CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014

 
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE

                                      December 2014
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Forward-Looking & Other Cautionary Statements

Please reference the last two pages of this presentation for important disclosures on:

   Forward-looking statements
   Non-GAAP measures
   Reserves
   Risked Resources

                                                                                         2
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Company Overview (NYSE:BBG)
BBG is a Rocky Mountain based oil development company

 ~ $1 billion enterprise value
  – ~$500 million market cap

 2 areas of operation
  – DJ Basin, Colorado & Wyoming
  – Uinta Oil Program, Utah

 3Q14 pro forma production ~70% oil
  – Boe: 15,185 Boe/d
  – Oil: 10,230 Bbls/d
  – Gas: 20.1 MMcf/d
  – NGLs: 1,610 Bbls/d

                                                        3
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Value Creation 2014

2014 Accomplished key objectives

Completed transition from natural gas exploration company to oil development company
     – Simplified portfolio to two core oil development programs

     – Focused portfolio in DJ and Uinta basins that offer comparably strong returns

     – Sold assets that we were no longer investing in

Added  value to Northeast Wattenberg position by increasing net acreage 20% and
 negotiating terms to increase flexibility for our drilling operations

Strengthened balance sheet: cut net-debt in half, established ample liquidity
Settled Cottonwood Gulch litigation with expected proceeds of $42mm
Allocated capital to most profitable programs increasing operating profit margin ~40%
Initiated extended reach lateral drilling program in DJ to maximize returns
     – 27 longer lateral wells successfully drilled and completed to date

                                                                                         4
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Exceptionally Well Positioned for 2015

Low exposure to risk in challenging commodity price environment
  • Fully hedged 2014 exit rate oil production – for 2015 ~11,000 b/d hedged at $90
    – Minimal sensitivity to oil prices, estimated at less than 5% of cash flow

  • Ample liquidity
    – $375 million revolver undrawn

    – $250+ million cash

  • Nominal drilling commitments to hold acreage
  • Flexibility in capital program - short term drilling and completion contracts enable
    flexibility in total capital commitments, timing of commitments and offer potential to
    negotiate improved costs
  • Expect double digit pro forma production growth in 2015 given contribution from wells
    already drilled coming on-line

                                                                                             5
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Hedging Provides Price Predictability

 Hedge on a 12-month forward basis to reduce risk and support capital expenditure
  program
         –      4Q14: 1.3 MMBoe; Oil: 10,600 Bbls/d at $93.88/Bbl; natural gas: 19,158 MMBtu/d at
                $3.55/MMBtu
         –      2015: 5.2 MMBoe; Oil 11,171 Bbls/d at $90.13/Bbl; natural gas: 20,000 MMBtu/d at
                $4.13/MMBtu
         –      2016: 2.0 MMBoe; Oil 4,746 Bbls/d at $87.46/Bbl; natural gas: 5,000 MMBtu/d at
                $4.10/MMBtu

    As of December 5, 2014                                                                                                    Volume (MMBoe)
                                                                                                                              Price ($/Boe)

                                     2.5                                                                                       $100

                                     2.0                                                                                       $80
                    Volume (MMBoe)

                                                                                                                                      Price($/Boe)
                                     1.5                                                                                       $60

                                     1.0                                                                                       $40

                                     0.5                                                                                       $20

                                     0.0                                                                                       $0
                                           4Q14       1Q15               2Q15              3Q15               4Q15

Notes: As of December 5, 2014. Average swap price is for illustrative purposes only and does not represent formal guidance.

