1. Healthcare

GHS BUS TOUR - JANUARY 28, 2015
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
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
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
value to Northeast Wattenberg position by increasing net acreage 20% and
Added
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
4
Exceptionally Well Positioned for 2015
Low exposure to risk in challenging commodity price environment
• 2015 oil hedges ~11,000 b/d at $90
– Minimal sensitivity to oil prices, estimated at less than 5% of cash flow
• Ample liquidity
– $375 million revolver undrawn
– $250+ million cash (as of the end of the 3rd quarter 2014)
• 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
Hedging Provides Price Predictability
 Hedge on a 12-month forward basis to reduce risk and support capital expenditure
program
–
2015: 5.2 MMBoe; Oil 11,021 Bbls/d at $90.59/Bbl; natural gas: 19,745 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
$4.10/MMBtu
As of January 2, 2015
Volume (MMBoe)
Price ($/Boe)
$80
2.0
Price($/Boe)
Volume (MMBoe)
2.5
1.5
1.0
0.5
0.0
$60
1Q15
2Q15
3Q15
4Q15
Notes: As of January 2, 2015. Average swap price is for illustrative purposes only and does not represent formal guidance.
6
2015 Outlook: Operating Plan in Progress
Typically provide full year guidance late January
• Current process and considerations in a challenging environment:
– Exit 2014 with 3 rigs drilling in the DJ Basin and 1 rig drilling in the Uinta Oil Program
– Reviewing range of scenarios/rig activity at multiple commodity prices including a significantly
lower capital expenditure program
– Based on current service costs and net working interests, annual well drilling and completion
costs are approximately $120 million per rig in the DJ Basin and $45 million per rig in the Uinta
Oil Program
– The operating plan will dictate the budget for land and facility costs
– 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 long-term corporate objective of 2.5X or less
– Evaluating timing and impacts to 2016 program
– Cautious in baking-in cost reductions until they can be realized
7
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); $4.00 natural gas price
•
East Bluebell assumptions: 220 MBoe EUR; $2.5 D&C costs
8
September Transaction Summary Totaling $757 million Piceance, Powder Asset Sales/DJ Acreage Acquisition
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. $1.1 B
Debt -to-EBITDAX moving toward long-term objective of 2.5X
 Driving growth in the Northeast Wattenberg
–
–
–
7,856 net acres acquired, net acreage up ~20%
390 Boe/d production acquired
Increased working interests gain increased control, ability to accelerate drilling
9
Net Debt Cut by More Than 50%
($ millions)
3Q14
Outstanding Balance Revolving Credit Facility
7.625% Senior Notes due 2019
7.000% Senior Notes due 2022
5.000% Convertible Senior Notes
Lease Financing Obligation
Total Debt
Cash on hand
Net Debt
$
Borrowing Base
Letter of Credit
Cash on hand
Liquidity
$
$
$
$
400.0
400.0
25.3
3.7
829.0
294.8
534.2
375.0
(26.0)
294.8
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
DJ
2013
2014e
UOP
2010
2011
2012
DJ
2013
2014e
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

Production 4Q14 was impacted by
approximately 1,000 Boe/d as a result of
downtime at third party facilities in the area
 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
to make drilling program adjustments
50 Miles
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
Boe/d
6,000
3,000
1,564
0
Operated
Wells spud
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
3Q14
13
7
2
10
21
27
20
13
14
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/
Redtail
BCEI
– Successful extended reach
laterals within 2 miles of
BBG position
 Successful 40-acre spacing
within 3 miles of BBG position
 Continuation of geologic and
geophysical parameters across
position
SYRG
NBL
Loeffler Pad
NBL
Wells Ranch
CRZO
Razor/Rohn
BCEI
PDCE
Waste Mgt.
10 miles
BBG Acreage
15
Northeast Wattenberg – Driving Growth and Returns with XRLs
Extended Reach Lateral Program on Track*

27 wells drilled and completed: 15 northern
(all Niobrara B), 12 southern blocks (5
Niobrara B and 7 Niobrara C)

