barclays ceo energy-power conference...wpx energy | barclays ceo energy-power conference | september...

Barclays CEO Energy-Power Conference

Rick Muncrief, President and Chief Executive Officer

Sept. 9, 2015

Announced or completed more than half of year-end 2015 divestitures target ► Announced ~$185MM sale of Van Hook gathering system

► Completed ~$80MM sale of Powder River Basin operations

Upsized unsecured revolver to $1.750B Ability to rapidly lower or accelerate capital program

► Minimal capital required to maintain core acreage

Nearly fully hedged for the balance of 20151

► Oil production ~80% hedged at $85.14 per barrel

► Natural gas production ~75% hedged at $4.04 per MMbtu

Strong hedge position heading into 20162

► Oil production at least 50% hedged at $62.23 per barrel

► Natural gas production at least 70% hedged at $3.63 per MMbtu

Upsized unsecured revolver to $1.750B

WPX Highlights

1Based on mid-point of July – December production guidance. 2Based on the 2016 outlook mid-point in the RKI acquisition presentation

2 WPX Energy | Barclays CEO Energy-Power Conference | September 9, 2015

Highlights Over the Past 16 Months

Rick Muncrief becomes CEO May 2014

WPX completes sale of working interest to Legacy LP June 2014

Infill project added ~200 gross locations in Williston August 2014 Completed sale of Northeast

Pennsylvania assets February 2015

Announced consolidation of Denver office to Tulsa March 2015

Completed sale of Northeast Supply Link

May 2015

Completed exit of international assets January 2015

Completed acquisition of RKI

August 2015

2014 2015 2016

Added partner to accelerate development of Trail Ridge Properties

August 2014

Outlined multi-year strategy October 2014

Named Clay Gaspar SVP of Operations and Development

October 2014

Gallup oil play hits 100,000 net acres June 2015

Targeting $400MM-$500MM

in Asset Sales Year-end 2016

Named Kevin Vann as CFO July 2014

Spud first 2 mile Niobrara lateral

July 2015

Adds 26K acres in Gallup oil play August 2014

Renegotiated $1.75B unsecured revolver July 2015

Targeting $150MM-$250MM in additional asset sales Year-end 2015

NOTE: Transactions totaling over $4 Billion. Acquisitions Asset sales


Announced sale of Van Hook Gathering System August 2015

Completed Powder River Basin Sale

September 2015

Premier Western Energy Producer

PICEANCE BASIN Cash Flow + Resource Potential

• Vertical: Deep inventory (~10,000 locations) with infrastructure in place

• Niobrara/Mancos: 15 -20 Tcfe stacked-pay resource potential

• Stable cash flows provide financial flexibility

WILLISTON BASIN High Oil Content with Continuing Growth

• 600+ operated remaining locations, ~87,000 acres

• 37% production CAGR 2Q’12-2Q’15 (Mboe/d)

• Downspacing, infrastructure, operational efficiencies drive upside

PERMIAN BASIN Deep Inventory of High-Return Locations

• Decades of drillable locations

• Significant upside potential from downspacing and additional prospective horizons

• 670,000+ net prospective acres

SAN JUAN BASIN Oil and Natural Gas Development Opportunities

• Gallup Oil: 400+ locations, ~100,000 acres

• Natural gas: potential for future development opportunities

• Established infrastructure


Core Delaware Basin Acreage

New Mexico

Texas

Infrastructure Hub

WPX ACREAGE

Wolfcamp

Bone Spring

Avalon

Delaware Sands

~92,000 net acres with 12 prospective zones

► 670,000+ net prospective acres of stacked pay

► 3,600+ gross risked locations

► ~98% of net acres held by production

► ~22,000 Boe/d current production

Infrastructure capacity in place for rapid development

► 375+ miles of gas gathering and water infrastructure

► 200,000 barrels per day of water gathering capacity

► Current gathering: ~90,000 bpd

► 90 MMcf/d of gas compression capacity

► Current compression: ~40 MMcf/d

Significant upside opportunities

► High intensity completions

► Downspacing/longer laterals

► Netback improvements

1,500 lb/ft Wolfcamp A well exceeding type curve1

► 199.2 Mboe of cumulative production first 224 days

► Exceeds type curve by 85.5Mboe, or 75% in the first 224 days

► Moving to 2,000 lb/ft completions


1 Covington 46-3H well

9,0

00

’

