scotia howard weil energy conference - amazon …...scotia howard weil energy conference- march...

March 21-22, 2016

Rick Muncrief, President and CEO

Scotia Howard Weil Energy Conference

2

Premier Asset Portfolio Coming Into Focus

Scotia Howard Weil Energy Conference- March 21-22, 2016

WPX Profile: World-Class Delaware Position

► World-Class Delaware acreage

► Core Williston basin position

► Leading San Juan acreage

► Multi-decade inventory

► Balanced commodity mix1

► Strong 2016 hedge position

► Liquidity in place for prolonged downturn

1 Based on midpoint of guidance

WILLISTON BASIN

HEADQUARTERS TULSA, OK SAN JUAN

BASIN

PERMIAN BASIN

3

WPX TODAY

OIL NATURAL GAS


Piceance 16%

Williston 29%

Marcellus <1%

San Juan 39%

Permian 15%

Other <1%

Williston 28%

San Juan 21%

Permian 51%

4

2016 Outlook Focused on Fewer Basins

OIL NGLS NAT. GAS

67%

21%

12%

2015 20161

D & C C A P I TA L

C O M M O D I T Y M I X

2015 6 BASINS

~$657MM

20161

3 BASINS $395MM

► DELAWARE RECEIVING OVER 50% OF CAPEX

► MAINTAINING OPERATIONAL MOMENTUM

► FLEXIBLE CAPITAL PROGRAM

► MORE NIMBLE AND FOCUSED

► BALANCED COMMODITY MIX

► MAINTAIN STRONG LIQUIDITY


39%

49%

12%


0%

20%

40%

60%

80%

100%

Oil Natural Gas

WPX Pro-Forma Liquidity, Hedges and Debt Maturities

Pro-Forma Liquidity

Cash and Equivalents1 $41

Senior Notes Due 20171 (304)

Revolver Balance 1 (355)

Sale Proceeds 1,200

Net Proceeds 541

Undrawn Credit Facility 1,025

Total Pro-Forma Liquidity $1,607

1 Balance as of 2/19/2016

5

Pro-Forma Debt Maturity1

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Expect $1.2B OF

SALES PROCEEDS

IN 1H OF 2016

$1,485 UNDRAWN

$60.85

% o

f P

rod

uct

ion

Hed

ged

$3.79


20162

$500

$1,100

$500 $500

$0

$200

$400

$600

$800

$1,000

$1,200

2016 2017 2018 2019 2020 2021 2022 2023 2024

$M

M

STRONG HEDGE POSITION

Oil: 22,804 bbl/d Hedged

► $50.71 per barrel

~75% of oil production hedged

► $60.85 per barrel

Natural gas fully hedged

► $3.79 per MMBtu

20

17

20

16

2


$4.24

$3.78

$3.50

$3.60

$3.70

$3.80

$3.90

$4.00

$4.10

$4.20

$4.30

FY 2014 FY 2015

-$10.61

-$7.16

-$12

-$10

-$8

-$6

-$4

-$2

$0

FY 2014 FY 2015

$5.28

$4.59

$4.20

$4.40

$4.60

$4.80

$5.00

$5.20

$5.40

YTD 2014 YTD 2015

$3.92

$3.58

$3.30

$3.40

$3.50

$3.60

$3.70

$3.80

$3.90

$4.00

YTD 2014 YTD 2015 FY 2014 FY 2015

Cost Continue to Trend Lower $

per

BO

E $

per

BO

E

$ p

er B

OE

6

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

9% REDUCTION IN LOE PER BOE

13% REDUCTION IN GP&T PER BOE

11% REDUCTION IN G&A PER BOE1

33% IMPROVEMENT IN DIFFERENTIALS

FY 2014 FY 2015


7

Overview of WPX’s World-Class Delaware Position

9,0

00

’

