chalk Bluffs and Wyoming border region: 22,995 net<br />
acres<br />
• Proved reserves: 12.5 MMBoe; up 80+% (as of<br />
12/31/12)<br />
• Increasing efficiencies – initiated pad drilling<br />
• 3 four-well pads drilled<br />
• 24-hour peak IP rates for 3 pads: 712/764/750 Boe/d per well<br />
• 30-day average IP rates for 3 pads: 407/472/358 Boe/d per well<br />
DJ Basin<br />
BBG Acreage<br />
Gas Production<br />
Oil Production<br />
Wattenberg<br />
Field<br />
50 miles<br />
Core Wattenberg Development<br />
Chalk Bluffs & Exploration<br />
Northeast Wattenberg<br />
16
DJ Basin: Northeast Wattenberg<br />
Strong and repeatable well results in the area<br />
• Northeast Wattenberg Upside:<br />
• Increased density: 80-acre and 40-acre<br />
horizontal downspacing being tested<br />
• ‘C’ Bench development<br />
• Codell development<br />
• Extended laterals<br />
• Pad development to increase cost efficiencies<br />
• Improved drilling and completion techniques<br />
offer increased EURs and lower cost<br />
• Strong results from peer offset wells<br />
demonstrates acreage quality<br />
• 4 peer wells follow ~300 MBoe EUR type<br />
curve<br />
• 1 extended reach lateral following 750+MBoe<br />
type curve<br />
Greeley<br />
Wattenberg<br />
Field<br />
BBG Acreage<br />
Gas Production<br />
Northeast Wattenberg<br />
Niobrara Formation<br />
6 miles<br />
DJ Basin<br />
Oil Production<br />
BBG Rig<br />
Peer Offset Oil Wells<br />
(NBL, BCEI)<br />
17
Cumulative BOE<br />
NE Wattenberg Performance<br />
Results follow 300 MBoe type curve<br />
• 12 successful wells on 3 4-well pads<br />
• Located in western portion of NE Wattenberg<br />
• Only 2 of 12 wells on artificial lift<br />
• Smaller frac stimulations<br />
= 300 Mboe type curve<br />
= BBG Wells<br />
18
DJ Basin Infrastructure<br />
Infrastructure additions to double capacity by 2015<br />
• DCP Midstream<br />
• Mewborn expansion of 35 MMcf/d in 2012<br />
• LaSalle Plant with maximum capacity of 160 MMcf/d expected in 2H13<br />
• Lucerne II Plant with maximum capacity of 230 MMcf/d in 2H14<br />
• NGL Pipeline expected in 4Q13<br />
• 230 Mbbls/d to connect to Texas Express Mainline and MAPL<br />
• Provide access to Gulf Coast markets (Mt Belvieu)<br />
• Western Gas Lancaster Plant<br />
• Estimated start-up 1Q14<br />
• 300 MMcf/d capacity<br />
19
Uinta Oil Program: Driving Substantial Oil Growth<br />
Expanded acreage, 4 rigs operating in <strong>2013</strong><br />
• Significant land position:<br />
• 120,800 net undeveloped acres<br />
• Prolific Wasatch-Green River targets<br />
• Rapid growth: production 6,920 Boe/d<br />
(4Q12)<br />
• 1P reserves up 60+% to 47 MMBoe<br />
• Proved + risked resources up 20+% to 161<br />
MMBoe<br />
• Proved + Risked gross locations increased to<br />
1,696<br />
• Increasing efficiencies:<br />
• 2012 doubled our activity<br />
• Most recent 6 months have shown $600-$700K<br />
improvement in overall costs (mostly completion)<br />
vs. the previous 18 months<br />
• Upside opportunities:<br />
• Spud first 80 acre pilot<br />
• Blacktail Ridge stepouts encouraging and eastern<br />
acreage demonstrating strong well results<br />
Blacktail Ridge<br />
Altamont/Bluebell<br />
Cum: 312 MMBo/539 Bcf<br />
Roosevelt<br />
Lake<br />
Canyon<br />
10 Miles<br />
Wasatch, Green River Formations<br />
South Altamont<br />
Monument<br />
Butte<br />
Cum: 72 MMBo<br />
/244 Bcf<br />
BBG Acreage<br />
BBG Rig<br />
East Bluebell<br />
Natural Buttes<br />
Cum: 2.3 Tcf<br />
/18 MMBo<br />
Gas Production<br />
Oil Production<br />
N<br />
*Gross operated wells<br />
20
Wasatch Green River<br />
Uinta Oil Program: Significant Upside<br />
Multiple Horizons<br />
• Vertical drilling needed to produce oil<br />
from stacked, discontinuous zones<br />
over 3-4,000’<br />
• Historical recoveries of 4-6% per<br />
section<br />
Carbonate<br />
• Increased density one step to<br />
maximizing recovery:<br />
• 160 acre infill established<br />
• 80 acre pilots spud<br />
21
Uinta Oil Program: Marketing<br />