                                                                                                                                                     6
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
2015 Outlook: Operating Plan in Progress

Typically provide full year guidance late January

  • Current process and considerations in a challenging environment:
    – Reviewing range of scenarios/rig activity at multiple commodity prices

    – Maximum scenario under consideration = exit rate rig activity including 3 rigs in the DJ and 1 rig
      in UOP for total capital program of $475 million. Considering range of scenarios including
      significantly lower total capital expenditures

    – Investment decisions based on merits at pre-hedge pricing. Programs will be concentrated on
      highest return/best payback activity

    – Mindful of net-debt: EBITDAX with corporate objective of 2.5X or less

    – Mindful of timing and impacts to 2016 program

    – Cautious in baking-in cost reductions until they can be realized

                                                                                                           7
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Preliminary Look at Returns

Sensitivity to commodity prices: returns hold up pre-hedge, favor XRLs

   • Investment decisions based on merits of investment pre-hedge
   • Northeast Wattenberg XRLs exceed 20% hurdle rate at $65 oil
        •    XRL assumptions: 870 MBoe EUR (3-stream); $8.25 MM D&C costs (includes additional costs for increased
            sand, stages and plug-n-perf but no additional EUR until evidenced over time)

        •   East Bluebell assumptions: 220 MBoe EUR; $2.5 D&C costs

                                                                                                                 8
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Summary of September Transactions – Totaling $757 million
 1. Simplified portfolio
 2. Focused on highest return assets
 3. Strengthened balance sheet, materially reduced debt
 4. Increased Northeast Wattenberg position

  Simplified portfolio
      –   2 areas of operations down from 4

  Focused on highest return assets
      –   DJ and Uinta Basins offer highest returns in portfolio
      –   Production 70% oil v. 39% oil pre-transaction

  Strengthened balance sheet, materially reduced net debt
      –   ~$534MM v. $1.1 B
      –   Debt -to-EBITDAX moving toward long-term objective of 2.5X

  Driving growth in the Northeast Wattenberg
      –   7,856 net acres acquired, net acreage up ~20%
      –   390 Boe/d production acquired
      –   Increased working interests gain increased control, ability to accelerate drilling

                                                                                               9
CAPITAL ONE SECURITIES 9TH ANNUAL ENERGY CONFERENCE - December 2014
Net Debt Cut by More Than 50%

     ($ millions)                                        3Q14

     Outstanding Balance Revolving Credit Facility   $       -
     7.625% Senior Notes due 2019                        400.0
     7.000% Senior Notes due 2022                        400.0
     5.000% Convertible Senior Notes                      25.3
     Lease Financing Obligation                            3.7
       Total Debt                                    $   829.0
     Cash on hand                                        294.8
       Net Debt                                      $   534.2

     Borrowing Base                                  $   375.0
     Letter of Credit                                    (26.0)
     Cash on hand                                        294.8
      Liquidity                                      $   643.8

                                                                  10
Delivering High Growth from Core Oil Programs

              Production (MMBoe)                                                                         Operating Cash Flow* ($MM)
8                                                                                                 $300

6
                                                                                                  $200

4

                                                                                                  $100
2

0                                                                                                   $0
        2010         2011          2012         2013        2014e                                        2010   2011        2012   2013   2014e

                                    DJ      UOP                                                                        DJ   UOP

      Focused capital program on Uinta and DJ Basin development delivers strong
       production and cash flow growth

    *Operating cash flow is field level before general and administrative and interest expense.

                                                                                                                                                  11
DJ BASIN
DJ Basin: Lots of Running Room
Added 7,856 net acres September 2014 to total 84,450   Niobrara and Codell Formations
 Northeast Wattenberg: 49,365 net acres, up 20%
 Chalk Bluffs: 22,680 net acres
 Wattenberg interior: 12,405 net acres

Driving rapid growth
 Production 3Q14: 8,270 Boe/d, up 150% from
  3Q13
 2014 plan: ~75% of capital program to drill ~65
  gross/53 net and participate in ~47 gross/9 net
  non-operated wells
 Increased working interest through asset
  exchange enables better control and flexibility
                                                                          50 Miles
  to make drilling program adjustments
                                                                           BBG Acreage