WOLFCAMP B

WOLFCAMP C

WOLFCAMP D

CHERRY CANYON

BRUSHY CANYON

AVALON

FIRST BONE SPRING

SECOND BONE SPRING

BELL CANYON

THIRD BONE SPRING

WOLFCAMP A

Hydrocarbon Pay Indication

~94,000 TOTAL NET ACRES1, ~60,000 NET

ACRES NEAR STATELINE

12 PROSPECTIVE ZONES WITH 3,600++

GROSS LOCATIONS

OWNED/OPERATED MIDSTREAM

INFRASTRUCTURE

1.1+ BILLION BARRELS OF EQUIVALENT NET

RESOURCE POTENTIAL

WOLFCAMP

AVALON

DELAWARE SANDS

BONE SPRING

1 Includes ~1,000 acres in Midland Basin Scotia Howard Weil Energy Conference- March 21-22, 2016

0

20

40

60

80

100

120

140

160

180

200

Cu

mu

lati

ve M

BO

E

Normalized Days On Production

► Wolfcamp A exceeding acquisition assumptions

► Up to 6 two-mile Wolfcamp A laterals in 2016

► Completion design changes

► Reduced cost switching to self-sourcing model

► Targeting additional zones in Wolfcamp A

8

Delaware: Operational and Technical Momentum

100’ 50’ 50’

50’ 50’ 50’ 50’

PRE-ACQUISITION DESIGN CROSSLINK/HYBRID, 1,000 LBS/FT, 200-250 STAGE SPACING, 3 PERF CLUSTERS

POST-ACQUISITION DESIGN SLICKWATER/HYBRID, 1,500-2,000 LBS/FT, 200 STAGE SPACING, 4 PERF CLUSTERS

BASIN HIGHLIGHTS

Vision: 1,000 MBOE WPX Now: 850 MBOE Acquisition: 670 MBOE


0

200

400

600

800

1000

1200

RKI WPX Vision

$-

$5.00

$10.00

$15.00

$20.00

RKI WPX Vision

$0

$2

$4

$6

$8

$10

RKI WPX Vision

9

Rapid Progress in the Wolfcamp A and Just Getting Started D&C1,2 EURS F&D Cost

Vision: $5.0MM Vision: 1,000 MBOE Vision: $5.00 per BOE

43% REDUCTION

85% INCREASE

► Avg. 3,800’ laterals3

► Avg. 1,000 lb/ft. of proppant

► Hybrid completion design

► No Geosteering/3D seismic

► Avg. 4,000’ laterals

► Avg. 1,500 lb/ft. of proppant

► Hybrid completion design

► Increased density testing

► Target landing

► Avg. 4,750’ laterals

► 1,500 lb/ft.+ of proppant

► Testing slick water completion design

► Geosteering/3D Seismic

► Target landing

69% REDUCTION

RKI: 2014-ACQUISITION WPX NOW WPX VISION

1 Wolfcamp Well Costs: October 2013 August 2015 2 Current Wolfcamp AFEs 3 Per 640 acre spacing unit


Permian: Well and Economic Projections – Wolfcamp A Type Well

10

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$30 $40 $50 $60 $70 Flat WTI Oil Price

Vision: $5.0MM D&C - 1,000 Mboe

Current: $6.0MM D&C - 850 Mboe

B-t

ax R

OR

550

650

750

850

950

1,050

1,150

1,250

$4.0 $4.5 $5.0 $5.5 $6.0 $6.5 $7.0 $7.5 $8.0 $8.5 D&C, $MM

Price Sensitivity Curve Capital/EUR Sensitivity Curve

Vision

Current EUR

, BO

E

Acquisition Curve

► Lateral Length: Current 4,000ft, Vision 4,750ft ► Current D&C: $6.0MM, Vision $5.0MM ► EUR: Current 850 MBOE, Vision 1,000 MBOE ► B-Factor: 1.3 ► Crude Differential: $3.50 ► GP&T per BOE: $0.58 ► LOE per BOE: $4.95 ► Avg Working Interest1: 98% ► NRI 1 : 75% ► Assumes $40/$2.70 flat price

2016 Assumptions

1 Based on 2016 Guidance Scotia Howard Weil Energy Conference- March 21-22, 2016

0

20

40

60

80

100

120

140

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190

Cu

mu

lati

ve M

BO

E

Normalized Days of Production

11

Strong Results in Williston and San Juan Gallup

1 Combined average of 6MM lb. wells and 10MM lb. wells

WILLISTON BASIN HIGHLIGHTS

► Wells trending above type curve

► Record 6.5 days spud to rig release ► Set new drilling record 5,100ft in 26 hours

► Increased pounds of sand per lateral ft. ► 1,000+ lbs from 730 lbs

► West Lybrook 6 well pad 1st spud late Feb.