Refining capacity in basin is increasing; confident we can sell our growing production<br />
• Current agreement<br />
• 7,500 Bbl/d through 2018<br />
• Typical 16-18% price deduct from WTI<br />
• Oil refined in Salt Lake City<br />
• Salt Lake City Refining<br />
• 5 refineries have an estimated 173,000 Bbl/d total capacity; approximately 52,000 Bbl/d wax capacity<br />
• New Holly Frontier refined products pipeline to Las Vegas<br />
• Increased capacity alternatives<br />
• Additional wax expansion at existing refineries<br />
• Proposed upgrader with 44,000 Bbl/d initial wax crude processing capacity<br />
• Rail expansion initiatives developing<br />
• Currently negotiating with multiple parties to secure additional long-term capacity<br />
22
Powder River Deep<br />
Stacked oil play providing early positive test results<br />
• 155,950 gross and 66,865 net acres<br />
• Horizontal Shannon well<br />
• 24 hour peak rate: 523 Boe/d<br />
• 30-day average rate: 429 Boe/d<br />
• On pump: recent 600 Boe/d<br />
• Horizontal Sussex well<br />
• 24 hour peak rate: 584 Boe/d<br />
• 30-day average rate: 427 Boe/d<br />
• ~10,000 feet vertical depth; 4,100 foot<br />
lateral; 17 frac stages<br />
• Two additional horizontal Frontier<br />
wells and one horizontal Shannon well<br />
in various stages of completition<br />
23
APPENDIX
Piceance Basin: Gibson Gulch<br />
Significant NGL Exposure<br />
• High liquids content increases<br />
revenue<br />
• NGLs will be reported as separate<br />
production in <strong>2013</strong><br />
• Proved reserves: 400 Bcfe<br />
Silt<br />
Cottonwood<br />
Gulch<br />
Williams Fork Formation<br />
3-Component<br />
3-D Seismic<br />
N<br />
N<br />
• Proved + risked resources: 510<br />
Bcfe<br />
• Gross locations: 528<br />
Mamm Creek<br />
Silt<br />
Gibson<br />
Gulch<br />
• Net production: 133 MMcfe/d<br />
(4Q12) (pre-asset sale)<br />
6 Miles<br />
BBG Acreage<br />
Gas/NGL Production<br />
• <strong>2013</strong>: no drilling activity planned<br />
• 4Q12 sale of 18% working interest<br />
progressing to 26% in 2016<br />
• Implies $700-$800 million value for<br />
remaining holding<br />
25
UBFS pipeline<br />
Uinta Basin: West Tavaputs<br />
• Proved reserves: 265 Bcfe<br />
Shallow – Wasatch, North Horn, Price River<br />
• Proved + risked resources:<br />
885 Bcfe<br />
West Tavaputs<br />
Development Area<br />
N<br />
• Gross locations: 588<br />
• Net production: 77 MMcfe/d<br />
(4Q12)<br />
• <strong>2013</strong>: no drilling activity<br />
planned<br />
Prickly<br />
Pear<br />
Peter’s<br />
Point<br />
Hornfrog<br />
8-9-13-18<br />
Hornfrog<br />
Drill-to-Earn<br />
Area<br />
Mancos<br />
Producers<br />
Hornfrog<br />
10-15-13-18<br />
1.5 Bcf Cum<br />
from North Horn<br />
Upside Potential:<br />
6 Miles<br />
BBG Acreage<br />
Gas Production<br />
Gas Well<br />
• Identified cost reductions<br />
• Mancos/Niobrara<br />
Shale Gas<br />
• Deep horizons<br />
26
Total Debt<br />
($ in millions)<br />
12/31/2012<br />
Revolving Credit Facility due 2016 -<br />
Borrowing Base $825<br />
5.000% Convertible Notes due 2028 (March 2015 Put) 25<br />
9.875% Senior Notes due 2016 250<br />
7.625% Senior Notes due 2019 400<br />
7.000% Senior Notes due 2022 400<br />
Lease Financing Obligation 98<br />
Total Debt $1,173<br />
27
in millions<br />
Manageable Debt Levels<br />
• Well-spaced debt maturities<br />
• Completed $101 million lease financing agreement of BBG owned facilities at 3.5%<br />
• $335 million sale of natural gas assets finalized December 31, 2012<br />
• Bank credit facility with $825 million of commitments, $0 drawn at year-end<br />
$450<br />
$400<br />
$350<br />
$300<br />
$250<br />
$200<br />
$150<br />
$100<br />
$50<br />
$-<br />
Debt Maturity Schedule<br />
Remaining<br />
5.000%<br />
Convert<br />
9.875%<br />
Lease<br />
Financing<br />
EBO<br />
7.625%<br />
7.000%<br />
2012 <strong>2013</strong> 2014 2015 2016 2017 2018 2019 2020 2021 2022<br />
28
Credit Metrics Modest Compared to Peers<br />