Delaware - World-Class Hydrocarbon System

Delaware Mountain Group

► 3,000’+ of stacked conventional sands

► 200+ vertical Delaware wells across Stateline position de-risk the play

► Horizontal development remains as upside potential

Avalon Shale

► Thick section of combined Upper and Lower Avalon with greater than 900’ of gross thickness in core of Stateline field

► Large hydrocarbon resource in place

► Both Upper and Lower Avalon have been de-risked by 50 producing wells on Stateline acreage

Bone Spring

► Three benches present

► Over 1,300’ of total gross interval

► Sufficient resource thickness exists to support stacked development

► Production currently established from 1st and 2nd Bone Spring on the acreage position

Wolfcamp

► Four benches present on Stateline acreage

► Total section in excess of 2,000’ thick

► Production currently established from A and C benches on Stateline

► Wolfcamp A de-risked by 29 horizontal wells

Hydrocarbon Pay Indication

WOLFCAMP B

WOLFCAMP C

WOLFCAMP D

CHERRY CANYON

BRUSHY CANYON

AVALON

FIRST BONE SPRING

SECOND BONE SPRING

BELL CANYON

THIRD BONE SPRING

WOLFCAMP A


$8.61

$6.11

$-

$3

$6

$9

2Q'14 2Q'15

Williston: Costs Down with Performance Increasing

$/B

OE

Flexible capital program ► Adding 3rd rig in November

► Inventory of 14 drilled uncompleted wells

Increased EUR’s 25% to 750 Mboe ► Additional upside with larger stimulations

Testing larger stimulations ► Higher intensity slick water completions

► 10MM pounds with more stages

Advancing drilling technology in 3 mile laterals

► Record 14,707’ rotary steerable run

► Cost reduction in rotary steerables competing with conventional tools

29% Decrease

LOE per BOE

HIGH INTENSITY

COMPLETIONS


$172

$152

$130 $130 $129 $126 $120

$115 $110

$98 $95

$60

$80

$100

$120

$140

$160

$180

San Juan Gallup: Continued Growth and Execution

300%+ production growth1

Efficiencies drive more wells with fewer rigs ► Two record wells of 7.9 days

► Intra-pad rig move of 0.3 days

Surpassed basin measured depth record 3x ► Unit #134H @ 13,418’

► Unit #133H @ 13,741’

► Unit #900H @ 15,391’, longest lateral drilled in basin

Oil gathering agreement improving differentials ► Oil differentials improve 24%2

► $8 -$10 differentials 2nd half of 2015 and beyond

Increased Gallup position to ~100,000 net acres

-$13.45

-$10.22

-$16

-$14

-$12

-$10

-$8

-$6

-$4

-$2

$0

2Q'14 2Q'15

24% Improvement

Oil Differentials Y/Y

12Q ’15 vs. 2Q ’14 equivalent production 22Q ’15 vs. 2Q ’14

Gallup Drilling Efficiency

Dri

llin

g C

ost

/ft.


Piceance: Large-Scale Resource with Deep Potential

Half the time and twice the depth ► Spud May 2014: 1 mile drilled in 117 days

► Spud April 2015: 2 mile drilled in 50 days

2 mile Niobrara well ► Currently producing 13.3MMcf/d @ 6,200 psi

Testing alternative spacing in Mesa Verde ► Valley 20-acre spacing

► Ryan Gulch 15-acre spacing

Tailor frac design/volume in Mesa Verde ► Valley – 1,100 gal/ft to 2,500 gal/ft

► Ryan Gulch – 1,500 gal/ft to 2,500 gal/ft

► High volume 100 mesh test

Evaluate creative options to unlock Piceance Basin value

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

0 15 30 45 60 75 90 105 120

Me

asu

red

De

pth

(ft

)

Days From Spud

1 mile lateral spud May 2014 (Total measured depth of 15,787’)

2 mile lateral spud April 2015 (Total measured depth of 19,070’)

Piceance Niobrara Days vs. Depth


WPX is an Attractive Investment Opportunity

Core Acreage

Deep Oil Inventory

Massive HBP Natural Gas Option

Financing and Delevering Options

WPX holds core acreage in each of its basins

Decades of drilling inventory with ~4,600 quality drillable locations in the Delaware, Williston and San Juan Gallup

