Highpine Oil & Gas - imlay.com · production, costs and expenses. These and other risks are described in the 2006 annual information form of Highpine Oil & Gas Limited (“Highpine”)

HIGHPINE

Thrivingin

Tumultuous Times

ResourceOne ConferenceSan FranciscoDecember 11, 2008

RESOURCEONE CONFERENCE December 11, 2008 2

DisclaimerStatements in this corporate presentation contain forward-looking information including expectations of future production, components of cash flow and earnings, drilling and exploration plans, timing and amounts of capital expenditures and future debt levels. Readers are cautioned that assumptions used in the preparation of such information may prove to be incorrect. Events or circumstances may cause actual results to differ materially from those predicted, as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Highpine. These risks include, but are not limited to; the risks associated with the oil and gas industry, commodity prices and exchange rate changes. Industry related risks include, but are not limited to; operational risks in exploration, development and production of oil and gas and production risks associated with sour hydrocarbons, dependences on third party owned and operated production facilities, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production, costs and expenses. These and other risks are described in the 2006 annual information form of Highpine Oil & Gas Limited (“Highpine”) and other documents Highpine files with the Canadian Securities Regulatory Authorities. The reader is cautioned not to place undue reliance on any forward-looking information. Highpine undertakes no obligation to update or revise any forward-looking statements except as required by applicable securities laws.

All evaluations of future net cash flows are stated before and after the provision for income taxes and prior to indirect costs and after deduction of royalties, estimated future capital expenditures and well abandonment costs and after giving effect to the Alberta Royalty Tax Credit. It should not be assumed that the present values of estimated future net cash flows shown in the corporatepresentation are representative of the fair market value of Highpine's crude oil, natural gas liquids and natural gas reserves. There is no assurance that the price and cost assumptions used in estimating such future net cash flows will be consistent with actual prices and costs and variances could be material.

The recovery and reserve estimates of Highpine's crude oil, natural gas liquids and natural gas reserves provided in the corporate presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas liquids and natural gas reserves may be greater than or less than the estimates provided herein.

BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion factor is an industry accepted norm and is not based on either energy content or current prices.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Investors are further cautioned that the preparation of financial statements in accordance with Canadian generally accepted accounting principles ("GAAP") requires management to make certain judgements and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes. Cash flow is not a recognized measure under GAAP. Management believes that in addition to net income, cash flow is a useful supplemental measure as it demonstrates Highpine's ability to generate the cash necessary to repay debt or fund future growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an alternative to net income determined in accordance with GAAP as an indication of Highpine's performance. Highpine's method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to measures used by other companies. For these purposes, Highpine defines cash flow as cash provided by operations before changes in non-cash operating working capital.

The information contained in this corporate presentation does not purport to be all-inclusive or to contain all information that a prospective investor may require. Prospective investors are encouraged to conduct their own analysis and reviews of Highpine and of the information contained in the corporate presentation. Without limitation, prospective investors should consider the advice of their financial, legal, accounting, tax and other advisors and such other factors they consider appropriate in investigating and analysing Highpine.


Who is Highpine?

• Alberta based, oil levered intermediate

• 70% Light Oil & Natural Gas Liquids

• Concentration in the Pembina Nisku Fairway

• Conventional & Resource Plays:

exploration, development & production

• Dominate Nisku position: land & facilities

• New leadership and focus in 2008

• Growing inventory of new opportunities


Corporate Profile• Founded: March, 1998

• Listed since April, 2005: TSX: HPX

• YTD ‘08 Production: 19,843 boe/d

• Current Price (Dec. 2) : C$ 5.29 (C$14.69 - C$4.33)

• Average of 11 Analysts 1 C$ 11.25 per share 12 Month Target

• Daily Volume Traded YTD 2008: 460,000 Shares

• Shares Outstanding (diluted): 67 MM (72 MM)

• Market Capitalization: C$ 350 MM

• Net Debt (Cash) : C$ 4.5 MM

1. Range C$ 6.25 to C$ 14.00 December 2, 2008


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Cash

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hare

Cashflow CF/Sh

Track Record

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2003 2004 2005 2006 2007 2008 Est

