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.
RESOURCEONE CONFERENCE December 11, 2008 3
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
RESOURCEONE CONFERENCE December 11, 2008 4
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
RESOURCEONE CONFERENCE December 11, 2008 5
$0.0
$50.0
$100.0
$150.0
$200.0
$250.0
$300.0
$350.0
$400.0
2003 2004 2005 2006 2007 2008 Est
Ann
Cash
flow
Cdn
$MM
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
Cash
flow
Cdn
$/S
hare
Cashflow CF/Sh
Track Record
0
5,000
10,000
15,000
20,000
25,000
2003 2004 2005 2006 2007 2008 Est
Daily
Ave
Pro
duct
ion
(boe
)
0
50
100
150
200
250
300
350
Prod
uctio
n/S
hare
Daily Prod Prod/Sh
Production GrowthAbsolute & Per Share
Growth in CashflowAbsolute & Per Share
Regular year-over-year increases
Regular year-over-year increases
RESOURCEONE CONFERENCE December 11, 2008 6
Focus on Fundamentals
Deliver Performance
Emphasis on Economics
Maintain Financial Discipline
Credible Business Model
Diversified Portfolio (play types, product mix, jurisdictions)
RESOURCEONE CONFERENCE December 11, 2008 7
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
RESOURCEONE CONFERENCE December 11, 2008 8
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
RESOURCEONE CONFERENCE December 11, 2008 9
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)
RESOURCEONE CONFERENCE December 11, 2008 10
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
RESOURCEONE CONFERENCE December 11, 2008 11
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
RESOURCEONE CONFERENCE December 11, 2008 12
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
RESOURCEONE CONFERENCE December 11, 2008 13
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
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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
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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
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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)
RESOURCEONE CONFERENCE December 11, 2008 17
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
RESOURCEONE CONFERENCE December 11, 2008 20
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
RESOURCEONE CONFERENCE December 11, 2008 21
2008 Hedges
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec
SWA
PS G
Js/d
$6.00
$6.50
$7.00
$7.50
$8.00
$8.50
$9.00
$9.50
$10.00
Fixe
d Pr
ice
Cdn
$/G
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
RESOURCEONE CONFERENCE December 11, 2008 22
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
RESOURCEONE CONFERENCE December 11, 2008 23
Tax Pools
Dec 31, 2007
COGPE Cdn $148 Million
CDE Cdn $100 Million
CEE Cdn $214 Million
UCC Cdn $158 Million
Total Cdn $620 Million
RESOURCEONE CONFERENCE December 11, 2008 24
Alberta New Royalty FrameworkNRF Announced October, 2007Deep Resources programs for gas & oil announced April 10, 2008
Transition Royalty Program announced November 19, 2008
Proposed Implementation January 1, 2009
Impact to Highpine:
Jan 1, 2009: Crown Royalty increase ~45-55%, Cash flow decreased ~25-30%
Deep oil royalty adjustment will improve economics of successful exploratory wells
No new Nisku oil projects likely, based solely on DEOP
Deep gas royalty credits (NGDDP) will have application in: Ansell, Rock Creek, Tay, Wapiti
Transitional Royalty Program on new drilling for 5 years:
For oil projects TRP royalty rates of +/- 38% vs 50% under the NRF at 70C$/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
RESOURCEONE CONFERENCE December 11, 2008 25
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
RESOURCEONE CONFERENCE December 11, 2008 26
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
RESOURCEONE CONFERENCE December 11, 2008 27
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
RESOURCEONE CONFERENCE December 11, 2008 28
Prolific Play Opportunity
800 BCF
90 MMBO
90 MMBO?
Pembina Nisku
GIP
OOIP
OOIP
RESOURCEONE CONFERENCE December 11, 2008 29
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
RESOURCEONE CONFERENCE December 11, 2008 30
Improving Reliability
MM
NNGG
HH
QQII
V V
SS
WW
HHH
PPV
KK
YY
DDY
JJJ
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