Natural gas holdings exposed to growing demand in western markets

Ability to efficiently finance transaction with cash flow growth and deleveraging options

Visibility to Growth High returns drive future production and returns growth


Appendix

Pro Forma WPX Hedges


Sep - Dec 2015 2016 2017

Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price

Natural Gas (MMBtu)

Fixed Price Swaps¹ 436,506 $4.06 412,132 $3.63 - -

Costless Collars 50,000 $4.00 - $4.50 - - - -

Fixed Price Calls - - - - 16,301 $4.50

Natural Gas Basis (MMBtu)

MidCon Basis Swaps 20,000 ($0.18) 5,000 ($0.23) - -

Rockies Basis Swaps 280,000 ($0.17) 90,000 ($0.24) - -

San Juan Basis Swaps 107,500 ($0.11) 60,000 ($0.19) - -

SoCal Basis Swaps 50,000 $0.08 17,500 ($0.03) - -

Permian Basis Swaps - - 10,000 ($0.19) - -

Crude Oil (bbl)

Fixed Price Swaps¹ 30,433 $85.45 25,049 $62.23 5,554 $65.30

Crude Oil Basis (bbl)

Midland Basis Swaps 3,770 $0.30 5,000 ($0.45) - -

1 In connection with several natural gas and crude oil swaps, we entered into swaptions with the swap counterparties granting the counterparty the right, but not

the obligation, to enter into an underlying swap with us in the future. Natural gas swaptions for 2016 total 90,000 MMBtu/d at a weighted average strike price of

$4.23. Crude oil swaptions for 2016 total 8,500 bbl/d; 3,250 bbl/d at a weighted average strike price of $62.81 and 5,250 bbl/d at a weighted average strike price

of $97.55. Natural gas swaptions for 2017 total 65,000 MMBtu/d at a weighted average strike price of $4.19.

Updated: September 1, 2015

Williston Overview

~87,000 net acres

► Currently operating 2 rigs

► 2nd rig in August, well-to-well contract

► 3rd rig in November, well-to-well contract

600+ gross drilling locations

► 520 operated drilling locations

► 90 non-op locations

Commodity mix

► 87% oil

► 7% natural gas

► 6% NGLs

Available sales outlets

► Clearbrook, Minn. (WTI)

► Guernsey, Wyo. (WTI)

► Local refining markets

► Rail to all coastal markets (Brent, LLS, WTI)

N D


San Juan Overview

~232,000 net acres ► Oil window: ~100,000 acres1

► Gas window: ~132,000 acres

► Currently operating 2 rigs

~3,900 total gross drilling locations2

► Oil window: 400+3

► Gas window: ~3,5002

Commodity mix ► Oil window

► Oil: 54%

► NGLs: 22%

► Gas: 24%

► Gas window ► Natural gas: 99%

► NGLs: 1%

Available sales outlets ► Oil: Local refining markets or rail (WTI, Brent, LLS)

► Gas: Blanco Hub

DRY GAS

WET GAS

OIL

1 Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4,600' laterals


Piceance Overview

~200,000 net acres ► Currently operating 1 rig

~10,000 gross drilling locations

Commodity mix1

► 2% oil

► 77% natural gas

► 21% NGLs

Available sales outlets

► San Juan

► Rockies

► California

► MidCon

Unbooked deep resource potential

► Niobrara/Mancos: ~160,000 acres

► Dry gas

CO

1 Assumes full ethane recovery


$59

$51

$46

$48

$50

$52

$54

$56

$58

$60

2Q'14 2Q'15

$78

$69

$64

$66

$68

$70

$72

$74

$76

$78

$80

2Q'14 2Q'15

$68

$56

$0

$10

$20

$30

$40

$50

$60

$70

$80

2Q'14 2Q'15

Cost Continue to Trend Lower

LOE

GP&T

14% Decrease

G&A1

10% Decrease

18% Decrease

12% Decrease

1 Excludes one-time expenses associated with Early Exit Program (2014), Severance and Relocation (2015)

$(10.92)

$(7.62)

$(12.00)

$(10.00)

$(8.00)

$(6.00)

$(4.00)

$(2.00)