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Daily Prod Prod/Sh

Production GrowthAbsolute & Per Share

Growth in CashflowAbsolute & Per Share

Regular year-over-year increases

Regular year-over-year increases


Focus on Fundamentals

Deliver Performance

Emphasis on Economics

Maintain Financial Discipline

Credible Business Model

Diversified Portfolio (play types, product mix, jurisdictions)


Delivering Operational Performance

1Q 2008 2Q 2008 3Q 2008

Production : 19,331 boe/d 20,486 boe/d 19,715 boe/dFunds Flow : $ 74.2 million $ 112.9 million $96.5 millionOperating Netback : $ 44.89 /boe $ 62.77 /boe $54.77/boeG & A : $1.61 /boe $1.62 /boe $1.43/boeOp Cost : $ 11.19 /boe $ 11.18 /boe $11.78/boeNet Working Capital

(Debt) quarter end: $ (133.1) million $ (46.7) million $4.5 millionHighlights:

• Improved reliability

• WW South Pool

• New compression

• Operatorship at Easyford

• Elimination of Debt

• Active Share Buyback

• Strategic Land Purchases

• Inventory of Well Licenses


Pembina Rock Creek

Pembina Nisku Fairway

Other Growth Opportunities

• Joffre• Ansell• Wayne-Rosedale Nisku Oil• Tay River Leduc Gas• Wapiti Montney Gas• Pouce Coupe Lower Doig

EDMONTON

CALGARY

Growing Opportunity Base

ALBERTA


NE Pembina Extension of the Nisku

HighpineEasyfordBattery

Future Infrastructure

HPX Oil ,16% H2S

7 m pay, 600 boepd

CPC/HPX

26m full reef

1,400 boepd38o API Oil3.5% H2S

10.5 m pay. 6.8% H2S

1,400 boepd

HPX 16-14

TD June 08

3 m pay

HPX 14-19 (100% WI)

ERCB Hearing

Sept 23 – Oct 4, 2008

Decision expected: Dec 30

West/GPX 9-1

18 m pay

HPX 9-21 (100% WI)

ERCB Hearing

June 17 – July 3, 2008

Decision: Sept 30, 2008

HPX 7-9 Abandoned

Currently Drilling

HPX 14-36-48-8W5 long reach (94% WI)


Large Resource Play Opportunity

PEMBINA ROCK CREEK

• 100 LOCATIONS (2 per section)

• 2 MMcf/day WI Production

• 5 most recent IP over 1 MMscfe/d

• Fracturing and Multi-FracHorizontals unlocking the resource

Vertical Drill locations 2009

Drilling locations under consideration

Prod Well – IP > 1 MMscf/d

Prod Well – IP < 1 MMscf/d

Horizontal Drill locations 2009


Nisku Oil - Farm in

Wayne-Rosedale

Swalwell

5.8 MMBbls OOIP

3.7 MMBbls OOIP

35 MMBbls OOIP

WAYNE -ROSEDALE

• 105 Section Deal

• 100% 3-D Coverage

• Low Drilling Density

• 2,000 m depth

• $2.9 MM/well D,C & T

• Low H2S

• 100% WI

• ~ $3.0 MM Total Exposure

• 3 wells by end of 1Q09


STRACHAN 1630 BCF

Leduc Gas – High Impact

ALBERTA

TAY RIVER 128 BCFRICINUS WEST 918 BCF

TAY RIVER • 5,490 m Leduc Test

• Up to 200 Bcf Potential (Sales gas)

• 25% Earned WI

• Subthrust Leduc Reef

• Defined on 3-D Seismic

• Risks - Porosity

• $ 7.8 MM (HPX Sh.) D & E/A

• Construction underway

• 1Q09 Spud (145 days)