 Proved reserves YE13 66 MMBoe, up >350%

                                                                                     13
DJ Basin: Production Growth

                        DJ Basin Net Production and Gross Operated Horizontal Wells Spud
                9,000
                                                                                           8,270

                6,000
        Boe/d

                3,000

                         1,564

                   0
                          3Q12    4Q12    1Q13    2Q13    3Q13    4Q13    1Q14    2Q14     3Q14
    Operated
                          13       7       2       10      21      27      20      13       14
    Wells spud

                                   Driving continued growth

                                                                                                   14
Northeast Wattenberg: Prime Position Among Peers

Excellent position yet to be fully valued
 Located between BCEI positions                                      Niobrara Formation

 Adjacent to NBL Wells Ranch                                                        East Pony/
                                                                   BCEI               Redtail
    – Successful extended reach                            SYRG
      laterals within 2 miles of
      BBG position
                                                                NBL                    CRZO
                                                            Wells Ranch
 Successful 40-acre spacing                   NBL
                                            Loeffler Pad
                                                                                     Razor/Rohn

  within 3 miles of BBG position
                                                            BCEI
                                               PDCE
 Continuation of geologic and               Waste Mgt.
  geophysical parameters across
  position

                                                                                     BBG Acreage
                                                                          10 miles

                                                                                                  15
Northeast Wattenberg – Driving Growth and Returns with XRLs
Extended Reach Lateral Program on Track
   27 drilled and completed: 15 northern (all
    Niobrara B), 12 southern blocks (5 Niobrara
    B and 7 Niobrara C)

   13 have reached peak production and are
    on sales
   ( #1) 4-wells ~ 7,300’ laterals:
         24-hour average IP: 770 Boe/d
         30-day average IP: 548 Boe/d
         60-day average IP: 447 Boe/d

   (#2) 7 wells ~ 9,300’ laterals: 3 on sales*, 4
    in flowback

   (#3) 3 wells ~9,300’ laterals: all on sales

   (#4) 7 wells ~9,300’ laterals: 3 on sales; 4
    just completed

   (#5) 4 wells ~ 9,300’ laterals in flowback

     *Definition of sales includes wells that are producing hydrocarbons and initiated the 30-day IP period

                                                                                                              16
XRL Type Curve Performance

Peer wells prove type curve over two year time period
 6 peer wells in close proximity continue to
  follow 825 MBoe type curve (2-stream)

  1,000
  Average Daily Oil Production (BOPD)

                              100

                                        10                                                      Long Lateral Type Curve
                                                                                                (825 mboe)

                                         1
                                             0 30 60 90 120150180210240270300330360390420450480510540570600630660690720750780
                                                                               Days On Production
                                                                                                                                Peer locations

                                                                                                                                                 17
Northeast Wattenberg – Seeking Optimization
 “Controlled” flowbacks on all XRLs
 Downspacing test on four pads to mimic 40-acre spacing
 Increased sand volumes on 4 wells to 12 mm lbs. v. 9 mm lbs.
 Plug-and-perf completions on 5 wells v. sliding sleeve. Lower risk technique
 Increased stimulation stages to 55 on 7 wells (~1/2 with increased sand)

One-third Increase in sand volume                 25 v. 18 stages
Peer test: ~50% increase in EUR                   BBG test ~25% increase in EUR

                                                                                  18
UINTA OIL PROGRAM
Uinta Oil Program

Large, Scalable Program: ~150,000 net acres
                                                         Wasatch, Green River Formations
         East Bluebell: 23,675 net acres
         Blacktail Ridge/Lake Canyon:
          108,255* net acres
         South Altamont: 20,200 net acres

Driving Steady Growth

 Production: 6,800 Boe/d (3Q14)
 2014 plan: ~15-20% of capital plan
  with 51 gross/33 net operated wells
                                                             BBG Acreage         Gas Production
                                              10 Miles
 2Q14 added 4,500 Bbl/d firm                                                    Oil Production

  marketing agreement                                                                      BBG Acreage
                                                                           10 Miles

 Proved reserves 53 MMBoe, up 10%

* Includes acreage to be earned.