$-

2Q'14 2Q'15

Oil Differentials

30% Improvement

$ in

Mill

ion

s $

in M

illio

ns

$ in

Mill

ion

s


Strong Well Results Validate Delaware Core Position

Winkler

Eddy

Culberson Reeves

Loving

New Mexico

Lea

Texas

Anadarko McKnight 54-1-29 (4,000’ lat.) IP(30): 1.020 bbl/d Avalon

EOG Brown Bear 36 State #701H IP(30): 2,915 Boe/d Wolfcamp

RKI Jackson Unit 019H (4,320’ lat.) IP(30): 1,280 Boe/d 2nd Bone Spring

EOG State Magellan 2H (4,868’ lat.) IP(30): 1,027 Boe/d 2nd Bone Spring

EOG Brown Bear 36 State #502H IP(30): 2,125 Boe/d 2nd Bone Spring

EOG Gemini 2H (4,870’ lat.) IP(30): 1,907 Boe/d 2nd Bone Spring

EOG State Galileo 6H IP(30): 2,252 Boe/d Avalon

RKI Lindsay 10-1H (4,386’ lat.) IP(30): 1,035 Boe/d Lower Avalon

RKI Lindsay 10-8H IP(30): 1,294 Boe/d Wolfcamp

RKI Bunin 4-2H (3,618’ lat.) IP(30): 1,176 Boe/d Wolfcamp A

RKI CBR 44-2H (4,120’ lat.) IP(30): 1,188 Boe/d Wolfcamp A

OXY Goodnight 27 Federal 5H (2,800’ lat.) IP(30): 935 Boe/d Bone Spring

RKI Longview Federal 31-1H IP(30): 1,496 Boe/d 1st Bone Spring

Legend Anadarko

Apache

BHP

Cimarex

Concho

Devon

EOG

Mewbourne

OXY RKI

Shell

Other Operators

WPX Leasehold

RKI Pecos State 46-1H ([3,624’ lat.) IP(30): 1,269 Boe/d Avalon

Concho Lizard Pot Federal 5H (4,431’) IP(30): 1,200 Boe/d Bone Spring

OXY Misty 35 Federal Com 4H ( 4,135’) IP(30): 1,400 Boe/d Bone Spring

Mewbourne Gobbler 5 B2PM State Com 1H IP(30): 2,400 Boe/d Bone Spring

BHP Extinction 57-T1 32 1H (4,695’ lat.) IP(30): 1,279 bbl/d Wolfcamp D

Concho Jack Federal 4H (4,021’ lat.) IP(30): 1795 Boe/d Bone Spring

Matador Guitar 10 24S 202H IP(30): 822 Boe/d Wolfcamp

RKI Burton 4 IL Fed Com 1H (4,068’ lat.) IP(30): 1,293 Boe/d Bone Spring

ANADARKO HARRISON 29-28 1H IP(30): 1650 Boe/d Wolfcamp A


Infrastructure Capacity in Place for Rapid Development

Produced water gathering system ► 174 miles of pipeline

► 200,000 barrels per day of water gathering capacity

► Current gathering: ~90,000 bpd

Fresh water transfer system ► 16 miles of pipeline

► Supports temporary system to D&C new wells

► Significantly reduces well costs

Gas gathering system ► 192 miles of pipeline

► 90 MMcf/d of gas compression capacity

► Current compression: ~40 MMcf/d

Full field accessibility to electrical power

Opportunity to improve netbacks with future oil gathering build out

Future Oil Gathering Pipeline

Fresh Water Pipeline

Gas Gathering Pipeline

Produced Water Disposal

WPX Leasehold


2014-15 Reported Daily Production

2014 2015 1Q 2Q 3Q 4Q Total 1Q 2Q 3Q 4Q Total

Total Production

Gas (MMcf/d) 795 791 746 742 768 705 675 690

Oil (Mbbl/d) 19.3 23.7 25.8 32.3 25.3 34.6 32.7 33.7

NGLs (Mbbl/d) 17.6 17.9 17.1 15.9 17.1 16.9 19.7 18.3

Mboe/d 169.4 173.4 167.2 171.9 170.5 169.1 164.8 166.9

Note: Excludes discontinued operations (Powder River and International production)


Domestic Price Realization for 2015

Gas ($/Mcf) Oil ($/bbl) NGL ($/bbl)

