\CL.f u. - :E ex: e::: ~ 0 a:= 0... V) f- _J _. ..... 0.. ~ _.I LL.I :c < -l LLl t0 ..... ~ 0 V), I- _, 0 1-1' 0... LLJ I- i C -' 0 u • • EN • AL LIBRARY. .( '.•.,' NOV ,'.... ERIAL OilLf1,1ITED 0 ti;~~ -; " +:' •l's) Ul )> rrt * 00 VI ...... +:' " * 622.85747 - !34 1975 ., , V) === cC a= C, C> a= c.. I- _, 0 V) I- 0 _. .... 0... 1-C J LJ.J :c ~ _, _J I- t-t 0 _. 1-C c.. < _, f- C) V), Lu I- LLl 0... >- ~ 0.. . -~ - J. , • • • . •··. · J . '\ . ' .· . .· ' •:' ' I · , ,, ........ ·.: •' : · , ,...,., • , . .• ..,}••.:.· ~. -.•,:.;'', ~...;.':-; '·•.•. I·.-_: ,·•.: .:., ·•"'.'"".:-·ill.,., I .,,,, I ' \ \.. t . ,.. • •. 1,, · ' . .. . I I I. \ . ··. . . ' :, ; .. . . ' ~ • :, ,. • • ' .• , . ; 'f . o; •, l r· sa \t - I ~ . . 0. o •-::; f ' ' . ¾. . . ./ . . . . ·. =:· ._.-~· _.· ( ::.. .· ···,·.-.:, . . • I ':,: ' \ CALGARY . • T.62 ._. .··.·· "') . .. :...,.• :· ··•....·•-.-..·•.:·.-:~-~ ?/ .· .· . tJ> . . -".' ' . .. ..•\. ,..-------•-~•·--• -- . l . OIL SANDS , J . ·. J~POSITS .. '. . . . EDMONTON .. . . (. __.·,,,.,,.,.CO l D . LA I{ E WABASCA COLO LAKE t 1 ·. ·/ PEACE-~ RIVER~ ., • . • . •,, ( • . ., , , ;:f :''.: •.:::~ -·.>;/ :~ ..:::-.i~)~:~::;:;\;:: ::;:·:;;:i>•:'· .?~ .: ; '' : ' ' 1 .. •. : .:' ,::p_!: .. . , I .. ' . . • . . ' , •I ' I·: .~ •. . .. • ... t, ·;. ,; l.: : : ' ,: • . • • \' ., . • •• • ., • . ·. • ., . ~- : . • : . •. . • 1;' .· , - . ,. r .. ~ I. '\ .\ ! • / • • --- MAP - Heavyoil deposits outline Cold Lake - Wabasca- Peace River - Athabasca Existing Imperial Oil SandsAcreage . AREA RIGHTS* MACRES IOL INTEREST - % PRIMARY TERM : COLD LAKE ATHABASCA - IN-SITU - MINING PEACE RIVER 5 OSL 193.5 100 1989-90 16 OSL 545.8 33 1/3 1982 2 OSL 66.2 25 1982 16 BSL 624.2 6 BSL 187.6 l OSPP 4 P&NG LEASE GROUPS - 33 1/3 30 1980-81-82 44.8 - · 50 1976 85.8 100 1981-85 TEXT - Cold Lakeheavy oil sands underlie an area of 2.4 million acres. - ERCB estimates oil in place at 164 billion barrels, - Imperial oil sands leases cover 193,500acres. - Imperial estimates 011 1n place in these leases ~t about 45 billion barrels, * OSL Oil SandsLease BSL BituminousSandLease OSPP Oil Sand Prospecting Permit P&NG • Petroleumand Natural Gas 1981-82 -:::.:.::=.=-- •• CROSS SECTI .ON • COLD LArS.E-s ·ANDS .J .. <~i. s.w. I ·:'; . .' N.E 1000' :r: 1200' t w 0 1400' ti) ::> 0: 0 ww -~ ~ o t- ...J UJ CZ: ·• '·e• (..) ,-.: .,, I , ...;.,,...-. ✓ .-- i 2 ,·S· 'ji > w Q ,/ ' , I .•,:.i ··.•.;- .... "'\ 1~;" , •• ., : / • ..,.1• .. ,, . ... · • . :;/r;:::;i :,i:;: tii>::,:-.'<:\:t:I: ': ii:/{ :(, ;.~: .:..,................... ...... .... ........ ...... .......... ........ 1/ I , ., , -, ~;~ ~A~Os'. ,.···.·. ::· ·. -c·.:0.J· ·t>:~: ./·..i..... ;.-. .r'..-,:l':··· :_;.,·:' •,y•.·,,,d l ,....... .,,<._ 1,l •,• t,1 ::;·. , , .,·111•' .... ..... 