SAN JUAN BASIN HIGHLIGHTS

► Wells trending above type curve

► Complete 6 well pad mid-March

► Defer remaining completions ► 17-29 DUCS at year-end 2016

► Well cost remain low1

► $6.0MM D&C

► $1.1MM Artificial Lift and Facilities 0

50

100

150

200

250

0 40 80 120 160 200

Cu

mu

lati

ve M

BO

E

Normalized Days of Production


Execution Core to WPX

$1.2B IN CASH PROCEEDS EXPECTED 1H2016

COMPLETED

~$1.0B OF DIVESTITURES IN 2015

2016 FLEXIBLE CAPITAL PROGRAM

~75% OIL PRODUCTION HEDGED IN 2016

► PORTFOLIO REBALANCED IN CORE BASINS

► RAPID EXECUTION CREATES STRONG LIQUIDITY

► CONTINUED OPERATIONAL MOMENTUM

► IMPROVING COST STRUCTURE

► LEANER AND MORE NIMBLE COMPANY

► REMAIN OPPORTUNISTIC

WPX begins 2016 from a position of strength; core assets,

proven execution, and strong liquidity

12 Scotia Howard Weil Energy Conference- March 21-22, 2016

APPENDIX

Q1 2016 Q2 – Q4 2016 2017

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

Crude Oil (bbl)

Fixed Price Swaps¹ 30,024 $61.08 29,166 $60.77 22,804 $50.71

Crude Oil Basis (bbl)

Midland Basis Swaps 5,000 ($0.45) 5,000 ($0.45) - -

Natural Gas (MMBtu)

Fixed Price Swaps1,2 413,9173 $3.63 146,5413 $3.93 30,000 $2.70

Natural Gas Basis (MMBtu)

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

Rockies Basis Swaps 199,341 ($0.21) 140,000 ($0.22) 40,000 ($0.22)

San Juan Basis Swaps 100,000 ($0.18) 100,000 ($0.18) 32,500 ($0.16)

SoCal Basis Swaps 45,000 ($0.01) 45,000 ($0.01) 10,000 $0.00

Permian Basis Swaps 32,500 ($0.17) 32,500 ($0.17) - -

WPX Hedges Updated: March 16, 2016

14

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. Crude oil swaptions for 2016 total 1,257 bbl/d at a weighted average strike price of $57.15. Natural gas swaptions for 2017 total 65,000 MMBtu/d at a weighted average strike price of $4.19. Crude oil swaptions for 2017 total 3,264 bbl/d at a weighted average strike price of $51.22. 2 Including the derivatives sold with the Piceance Basin, WPX has natural gas derivatives for 2016 totaling 412,132 MMBtu/d at a weighted average price of $3.63 and 92,500 MMBtu/d at a weighted average price of $3.22 for 2017. 3 1Q’16 reflects our historical natural gas hedge position including Piceance volumes. 2Q’16 -4Q’16 hedge volumes are impacted by the transfer of natural gas hedges to Terra as of April 1st 2016.


15

Type Curve Assumptions: San Juan Gallup and Williston

0

100

200

300

400

500

600

700

800

0

200

400

600

800

1000

1200

1400

0 1 2 3 4 5 6 7 8 9 10

MB

OE/

D

780 Mboe/d EUR CUM 780 Mboe

30 + Yrs

Type Curve: San Juan Gallup

San Juan Gallup Assumptions C

um

MB

OE

Type Curve: Williston

Williston Assumptions

0

100

200

300

400

500

600

0

200

400

600

800

1,000

1,200

0 1 2 3 4 5 6 7 8 9 10

Cu

m M

BO

E

MB

OE/

D

750 Mboe/d EUR Cum 750 Mboe

► Lateral Length: 1.5 Mile

► D&C Cost: $5.08

► EUR: 780 MBOE

► B-Factor: 1.4

► Differential: ~$8.00

► GP&T per BOE: $3.80

► LOE per BOE: ~$6.00

► Avg Working Interest 3: 96.28%

► NRI3: 77.77%

► Lateral Length: 9,600 ft.