                                                                                                    20
Uinta Basin: Well Positioned Among Peers
                                          Wasatch, Green River Formations

                                    DVN
                     EPE
                                                              CPG
                                          CPG                 QEP
                              NFX
                                                  UPL
                                    NFX
                       LINN

                                                   10 Miles         BBG Acreage

                                                                                  21
UOP: East Bluebell Execution
East Bluebell Program Offers Substantial Upside
 36,895 gross/23,675 net acres                       Lower Green River

 Development on 80-acre spacing with further
  downspacing planned
 Vertical wells targeting Lower Green River
  formation
 Early stage program, 20 wells drilled 2013

2014 Plans: Capture Value at East Bluebell
 41 gross/27 net wells in 2014 plan
                                                                BBG Acreage
 Production: 3,100 Boe/d (3Q14)                  6 Miles

 Drive capital efficiencies
 Build out infrastructure
 Continue delineation efforts

                                                                              22
UOP: East Bluebell Production Growth

                        East Bluebell Net Production and Gross Operated Wells Spud
               4,000

                                                                                      3,100
               3,000
       Boe/d

               2,000
                       1,435

               1,000

                  0
                       3Q12    4Q12    1Q13    2Q13    3Q13    4Q13    1Q14    2Q14   3Q14
    Operated
    Wells spud          4       3       6       9       5        0       9      11     12

                 Increasing Activity and Growing Production

                                                                                              23
Solid Foundation for Our Future
  2014 accomplished what we set out to do

   – Completed transition to oil development company with simplified two asset portfolio

   – Increased Northeast Wattenberg position by 20%

   – Strengthened balance sheet: cut net-debt in half, established ample liquidity

   – Settled Cottonwood Gulch litigation with expected proceeds of $42mm

   – Allocated capital to most profitable programs and increased operating profit margin ~40%

   – Initiated extended reach lateral drilling program in DJ to maximize returns

   – Upheld high standards for health, safety and environment

  Exceptionally well positioned for 2015
   – Fully hedged exit rate oil production, minimal sensitivity to oil prices

   – Ample liquidity: $250 mm cash & undrawn revolver

   – Nominal drilling commitments to hold acreage

   – Flexibility in capital program

   – Expect double digit pro forma production growth in 2015 from 2014 exit rate production

                                                                                                24
APPENDIX
Natural Gas and Oil Hedges

As of December 5, 2014

Swaps
Period                          Oil                     Natural Gas

                     Volume           WTI Price     Volume      NWPL Price
                     (Bbls/d)          ($/Bbl)     (MMBtu/d)     ($MMBtu)

4Q14                     10,600           $93.88       19,158         $3.55

1Q15                     11,800           $90.46       20,000         $4.13

2Q15                     11,300           $90.39       20,000         $4.13

3Q15                     10,800           $89.81       20,000         $4.13

4Q15                     10,800           $89.81       20,000         $4.13

1Q16                      5,500           $87.61        5,000         $4.10

2Q16                      5,500           $87.61        5,000         $4.10

3Q16                      4,000           $87.24        5,000         $4.10

4Q16                      4,000           $87.24        5,000         $4.10

                                                                              26
Northeast Wattenberg – Driving Value Through Downspacing
                                                                   5,280’
Actively evaluating four downspacing pilots
 Two 9,300’ lateral B Bench wells
 Two 9,300’ lateral C Bench wells staggered
  beneath B Bench locations
 All testing areas on Southern acreage block
 Codell testing will follow

                                                                                       10,560’

                                         B Chalk

                                         C Chalk

                                         Codell

                                                   Pilot Program    Future Locations
      Downspacing Pilot Location
                                                                                          27
DJ Basin Operating Efficiencies