Debt TTM EBITDAX<br />
1.2x<br />
2.4x 2.6x 2.8x<br />
3.5X<br />
3.7X<br />
3.8X<br />
0.9x<br />
1.7x<br />
2.7x<br />
Credit<br />
rating<br />
SM PVA BRY PXP FST XCO CRK BBG 2010 BBG 2011 2012 Q3<br />
Ba3 /<br />
B2/<br />
Ba3 /<br />
Ba3/<br />
B1 /<br />
B1/<br />
B2/<br />
BB<br />
B<br />
BB-<br />
BB<br />
B+<br />
B<br />
B<br />
$2,010<br />
$3,486<br />
$4,582<br />
$5,403<br />
$5,426<br />
$6,693<br />
$7,612<br />
$1,600<br />
$3,050<br />
$4,095 $4,913<br />
Debt / PD Reserves ($/Mcfe)<br />
$1.38 $1.40<br />
Debt Avg Daily Production ($/Mcfe) $2.90<br />
Credit<br />
rating<br />
SM XCO CRK FST PVA PXP BRY BBG 2010 BBG 2011 2012 Q3<br />
Ba3 /<br />
BB<br />
B1/<br />
B<br />
B2 /<br />
B<br />
B1/<br />
B+<br />
B2 /<br />
B<br />
Ba3 /<br />
BB<br />
Ba3 /<br />
BB-<br />
$1.74 $1.85 $1.89 $2.08<br />
$0.80<br />
$1.28<br />
N/A<br />
Credit<br />
rating<br />
SM PVA FST BRY XCO CRK PXP BBG 2010 BBG 2011 2012 Q3<br />
Ba3 /<br />
BB<br />
B2 /<br />
B<br />
B1 /<br />
B+<br />
Ba3/<br />
BB-<br />
B1 /<br />
B<br />
B2 /<br />
B<br />
Ba3/<br />
BB<br />
Source: Q3 2012 10Q & BAML High Yield Energy Weekly (November 26, 2012)<br />
BBG rating: Ba3/BB-<br />
29
Natural Gas and Oil Hedges: Equivalents<br />
As of January 25, <strong>2013</strong><br />
Swaps & Collars<br />
Period Natural Gas NGLs* Oil<br />
Volume<br />
(MMBtu/d)<br />
Price<br />
($MMBtu)<br />
Volume<br />
Gallons<br />
(000s)<br />
Price<br />
($/Gal)<br />
Volume<br />
(Bopd)<br />
Price<br />
($/Bbl)<br />
1Q13 150,000 $3.69 3,375 $1.78 7,000 $98.00<br />
2Q13 140,000 $3.70 3,375 $1.78 7,000 $98.00<br />
3Q13 140,000 $3.70 3,375 $1.78 7,000 $98.00<br />
4Q13 123,400 $3.72 3,375 $1.78 7,000 $98.00<br />
1Q14 75,000 $3.83 3,200 $96.17<br />
2Q14 75,000 $3.83 3,200 $96.17<br />
3Q14 75,000 $3.83 3,200 $96.17<br />
4Q14 75,000 $3.83 3,200 $96.17<br />
Notes: As of January 25, <strong>2013</strong>. Average swap price is for illustrative purposes only and does not represent formal guidance.<br />
*NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged.<br />
30
Additional Swap/Collar Data<br />
As of January 25, <strong>2013</strong><br />
Natural Gas<br />
Oil<br />
Period<br />
Swaps<br />
Period<br />
Swaps<br />
Volume<br />
(BBtu/d)<br />
Price<br />
($/MMBtu)<br />
Volume<br />
(Bbl/d)<br />
Price<br />
($/Bbl)<br />
1Q13 150.0 $3.69<br />
2Q13 140.0 $3.70<br />
3Q13 140.0 $3.70<br />
4Q13 123.4 $3.72<br />
1Q14 75.0 $3.83<br />
2Q14 75.0 $3.83<br />
3Q14 75.0 $3.83<br />
4Q14 75.0 $3.83<br />
1Q13 7,000 $98.00<br />
2Q13 7,000 $98.00<br />
3Q13 7,000 $98.00<br />
4Q13 7,000 $98.00<br />
1Q14 3,200 $96.17<br />
2Q14 3,200 $96.17<br />
3Q14 3,200 $96.17<br />
4Q14 3,200 $96.17<br />
NGL<br />
Calendar Year <strong>2013</strong><br />
Volume<br />
(gal/month)<br />
Swaps<br />
Price<br />
($/MMBtu)<br />
Ethane - -<br />
Propane 250,000 $1.33<br />
Isobutane 250,000 $1.73<br />
Normal Butane 250,000 $1.64<br />
Natural Gasoline 250,000 $2.21<br />
No NGL hedges in place for 2014<br />
Notes: As of January 25, <strong>2013</strong>. Average floor/swap price is for illustrative purposes only and does not represent formal guidance.<br />
31
Land Summary<br />
As of year-end 2012<br />
Area<br />
Gross Acreage<br />
Net Undeveloped<br />
Acreage<br />
Average Gross<br />
Project NRI<br />
Average BBG<br />
Working Interest<br />
Development Properties<br />
Piceance – Gibson Gulch 17,725 3,815 81% 96%<br />
Uinta – West Tavaputs 40,685 19,905 83% 97%<br />
Uinta Basin – Uinta Oil Program<br />
Blacktail Ridge/Lake Canyon 134,020 31,495 82% 51%<br />
Minimum to be earned 131,595 54,275 82% 51%<br />
East Bluebell & Other 80,325 35,030 83% 60%-65%<br />
Total Uinta Oil Program 345,940 120,800<br />
DJ Basin – Wattenberg Core 17,575 2,250 1 84% 97%-100%<br />
Extension Properties<br />
Piceance Basin – Cottonwood Gulch 2 40,310 36,280 88% 90%<br />
Uinta Basin – Hornfrog (including to-be-earned) 30,585 16,120 85% 55%<br />
DJ Basin – Northeast Wattenberg 72,220 31,595 81% Varies<br />
Exploration Properties<br />