1Q ’15 2Q ’15 3Q ’15 4Q ’15 1Q ’15 2Q ’15 3Q ’15 4Q ’15 1Q ’15 2Q ’15 3Q ’15 4Q ’15

Weighted-Average Sales Price $2.90 $2.40 $38.34 $49.64 $22.74 $20.40

Revenue Adjustments1 $(.28) $(.32) $(.70) $(1.04) $(7.34) $(6.64)

Hedge Impact – – –

Net Price2 $2.62 $2.08 $37.64 $48.60 $15.40 $13.76

Realized Portion of Derivatives Not Designated as Hedges3 $1.05 $1.02 $29.49 $24.92 – –

Net Price Including All Derivatives

$3.67 $3.10 $67.13 $73.52 $15.40 $13.76

1 Natural gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(1.40). 2 “Net Price” equals income statement product revenues by commodity, divided by volume. 3 Represents the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes.


-2.00

-1.50

-1.00

-0.50

0.00

0.50

2006 to 2010 2011 to Now 3 Yr Fwd 2006 to 2010 2011 to Now 3 Yr Fwd

Western Prices Have Increased Relative to Eastern Locations

($1.76)

($0.19) ($0.24)

$0.33

($1.06)

West Basis Strengthening1 East Basis Weakening2

$ p

er M

MB

tu

3 3

1 Northwest Wyoming/Rocky Mountain basis 2 Dominion South basis 3 3-year average strip price as of 7/27/2015

($0.42)


Mexican Exports to Drive Western Demand Growth

W. Texas 3.1 Bcf/d

S. Texas 3.64 Bcf/d

Bentek Sourced Export Capacities

Costa Azul LNG Facility

Total Current Capacity

7.4 Bcf/d July 2014, El Paso announced 21 Year deal with Mexico’s CFE to provide up to 500 MMBtu/d of firm capacity from SJ basin to Mexico border beginning Nov. 2014.

North Baja 130 Mcf/d

Sempra and Pemex recently announced coordination for the potential development of LNG exports with assumed capacity of up to 1 Bcf/d.

Sept 2014, CFE outlines two pipe-line projects sourcing 2.5 Bcf/d from Waha, Texas, by 2017.

Colorado Interstate Gas Co El Paso Natural Gas Co Kern River Gas Transmission Co Northwest Pipeline Corp Questar Pipeline Co Transcolorado Gas Transmission Co Transwestern Pipeline Co

Arizona 812 MMcf/d

Total Proposed Capacity

7.7 Bcf/d


San Juan Gallup: Gathering Infrastructure Asset Description

► WPX built multi-commodity gathering system with multiple market outlets

► Current crude oil market access to Western’s Gallup, NM refinery and El Paso, TX refinery through Tex-New-Mex pipeline

► Additional outlets by rail (Brent, LLS, WTI)

► Natural gas market access through Williams and Enterprise

► 3rd party gathering potential

System Capacity

► ~220 total miles oil, natural gas, and water infrastructure by YE2015

► Existing CDPs with current storage of 10,000 bbls for water and oil

► Western’s Tex-New-Mex takeaway capacity of 65,000 bbls/d

► Western adding additional rail capacity

WPX CDP site

WPX constructed pipe

WPX planned pipe for 2015

Western Refining (oil pipe)

WPX leasehold

Western dedicated acreage


Williston: Van Hook Gathering System

Asset Description

► WPX built multiple commodity gathering system

► Access to utility grade power

► 2nd Bench Three Forks upside

► 3rd party gathering potential

System Capacity ► 45 miles of oil, natural gas and water

lines

► 30 mile expansion complete by 3Q, 2016

► CDP with 7,200 bbls crude storage and 1,600 bbls water storage

► Gas market at Whiting CDP

► Multiple crude oil markets through Slawson


WPX planned pipe

WPX Leasehold

WPX CDP Site Whiting CDP

Van Hook CDP


Piceance: Water Treatment System

Asset Description

► WPX built produced and completions water handling system

► Three water treatment facilities located in basin

► ~400 miles of water pipeline infrastructure

► System designed for 10 + rig program

► 3rd party water service opportunities

System Capacity ► Three water treatment facilities

► 18,700 – 37,400 bpd capacity per facility

► Disposal capacity of ~22,000 bpd

► Total storage capacity of ~1.9 MM bbls


WPX Leasehold

The Valley

The Highlands


Non-GAAP

WPX Non-GAAP Disclaimer

This presentation may include certain financial measures, including adjusted EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses), that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission.