       Average 4,000’ Lateral Drilling                     Average Drilling Cost per Foot
                   Days
18        17.1
                                                    $200

                                                               $173

                      11.8                          $150
12
                                  10.1
                                                                          $108
                                                                                     $97
                                                    $100

 6

                                                     $50

 0
          2012        2013      2014 YTD              $0
                                                               2012       2013     2014 YTD

      Standard reach lateral drill times improved by 15% year-over-year
      Drilling cost per foot nearly cut in half since 2012

                                                                                              28
DJ Basin: 20% Increase in Northeast Wattenberg Position

 7,900 net acres acquired increasing NE Wattenberg 20% to 49,365 net acres

                                    Southern Acreage Block   Northeast Wattenberg

                                                  Post-                  Post-
                                     YE2013    Transaction   YE2013   Transaction
  Gross Acreage                                              67,680      71,370

  Net Acreage                        21,100       29,000     40,500      49,365

  Proved Reserves (MMBoe) (YE13)       17           19         56          58

  Risked Resources (MMBoe) (YE13)      63           71        145         153

                                                                                    29
DJ Basin Infrastructure

 Existing local oil refining capacity and rail infrastructure >350mbbls/d
                                         Capacity
Capacity Expansion Projects                            Timing
                                        (MBbls/d)
Pony Express Pipeline                     230          In Service

White Cliffs Expansion                     75          In Service
Pony Express DJ Lateral                    90          1Q15
Saddlehorn Pipeline                    Open Season     2016
Grand Mesa Pipeline                    Open Season     2016

 Current gas processing capacity ~1.1 Bcf/d
                                             2014               2015
Capacity Expansion Projects (MMcf/d)
                                           Additions          Additions
Anadarko                                        300             300
DCP Midstream                                   100             170

 Front Range Pipeline brings NGLs access to Mt. Belvieu NGL market
NGL Pipelines Additions         Capacity (MBbls/d)            Timing

Front Range Pipeline            150                           In Service

                                                                             30
DJ Basin Infrastructure – Expected Capacities

                  Cheyenne Crude
                 Terminal 52mbbls/d

                                                                 Pony Express Conversion
                                                                In Service: 230-320mbbls/d

                                                        Pony Express NE CO Lateral
                                                             1Q15: 90mbbls/d

             Suncor Refinery:
               96MBbls/d                                                           White Cliffs Pipeline
                                                                                 In Service: 150mbbls/d
                                Plains Rail Facility:
                                 2H14: 68mbbls/d

                                                                                                           31
East Bluebell Production Efficiencies

       Average Drilling Days                              Average Drilling Cost per Foot
20.0                                               $200
        18.1                                                  $184

15.0                 14.3                          $150

                                                                         $113
                                 10.0
10.0                                               $100                             $93

 5.0                                                $50

 0.0                                                 $0
        2012        2013       2014 YTD                       2012       2013     2014 YTD

  Operating efficiencies increasing; wells being drilled faster for less
  Year-over-year 2014 average drilling days per well decreased 30%
  Year-over-year 2014 average cost per foot decreased 20%

                                                                                             32
Uinta Oil Program

Operator         Current Black/Yellow   Black/Yellow Capacity
                  Capacity (MBbls/d)    Expansions (MBbls/d)
Chevron                15,000                    ~5,000

Tesoro              15,000-20,000               ~20,000

Holly Frontier         10,000                    14,000

Big West               ~15,000                      -

Silver Eagle           12,000                       -

Total                  65,000+                  ~40,000

                                                                33
Low-risk, Long-term Growth Profile – Year-end 2013
           88% growth in proved reserves at three active oil programs
           80% growth in risked resources at three active oil programs
           ~$350 million increase in Pretax PV10
           $8.30/Boe 2013 F&D cost                                                                                       Year-end 2013
                                                                                                                              Proved +
       Proved                                                                                                                  Risked     Gross/Net
                                                                                                                   Proved    Resources     Drilling
       Total Risked Resources (2013)                 Oil      Gas/NGLs                                             MMBoe       MMBoe      Locations