SCL Limestn16-27-35-11 W5M


GRANDE PRAIRIE

DAWSON

Lower Doig/Montney Resource Play

ALBERTA

SWAN

WAPITI

SINCLAIR

POUCE COUPE

T65BC | AB

T80 SINCLAIR/POUCE• Adjacent to existing H Wells

• Nearby vertical gas tests

• Lower Doig & Montney

• Low Risk

• 4 ½ Net Sections

WAPITI• Geological mapping

• Upper Montney log plays

• Gas saturated

• 42 ¼ Net Sections

• + 300 Bcf (HPX WI) Potential


Strategic Business Plan

Leverage off the strong cash generated from the Pembina NiskuComplete NE Trend of the Pembina Nisku -Highly ProspectiveDevelop high value internal opportunities -Pembina Rock Creek ResourcesExpand into new opportunities areas

- Wayne Rosedale farm in- Tay River farm in- Wapiti Montney/Doig Resource play

Diversify away from dependence exclusively on the Pembina Nisku by increasing the range and number of new

opportunities for Highpine


Capacity for Meaningful Deals

Judicious Use Of OurCurrent Borrowing Base = $ 225 MM

Increase near-term cash flow

Increase reserve life

Significantly extend our opportunity inventory

Strategic position in favorable resources plays


Unrecognized Value

• Trading below Net Asset Value

• Improved per share metrics due to active NCIB

Free Option Value:

– NE Pembina Nisku future success

– Rock Creek program

– Wayne-Rosedale opportunity

– Tay River

– Wapiti Montney / Doig play

– Additional New Opportunities (leveraged with our Balance Sheet)


Summary

• Delivering on performance expectations

• Optimizing our internal suite of opportunities & live within cash flows

• Continuing to expand our opportunities with the right new deals

• Respecting our enviable balance sheet with the capacity to execute on meaningful new

opportunities

• Demonstrating the significant unrecognized value in Highpine with

Critical Progress in Key Strategic Areas

HIGHPINE should thrive in this environment as we focus on:

Transfer Agent Valiant Trust Company

Bankers Royal Bank of CanadaAlberta Treasury BranchesBank of Montreal

Auditors KPMG LLP

Legal Counsel Burnet, Duckworth & Palmer LLP

Independent Engineers Paddock, Lindstrom & Associates Ltd.

TSX: HPX

Supplemental Information


Guidance2008 Guidance 2007 Actuals

Production (boe/d)1 : 20,500 – 21,000 17,736CAPEX (Cdn$) : $ 175 ($ 150) million $199.5 millionOperating Costs : $10.5 – 10.75 /boe $10.34 /boeG & A : $1.60 - $1.80 /boe $1.88 /boe

YTD UpdateProduction 1Q08 ~18,000 boe/d 19,331 boe/dProduction 2,3,4Q08 +20,000 boe/d +/-19,900 boe/dDrilling 35 (29 net) wells 49 (35.6 net)

NE Nisku Exploration & Development $70 MM $ 17 MMOther Nisku Exploration & Development $50 MM $ 56 MMPembina Rock Creek $ 0 MM $ 20 MMWest Central & Other Gas Development $18 MM $ 47 MMLand, Seismic & Corporate $12 MM $ 35 MM


2008 Hedges

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Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec

SWA

PS G

Js/d

$6.00

$6.50

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d Pr

ice

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J

Gas Swap - Volume Fixed Price

Percentage of total production Net of royalties

25%

50%

75%

100%

No Oil Hedges In Place

Gas Hedges Off


2007 Results

Production : 17,736 boe/d 51% increase from 2006

Revenue : $403.6 MM 63% increase from 2006

Cashflow : $193.8 MM 52% increase from 2006

CAPEX : $199.5 MM 10% reduction from 2006

Net Debt : $174.8 MM 3% increase from 2006

Debt to CF: 0.9 reduced from 1.33 in 2006

Op Costs : $10.34/boe 20% increase from 2006

Reserves : 44.2 mmboe flat from 2006

Reserve Replacement: 120% excluding revisions and effect of acquisitions/dispositions

F&D : $30.04 boe/$30.23 boe Proven / Proven +Probable

All dollars expressed in Canadian currencyNatural Gas converted at energy equivalent of 6:1 for BOE