13 wells 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
*Data as of December 2014
**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)
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
 2Q14 added 4,500 Bbl/d firm
marketing agreement
10 Miles
BBG Acreage
Gas Production
Oil Production
10 Miles
BBG Acreage
 YE 13 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
NFX
CPG
QEP
UPL
LINN
NFX
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
 Production: 3,100 Boe/d (3Q14)
6 Miles
BBG Acreage
 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
Boe/d
3,000
2,000
1,435
1,000
0
Operated
Wells spud
3Q12
4Q12
1Q13
2Q13
3Q13
4
3
6
9
5
4Q13
0
1Q14
2Q14
3Q14
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 acreage 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
– Evaluated drilling and completion optimization
– Upheld high standards for health, safety and environment
 Exceptionally well positioned for 2015
– Fully hedged 2014 exit rate oil production, minimal sensitivity to oil prices
– Ample liquidity: $250 mm cash & undrawn revolver (as of end of 3Q14)
– Nominal drilling commitments to hold acreage
– Flexibility in capital program
– Expect double digit pro forma production growth in 2015 from 2014 exit rate production
24
APPENDIX
Natural Gas and Oil Hedges
As of January 2, 2015
Swaps
Period
Oil
Volume
(Bbls/d)
Natural Gas
WTI Price
($/Bbl)
Volume
(MMBtu/d)
NWPL Price
($MMBtu)
1Q15
11,190
$92.33
18,967
$4.15
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
Downspacing Pilot Location
Pilot Program
Future Locations
27
DJ Basin Operating Efficiencies
Average 4,000’ Lateral Drilling
Days
18
Average Drilling Cost per Foot
17.1
$200
$173
$150
11.8
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
YE2013
PostTransaction
Gross Acreage
Net Acreage
Northeast Wattenberg
YE2013
PostTransaction
67,680
71,370
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
(MBbls/d)
Capacity Expansion Projects
Timing
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
Additions
2015
Additions
Anadarko
300
300
DCP Midstream
100
170
Capacity Expansion Projects (MMcf/d)
 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
$184
18.1
14.3
15.0
$150
$113
10.0
10.0
$100
5.0
$50
0.0
$93
$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
Refining Capacity
Operator
Current Black/Yellow
Capacity (MBbls/d)
Chevron
15,000
~5,000
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
Tesoro
Black/Yellow Capacity
Expansions (MBbls/d)
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
MMBoe
Proved +
Risked
Resources
MMBoe
Gross/Net
Drilling
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
5
95
1,370/284
TOTAL
197
587
5,390/2,329
% OIL
42%
55%
Proved
Total Risked Resources (2013)
Oil
Gas/NGLs
Powder River
Deep2 (oil)
0
100
200
MMBoe
1DJ:Risked
resources includes between 8-20 wells per section; majority based on standard length laterals
both 4,000 and 9,000 foot laterals and drilling locations spread over six different formations
Note: $3.67 per MMBtu HH and $96.91 per barrel WTI pricing used in reserve calculations
2Includes
34
UOP: Undeveloped Location Inventory
Risked Resources (171 MMBoe)
785 Net Drilling Locations
(Gross 1,795)
124
42
92
137
524
37
Blacktail Ridge/Lake Canyon
Blacktail Ridge/Lake Canyon
East Bluebell
East Bluebell
South Altamont
South Altamont
 80-acre and 160-acre spacing
 Upside from downspacing
 Positive testing enables potential to
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
349
NE Wattenberg
(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, 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
 Lease Operating Expense: $58-$62 million
 Gathering, transportation & processing:
$36-$37 million
Uinta Oil
Program
Powder
River Deep
Program
DJ Basin
 General and Administrative: $43-$45 million
37
Land Summary
As of September 30, 2014
Area
Gross Acreage
Net Acreage
126,710
123,440
36,895
36,855
323,900
58,160
50,095
23,675
20,200
152,130
Total DJ Basin Program
71,370
16,300
37,910
3,860
129,440
Powder Deep Oil Program
Average Gross Project Average BBG Working
NRI
Interest
Active Oil Properties
Uinta Basin – Uinta Oil Program
Blacktail Ridge/Lake Canyon
Minimum to be earned
East Bluebell
Other
Total Uinta Oil Program
82%
82%
83%
80-100%
51%
51%
70%
70-90%
49,365
12,405
22,680
3,000
87,450
81%
84%
83%
Varies
97%-100%
Varies
38,455
18,695
80%
10%-65%
40,310
297,280
30,585
27,065
86,990
197,685
36,280
208,215
16,820
11,305
59,040
134,505
88%
83%
85%
83%
83%
Varies
90%
100%
55%
44%
55%
Varies
DJ Basin
Northeast Wattenberg
Wattenberg Core
Chalk Bluffs
Other
Exploration & Other Properties
Piceance Basin – Cottonwood Gulch1
Paradox Basin – Yellow Jacket
Uinta Basin (Hornfrog, including to-be-earned)
DJ Basin – Sage Brush
Alberta Basin
Other
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.
40