   Denver Julesburg1
   (oil/NGLs)                                                                                                        66         221       1,697/844

   Uinta Oil
   Program (oil)                                                                                                     53         171       1,795/785

   Gibson Gulch,
   Piceance (NGLs)                                                                                                   73         100        528/416

   Powder River
   Deep2 (oil)                                                                                                       5          95        1,370/284

                           0                           100                          200
                                                             MMBoe                                         TOTAL    197         587       5,390/2,329
1DJ:Risked resources includes between 8-20 wells per section; majority based on standard length laterals
2Includes both 4,000 and 9,000 foot laterals and drilling locations spread over six different formations   % OIL    42%        55%
Note: $3.67 per MMBtu HH and $96.91 per barrel WTI pricing used in reserve calculations

                                                                                                                                                        34
UOP: Undeveloped Location Inventory

     Risked Resources (171 MMBoe)               785 Net Drilling Locations
                                                         (Gross 1,795)

                                                        124
            42

                                                  137
                                 92
           37                                                            524

           Blacktail Ridge/Lake Canyon              Blacktail Ridge/Lake Canyon
           East Bluebell                            East Bluebell
           South Altamont                           South Altamont

 80-acre and 160-acre spacing            Positive testing enables potential to
 Upside from downspacing                  respace
                                          Plan to test EB 40-acre downspacing late
                                           ‘14/early ‘15
                                                                                      35
DJ Basin Year-end 2013 Undeveloped Location Inventory
                                844 Net Undeveloped Locations
                                        Total Gross: 1,697

                               94         130                           Core Wattenberg
                        43
                                                                        NE Wattenberg (North)

                                                                        NE Wattenberg (South)

                        228                                             NE Wattenberg
                                             349                        (Western)
                                                                        Chalk Bluffs

               Based on standard length laterals, as of year-end 2013

           Extensive inventory
           Upside from down-spacing
           Testing 40-acre spacing (4 wells per ¼ section) in 4 areas, to spud 2014
                                                                                                36
Capital Program 100% Directed at Oil Growth
2014 Adjusted Guidance

 Total capital of $560-$570 MM
                                                    2014 Capital % by Area
 Total Production of 9.0 – 9.4 MMBoe

    –   Fourth quarter guidance 1.3 – 1.7 MMBoe
                                                         Uinta Oil
                                                         Program
 Lease Operating Expense: $58-$62 million
                                                   Powder
                                                  River Deep
 Gathering, transportation & processing:          Program
                                                                     DJ Basin
  $36-$37 million

 General and Administrative: $43-$45 million

                                                                                37
Land Summary
As of September 30, 2014
                                                                                                                Average Gross Project Average BBG Working
Area                                                            Gross Acreage              Net Acreage
                                                                                                                        NRI                 Interest
Active Oil Properties
Uinta Basin – Uinta Oil Program
    Blacktail Ridge/Lake Canyon                                      126,710                   58,160                       82%             51%
    Minimum to be earned                                             123,440                   50,095                       82%             51%
    East Bluebell                                                     36,895                   23,675                       83%             70%
    Other                                                             36,855                   20,200                     80-100%          70-90%
Total Uinta Oil Program                                              323,900                  152,130

DJ Basin
    Northeast Wattenberg                                              71,370                    49,365                        81%           Varies
    Wattenberg Core                                                   16,300                    12,405                        84%         97%-100%
    Chalk Bluffs                                                      37,910                    22,680                        83%           Varies
    Other                                                              3,860                     3,000
Total DJ Basin Program                                               129,440                    87,450

Powder Deep Oil Program                                               38,455                    18,695                        80%          10%-65%

Exploration & Other Properties
Piceance Basin – Cottonwood Gulch1                                    40,310                   36,280                          88%           90%
Paradox Basin – Yellow Jacket                                        297,280                  208,215                          83%          100%
Uinta Basin (Hornfrog, including to-be-earned)                        30,585                   16,820                          85%           55%
DJ Basin – Sage Brush                                                 27,065                   11,305                          83%           44%
Alberta Basin                                                         86,990                   59,040                          83%           55%
Other                                                                197,685                  134,505                         Varies        Varies

Note: Ownership interest(s) include to-be-drilled locations and should be considered estimates as interests vary over time.
1 Subject to litigation

.