► D&C Cost: $7.1

► EUR: 750 MBOE

► B-Factor: 1.6

► Differential1 : ~$8.00

► GP&T per BOE2: $1.06

► LOE per BOE: $6.92

► Avg Working Interest 3: 83.5%

► NRI 3: 66.4%

1 Wellhead differential of $5.11 and $2.86 of GP&T accounted for as a contra revenue 2 Excludes GP&T contra revenue 3 Based on 2016 Guidance Scotia Howard Weil Energy Conference- March 21-22, 2016

1 Includes ~1,000 acres in Midland Basin

► ~94,000 net acres1

► Currently operating ~3 rigs

► 3,600 gross risked locations

► Commodity mix2

► 55% oil

► 28% natural gas

► 17% NGLs

► Available sales outlets

► Holley Frontier’s Artesia, NM Refinery

► Western’s El Paso Refinery

► Gulf Coast

► Cushing

► Midland

Permian Overview

16 2 4Q’2015 Scotia Howard Weil Energy Conference- March 21-22, 2016

Williston Overview

► ~85,000 net acres

► Currently operating 1 rig

► 575+ gross drilling locations

► ~510 operated drilling locations

► ~70 non-op locations

► Commodity mix1

► 85% oil

► 8% natural gas

► 7% NGLs


► Clearbrook, Minn. (WTI)

► Guernsey, Wyo. (WTI)

► Local refining markets

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

N D

17 1 4Q’2015


San Juan Overview

► ~226,000 net acres

► Oil window: ~96,000 acres1

► Gas window: ~130,000 acres

► Currently operating 1 rig

► ~3,900 total gross drilling locations2

► Oil window: ~4003

► Gas window: ~3,5002

► Commodity mix

► Oil window

► Oil: 52%

► NGLs: 19%

► Gas: 29%

► Gas window

► Natural gas: 99%

► NGLs: 1%


► 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 18 Scotia Howard Weil Energy Conference- March 21-22, 2016

Domestic Price Realization for 2015

Oil ($/bbl) Gas ($/Mcf) 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 $38.34 $49.64 $40.10 $35.41 $2.90 $2.40 $2.69 $2.25 $22.74 $20.40 $17.87 $16.82

Revenue Adjustments1 $(.70) $(1.04) $(1.99) $(.31) $(.28) $(.32) $(.30) $(.26) $(7.34) $(6.64) $(5.47) $(4.90)

Net Price2 $37.64 $48.60 $38.11 $35.10 $2.62 $2.08 $2.39 $1.99 $15.40 $13.76 $12.40 $11.92

Realized Portion of Derivatives Not Designated as Hedges3 $29.49 $24.92 $31.79 $32.76 $1.05 $1.02 $0.91 $1.23 – –

--

-

Net Price Including All Derivatives

$67.13 $73.52 $69.90 $67.86 $3.67 $3.10 $3.30 $3.22 $15.40 $13.76 $12.40 $11.92

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 $(1.33). 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.


20

2015 Production by Basin

First Quarter Second Quarter Third Quarter Fourth Quarter Year to Date

Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total Oil Gas NGL Total MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE MBbls Mmcf MBbls MBOE

Permian - - - - - - - - 4.6 18.6 1.6 9.3 9.1 27.3 2.8 16.5 3.5 11.6 1.1 6.5

Williston 24.9 12.6 1.8 28.8 22.6 12.4 2.0 26.6 18.9 10.1 2.1 22.7 20.9 11.9 1.9 24.8 21.8 11.7 2.0 25.7

San Juan 8.1 117.7 2.3 30.0 8.5 125.6 3.1 32.6 10.4 131.4 4.1 36.4 8.6 141.1 4.1 36.3 8.9 129.0 3.4 33.8

Piceance 1.6 529.4 12.7 102.5 1.6 510.7 14.4 101.1 1.3 480.9 13.3 94.7 1.4 465.6 13.0 92.0 1.5 496.4 13.4 97.6

Other 0.0 45.6 0.1 7.8 0.0 25.9 0.2 4.5 0.0 23.6 0.2 4.2 0.0 21.3 0.2 3.5 0.0 29.1 0.1 5.0

Total Continuing 34.6 705.3 16.9 169.1 32.7 674.6 19.7 164.8 35.2 664.6 21.3 167.3 40.0 667.2 22.0 173.1 35.6 677.8 20.0 168.6