DJ – Chalk Bluffs and other 36,335 17,040 83% Varies<br />
DJ – Sage Brush 81,425 35,695 83% 44%<br />
Paradox Basin – Yellow Jacket 388,770 290,235 83% 100%<br />
Powder River Basin – Deep 155,950 54,580 80% 10%-65%<br />
Alberta Basin 246,200 144,450 83% 55%<br />
San Juan Basin (including to be earned) 99,050 38,835 78%-81% 50%<br />
Other 778,775 538,630 Varies Varies<br />
Note: Ownership interest(s) include to-be-drilled locations and should be considered estimates as interests vary over time.<br />
1<br />
Net acreage is 13,560 acres where the Company will be actively drilling.<br />
2<br />
Subject to litigation<br />
.<br />
32
Forward-Looking & Other Cautionary Statements<br />
Reserve figures are presented as of year-end 2012. Current production 4Q12.<br />
FORWARD-LOOKING STATEMENTS –This presentation contains forward-looking statements, including preliminary and unaudited results for 2012 and projections for<br />
future events. In particular, the Company is providing “<strong>2013</strong> Operating Guidance,” which contains projections for certain <strong>2013</strong> operational and financial metrics. These<br />
forward-looking statements are based on management’s judgment as of the date of this press release and include certain risks and uncertainties. Please refer to the<br />
Company’s Annual Report on Form 10-K for the year-ended December 31, 2011 filed with the SEC, and other filings including our Current Reports on Form 8-K and<br />
Quarterly Reports on Form 10-Q, for a list of certain risk factors that may affect these forward-looking statements. The Company provided unaudited estimates of certain<br />
year-end financial results, which are subject to revision in our audited financial statements to be included in our Annual Report on Form 10-K to be filed in February <strong>2013</strong>.<br />
Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things:<br />
oil, NGL and natural gas price volatility; costs and availability of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and<br />
other permits and rights-of-way; regulatory approvals, including regulatory restrictions on federal lands; legislative or regulatory changes, including initiatives related to<br />
hydraulic fracturing; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and<br />
materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of financing<br />
to fund the Company’s operations; the ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital<br />
obligations when requested; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; development drilling and<br />
testing results; the potential for production decline rates to be greater than we expect; performance of acquired properties; compliance with environmental and other<br />
regulations; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company’s risk management activities; title<br />
to properties; litigation; environmental liabilities; and, other factors discussed in the Company’s reports filed with the SEC. <strong>Bill</strong> <strong>Barrett</strong> <strong>Corporation</strong> encourages readers to<br />
consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or<br />
update any forward-looking statements based on future events or circumstances.<br />
Calculation of Natural Gas Liquids as a Percent of Sales Volumes<br />
The Company’s 2012 natural gas production included in this presentation is based on wellhead volumes and its 2012 natural gas revenue includes the incremental revenue<br />
benefit of receiving NGL sales prices for NGL volumes processed by the purchasers of our natural gas deliveries. Many oil and gas producing companies report NGL<br />
volumes and revenues separate from natural gas volumes and revenues. In order to provide a metric that is comparable to other oil and gas production companies, the<br />
Company is providing the percentage of total company sales volumes that receive NGL pricing based on the barrel of oil equivalent NGL volumes for revenues received<br />