Tax Pools

Dec 31, 2007

COGPE Cdn $148 Million

CDE Cdn $100 Million

CEE Cdn $214 Million

UCC Cdn $158 Million

Total Cdn $620 Million


Alberta New Royalty FrameworkNRF Announced October, 2007Deep Resources programs for gas & oil announced April 10, 2008

Transition Royalty Program announced November 19, 2008

Proposed Implementation January 1, 2009

Impact to Highpine:

Jan 1, 2009: Crown Royalty increase ~45-55%, Cash flow decreased ~25-30%

Deep oil royalty adjustment will improve economics of successful exploratory wells

No new Nisku oil projects likely, based solely on DEOP

Deep gas royalty credits (NGDDP) will have application in: Ansell, Rock Creek, Tay, Wapiti

Transitional Royalty Program on new drilling for 5 years:

For oil projects TRP royalty rates of +/- 38% vs 50% under the NRF at 70C$/bbl

For gas projects (<2500m) TRP royalty rates of 30% vs 42% under the NRF at 7.2C$/GJ.

Deep(>2500m) and HZTL gas wells better under the NRF NGDDP


Leadership Team

Jonathan Lexier Strategy, New Business, IRPresident & CEO

Chuck Buckley Earth ScienceSVP Exploration

Harry Cupric Finance & AccountingVP Finance & CFO

Jim Broughton EngineeringVP Engineering

Dave Humphreys OperationsVP Operations

Wayne Gray Mineral LandVP Land


Capability

• Geology & GeophysicsProcessing AlgorithmsInterpretation

• Regulatory & Public ConsultationERCB CommunicationStakeholder Engagement

• DrillingH2S Expertise (planning/drilling)Area Challenges – long reach wells

• Production/OperationsMetallurgyMechanical Issues – ESP’sSour Fluid HandlingEmergency Preparedness and Response


Pembina Nisku

Subsurface………………………………….

Production…………………………………..

Target IP Rate/well………………………….

Target Reserves (P+P)/well……………….

Cost: Drill/Complete/Tie-in………………..

Continental LandBank Reefs

Offshore Pinnacle Reefs

Bank Reef Core Sample

Devonian (370 MM Yr), 8,800 – 9,800 ft

Light Oil +40o API / Liquids-Rich Gas

1,000 boepd

1,000 mboe

$2.0 MM / $0.6 MM/ $2.0 MM


Prolific Play Opportunity

800 BCF

90 MMBO

90 MMBO?

Pembina Nisku

GIP

OOIP

OOIP


Pembina Nisku Oil Pools by Rank

29

Milli

ons

of b

arre

ls O

OIP

Rank

1

10

100

0.1

20 40 60 800

N=86

316 MMBbls OOIP Resource

91 MMBbls Discovered

192 MMBbls to be discovered in pools over 2 MMBbls

600 sq miles

24% drilled


Improving Reliability

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HH

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WW

HHH

PPV

KK

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DDY

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TT

CCC

DDD

BB

FF

XX

JJ

LL

PP

T

EE

ZZZNN

LL

KK

IIOOAA

LLL

AAA

FFF

RRR

SSS

Keyera Brazeau River

Atco Midstream

Blaze Brazeau

Highpine Battery

Keyspan Bigoray

Baytex North Battery

West Pembina

KeyeraEasyfordBattery

Brazeau Reservoir

Buck Lake

DRAYTONVALLEY

Potential for additional compression and improved acid gas injection capacity

-- Planning; 2009

14-34 Compressor Install; reduce line pressure, allow higher volumes of gas to go through the underutilized high pressure “side” of the plant

-- Commissioned April 2008

Debottlenecking HPX facility

-- possible 2009 activity

AA Pool acid gas injection

-- online Feb 2008

6-29 Compressor Install; reduce line pressure, improve deliverability in Brazeau area

-- online Feb 2008

Planning for increased capacity to accommodate future volumes

-- 2009

Off Loading Capability to Strachan

-- Initiated 1Q, Complete 2Q

Highpine Oil & Gas - imlay.com · production, costs and expenses. These and other risks are described in the 2006 annual information form of Highpine Oil & Gas Limited (“Highpine”)

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