Permian: Infrastructure Capacity in Place for Rapid Development

21

► Water gathering system

► 174 miles of pipeline

► 200,000 barrels per day of capacity

► Current utilization: ~90,000 bpd

► Fresh water transfer system


► Supports temporary system to D&C new wells

► Significantly reduces well costs

► Gas gathering system


► 90 MMcf/d of gas compression capacity

► Current utilization : ~40 MMcf/d

► Full field accessibility to electrical power

► Opportunity to improve netbacks with future oil gathering build out

► Owned and operated

Future Oil Gathering Pipeline

Fresh Water Pipeline

Gas Gathering Pipeline

Produced Water Disposal

RKI Leasehold


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 YTD 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) $ (110) $ (1,537) $ (1,648)

Income (loss) from continuing operations - diluted earnings per share $ - $(0.71) $ 0.23 $ 1.10 $ 0.62 $ 0.11 $ (0.12) $(0.44) $(5.58) $ (7.04)

Pre-tax adjustments:

Impairment of producing properties and equity investment $ - $ - $ - $ 20 $ 20 $ - $ - $ - $2,311 $2,311

Impairments- exploratory related $ - $ 40 $ 22 $ 67 $ 129 $ - $ - $ 47 $ 29 $ 76

Net (gain) loss on sales of assets $ - $ 195 $ 1 $ - $ 196 $ (69) $ (209) $ (2) $ (70) $ (350)

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

Contract termination and early rig release expenses $ - $ - $ 6 $ 6 $ 12 $ 26 $ - $ - $ 5 $ 31

Accrual for certain future gathering obligations associated with an abandoned area $ - $ - $ - $ - $ - $ - $ - $ - $ 23 $ 23

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

Costs related to severance and relocation $ - $ - $ - $ - $ - $ 8 $ 7 $ 1 $ (1) $ 15

Costs related to acquisition and retention $ - $ - $ - $ - $ - $ - $ 1 $ 103 $ 1 $ 105

Unrealized MTM (gain) loss $ 27 $ - $ (133) $ (453) $ (559) $ 30 $ 203 $ (50) $ 16 $ 199

Total pre-tax adjustments $ 27 $ 237 $ (96) $ (346) $ (178) $ (5) $ 2 $ 99 $2,314 $2,410

Less tax effect for above items $ (10) $ (87) $ 35 $ 126 $ 64 $ 2 $ (1) $ (35) $ (852) $ (886)

Impact of state deferred tax rate change $ - $ - $ - $ - $ - $ - $ - $ - $ 8 $ 8

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 $ 64 $1,470 $1,532

Adjusted income (loss) from continuing operations available to common stockholders $ 26 $ 6 $ (15) $ 7 $ 24 $ 19 $ (22) $ (46) $ (67) $ (116)

Adjusted diluted earnings (loss) per common share $ 0.13 $ 0.03 $(0.07) $ 0.03 $ 0.12 $ 0.09 $ (0.11) $(0.18) $(0.24) $ (0.50)

Diluted weighted-average shares (millions) 205.2 202.7 207.5 206.3 206.3 205.9 205.0 251.2 275.4 234.2


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) $ (230) $ (1,534) $ (1,726)

Interest expense 29 28 31 35 123 33 32 65 57 187

Provision (benefit) for income taxes 13 (82) 25 119 75 13 (14) (52) (862) (915)

Depreciation, depletion and amortization 193 202 201 214 810 216 227 242 255 940

Exploration expenses 15 54 28 76 173 7 6 56 42 111

EBITDAX 269 69 351 663 1,352 337 221 81 (2,042) (1,403)

Impairment of producing properties and equity investment - - - 20 20 - - - 2,311 2,311

Accrual for certain future gathering obligations associated with an abandoned area - - - - - - - - 23 23

Net (gains) loss on sales of assets - 195 1 - 196 (69) (209) (2) (70) (350)

RKI acquisition costs and loss on acquired debt retirement - - - - - - - 87 - 87

Net (gain) loss on derivatives 195 17 (148) (498) (434) (105) 71 (205) (179) (418)

Net cash received (paid) related to settlement of derivatives (168) (17) 15 45 (125) 135 132 155 195 617

(Income) loss from discontinued operations (19) (11) (20) 8 (42) (46) 7 124 2 87

Adjusted EBITDAX $ 277 $ 253 $ 199 $ 238 $ 967 $ 252 $ 222 $ 240 $ 240 $ 954


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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