This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare a company’s performance. Management believes that these measures provide investors an enhanced perspective of the operating performance of the company and aid investor understanding. Management also believes that these non-GAAP measures provide useful information regarding our ability to meet future debt service, capital expenditures and working capital requirements. These non-GAAP financial measures should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.


Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2014 2015

(Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q Year 1Q 2Q 3Q 4Q YTD

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ - $ (144) $ 46 $ 227 $ 129 $ 22 $ (23) $ (1)

Income (loss) from continuing operations - diluted earnings per share $ - $(0.71) $ 0.23 $ 1.10 $ 0.62 $ 0.11 $ (0.12) $ (0.01)

Pre-tax adjustments:

Impairment of producing properties, costs of acquired unproved reserves and leasehold (1) $ - $ - $ - $ 20 $ 20 $ - $ - $ -

Impairments- exploratory related $ - $ 40 $ 22 $ 67 $ 129 $ - $ - $ -

Loss on sale of working interests in the Piceance Basin $ - $ 195 $ 1 $ - $ 196 $ - $ - $ -

Net gain on sales of assets $ - $ - $ - $ - $ - $ (69) $ (209) $ (278)

Expense related to Early Exit Program $ - $ 2 $ 8 $ - $ 10 $ - $ - $ -

Contract termination and early rig release expenses $ - $ - $ 6 $ 6 $ 12 $ 26 $ - $ 26

Assignment of natural gas storage commitment $ - $ - $ - $ 14 $ 14 $ - $ - $ -

Costs related to severance and relocation $ - $ - $ - $ - $ - $ 8 $ 7 $ 15

Costs related to acquistion $ - $ - $ - $ - $ - $ - $ 1 $ 1

Unrealized MTM (gain) loss $ 27 $ - $ (133) $ (453) $ (559) $ 30 $ 203 $ 233

Total pre-tax adjustments $ 27 $ 237 $ (96) $ (346) $ (178) $ (5) $ 2 $ (3)

Less tax effect for above items $ (10) $ (87) $ 35 $ 126 $ 64 $ 2 $ (1) $ 1

Impact of new state tax law in New York (net of federal benefit) $ 9 $ - $ - $ - $ 9 $ - $ - $ -

Total adjustments, after-tax $ 26 $ 150 $ (61) $ (220) $ (105) $ (3) $ 1 $ (2)

Adjusted income (loss) from continuing operations available to common stockholders $ 26 $ 6 $ (15) $ 7 $ 24 $ 19 $ (22) $ (3)

Adjusted diluted earnings (loss) per common share $ 0.13 $ 0.03 $(0.07) $ 0.03 $ 0.12 $ 0.09 $ (0.11) $ (0.02)

Diluted weighted-average shares (millions) 205.2 202.7 207.5 206.3 206.3 205.9 205 204.6

(1) These items are presented net of amounts attributable to noncontrolling interests.


Reconciliation – EBITDAX (Unaudited)

2014 2015 (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD

Adjusted EBITDAX

Reconciliation to net income (loss):

Net income (loss) $ 19 $ (133) $ 66 $ 219 $ 171 $ 68 $ (30) $ 38

Interest expense 29 28 31 35 123 33 32 65

Provision (benefit) for income taxes 13 (82) 25 119 75 13 (14) (1)

Depreciation, depletion and amortization 193 202 201 214 810 216 227 443

Exploration expenses 15 54 28 76 173 7 6 13

EBITDAX 269 69 351 663 1,352 337 222 474

Impairment of producing properties, costs of acquired unproved reserves and equity investments

- - - 20 20 - - -

Loss on sale of working interests in the Piceance Basin - 195 1 - 196 - - -

Net gain on sales of assets - - - - - (69) (209) (278)

Net (gain) loss on derivatives 195 17 (148) (498) (434) (105) 71 (34)

Net cash received (paid) related to settlement of derivatives

(168) (17) 15 45 (125) 135 132 267

(Income) loss from discontinued operations (19) (11) (20) 8 (42) (46) 7 (39)

Adjusted EBITDAX $ 277 $ 253 $ 199 $ 238 $ 967 $ 252 $ 222 $ 474


Disclaimer

The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company’s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized.

Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based (1) upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change.

There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein.


Reserves Disclaimer

The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC’s website at www.sec.gov.

The SEC’s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.


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