                                                                                                                                                            38
Forward-Looking & Other Cautionary Statements
Reserve figures are presented as of December 31, 2013.

FORWARD-LOOKING STATEMENTS:

This presentation contains forward-looking statements. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s
control. Actual results could differ materially from those discussed in these forward-looking statements. In particular, the Company is providing updated “2014 Operating
Guidance,” which contains projections for certain 2014 operational and financial metrics. These and other forward-looking statements in this presentation are based on
management’s judgment as of the date of this presentation and include certain risks and uncertainties. Among a number of factors, operations plans are subject to change
during the year and such changes can materially affect projected results provided in the Company’s guidance. Please refer to the Company’s Annual Report on Form 10-K
for the year ended December 31, 2013 filed with the SEC, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of
certain risk factors that may affect these forward-looking statements.

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:
oil, NGL and natural gas price volatility, including regional price differentials; costs, availability and timing of build-out of third party facilities for gathering, processing,
refining and transportation; delays or other impediments to drilling and completing wells arising from political or judicial developments at the local, state or federal level,
including voter initiatives related to hydraulic fracturing; development drilling and testing results; the potential for production decline rates to be greater than expected;
regulatory delays, including seasonal or other wildlife restrictions on federal lands; exploration risks such as drilling unsuccessful wells; higher than expected costs and
expenses, including the availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity
market conditions, including the availability and costs of financing 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 obligations when requested; declines in the values of our oil and gas properties resulting in
impairments; changes in estimates of proved reserves; compliance with environmental and other regulations; derivative and hedging activities; risks associated with
operating in one major geographic area; the success of the Company’s risk management activities; title to properties; litigation; environmental liabilities; and, other factors
discussed in the Company’s reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and
other forward-looking statements and to not place undue reliance on any such statements. In addition, the Company assumes no obligation to publicly revise or update any
forward-looking statements based on future events or circumstances.

NATURAL GAS LIQUIDS:

Effective January 1, 2013, the Company began reporting its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas
stream and sold as a distinct product.

2013 year-end reserves are presented on a three-stream basis, and year-end 2012 reserves are recalculated to reflect three-stream volumes for comparability. NGL
volumes are converted to an oil equivalent based on 42 gallons per barrel and compared to overall gas equivalent production based on a 1 barrel to 6 Mcf ratio.

                                                                                                                                                                                      39
Forward-Looking & Other Cautionary Statements
NON-GAAP MEASURES:

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
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 from
the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and
the method by which assets were acquired, among other factors. There are significant limitations to using EBITDAX as a measure of performance, 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 operations of different
companies and the different methods of calculating EBITDAX reported by different companies. The Company’s calculation of EBITDAX is discretionary cash flow plus cash
interest expense and cash tax expense added back.

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
Company does not plan to include probable and possible reserve estimates in its filings with the SEC.

We may use certain terms, such as “risked resources,” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The calculation 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 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 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 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
companies; however, the Company’s estimate of risked resources may not be comparable to similar metrics provided by other companies. Investors are urged to consider
closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2013, available on the Company’s website at 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-SEC-0330 or at www.sec.gov.

FINDING AND DEVELOPMENT COST – Finding and development cost is a non-GAAP metric commonly used in the exploration and production industry. Calculations
presented by the Company are based on costs incurred, as adjusted by the Company, divided by reserve additions and are unaudited.

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