from our gas purchasers. The NGL volumes identified by our gas purchasers are converted to an oil equivalent based on 42 gallons per barrel and compared to overall gas<br />
equivalent production based on a 1 barrel to 6 Mcf ratio.<br />
Effective January 1, <strong>2013</strong>, the Company intends to report its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas<br />
stream and sold as a separate product.<br />
33
Forward-Looking & Other Cautionary Statements<br />
Non-GAAP MEASURES:<br />
DISCRETIONARY CASH FLOW - is a non-GAAP financial measure. It is presented because management believes it provides useful additional information to<br />
investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income for unusual<br />
items to allow for a more consistent comparison from period to period. In addition, these measures are widely used by professional research analysts and others in the<br />
valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published<br />
research of industry research analysts in making investment decisions. Historical discretionary cash flow is reconciled to net income each quarter in the Company’s<br />
quarterly press release of results of operations.<br />
EBITDAX - is a non-GAAP financial measure. It is presented because management believes that it is useful to an investor for evaluating the Company’s operating<br />
performance. This is a widely used measure by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded<br />
from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital<br />
structure and the method by which assets were acquired, among other factors. There are significant limitations to using EBITDAX as a measure of performance,<br />
including the inability to analyze the effect of certain recurring and non-recurring items that materially affect net income or loss, the lack of comparability of results of<br />
operations of different companies and the different methods of calculating EBITDAX reported by different companies. The Company’s calculation of EBITDAX is<br />
discretionary cash flow plus cash interest expense and cash tax expense added back.<br />
FINDING AND DEVELOPMENT COST – Finding and development cost is a non-GAAP metric commonly used in the exploration and production industry. Calculations<br />
presented by the Company are based on costs incurred, as adjusted by the Company, divided by reserve additions. Reconciliation of adjustments to costs incurred is<br />
provided in the Company’s earnings release and Current Report on Form 8-K issued February 23, 2012.<br />
RESERVE and RESOURCE DISCLOSURE - The SEC permits oil and gas companies to disclose proved, probable and possible reserves in their filings with the SEC. The<br />
Company does not plan to include probable and possible reserve estimates in its filings with the SEC.<br />
We may use certain terms in this presentation, such as “risked resources,” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The calculation<br />
of risked resources, and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with<br />
SEC guidelines. Our estimate of risked resources is not prepared or reviewed by third party engineers, is determined using strip pricing, which we use internally for planning<br />
and budgeting purposes, and may differ from an un-risked estimate of proved, probable and possible reserves. The Company’s estimate of risked resources is provided in<br />
this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of<br />
companies; however, the Company’s estimate of risked resources may not be comparable to similar metrics provided by other companies.<br />
Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, available on the Company’s website at<br />
www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-<br />
SEC-0330 or at www.sec.gov.<br />
34
1099 Eighteenth Street, Suite 2300<br />
Denver, Colorado 80202<br />
303.293.9100<br />
www.billbarrettcorp.com<br />
Investor Relations:<br />
Jennifer Martin, Vice President<br />
303.312.8155<br />
jmartin@billbarrettcorp.com
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