1' _i • ' ::::;;;:,: ~.:::: :••<· .'' ,,,. l fO MILES i,,wcrrn:rN:11 ;'• . i::;~:;; :i .:,.:.' :'.;; ,i.:!;:;:/_: \?:;:~;::;:J/) :!;~~; :[: ·; :~ // · ··:··- 0 -.-"'"": ·f ,·~. ·• • I .... ,::,.;": i ; ,_.\i i z '. "'.... v· .. , ·,· ' ,, . :'. ,. •:: . ,. I. .... . -~ .. .... .. 1 • •• ... \.::·:·,'"• ... ' '· .· ,. f '. I• /.·i '' ~- '~• ---.. '"" • .. , CROSS SECTION Section•throuph Imperial Leasesas shown or,and "' 0eoth -TEXT zones .. 1100 to 1800 ft,, Four separate zones of sand d_eposition. .. Imperi al designation . A, B, C, D, - ERCB desi9nation - UpperGrandRapids, LowerGrand Rapias, Clean1ater, ~c~urray Variablerock properties in· each zone Sand thickness and vertical continuity .. Occurrenceof underlying water · • Presenceof pa~ (irain size distribution - Permcabili_ty and porosity .. Structure control1ed by ·underl.vi np formations - Devonian (Woodbend/BeaverhillLake) . • Indications of fluid property variations_ ~ . Imperial activity concentrated on c-zone- 1500" l65q fts ..... ' -.~ '' .' ., ,·, · I I I I .' . • . COr:tPARISON OFOILPROPERTIES ; . .... I' . •O .' COLD LAKE "C11 UNITSAND -ATHABASCA 0 GRAVITY API 8 .. 10 ...-? :1•03 .. SPECIFIC GRAVITY 1.Ol \ '· . ' VISCOSITY -AT RESERVOIR CONDITIONS, C.S. :- . . REDWATER D-3 CARnONATE 10 - 12 35 1.0·- .99 .05 . 100,000 - 3,000,000 10.0,000 3. l I , •, SULPHUR % · 3 • 5%. · , .... -· ·· • l; f KEYFACTOR FORRECOVERY IS VISCOSITY .,:.: • ·' ., i I. ;• ,,' . .. 4.4 • ., ...-:. . , . . • ;' • • 2.7 ,. ,.. I ~ .l ' I ; .:.: !. "/ ~ ..,... ;,. •· . ' i • • : •~ '~, •~ ! I •i •I ' 1 :• :,,J _.,:.~·rl ~.-. ~ ·.,: ·. ~ i:• ; . ·-· ··' .! ' t . •.. . 1/· ·~, 01 , .,._ I • . '• ; ; . ., ·:i;;, 1 f • •• r • ."• ;•; • .•·· I • . • . • ~ ; . :::_>f :·t;;:_:; ".::·_;},, ,·,'.;' • ·"• -~-• ;- ,,: _- • f ...·.,, '·· II . .... ..... ., _:__. .... 3 ·. :. ··• _.,, __ . , ! OILPROPERTIES COMPARISON {P_hys1cal1 Properti _es·) TEXT l I •. -Most 011... is 1i ghter than water, .. i.e. fl oats ; ....•~ -Cold Lake oil is» in fact, heavy- . i.e. water can float on it -APl Gravity 10 - 12 degrees Specific Gravity! leO - 0.99." Essentially sameas water t ~ I -Cold Lake oil is very thick Mor viscous -In ·the Reservoir the Viscosity is 100,000 times that of water -i.e .. Viscosity o_f 100,000 centistokes -Cold Lake oil contains sulphur - avera~e 4.4% by weight KeyFactor for Recovery 1s Viscosity ' ! . . . . '}. ,, ' ... ~ ,·, .. .. .. ' ---- -· I t 10,000,0001 1,000,0001 I too,ooo I 1o, o Oo lJJ :i..c: • •·1 VIS cos;'"'( Its ATHA BAS .CA M I L D RED LA K E) .)t' ( KERN RIVER (CALIFo) v, .-.,.. - . () ~ . •• 8 I COMP fJ~nISO i~ I i- + ORINOCO TAI? BELT . (Vl:NEZUELA) lOOOl---------'--~k-~-:.-.--l----1----1-----1---t----t---t---t V> w u . MIDV/AY--SUNSET · 10 0 . ' (CALIF~) -~-:f::__4- ~-~l----t---i---t---t---r---1 __ ~ LAKE V) CRUDE 0 u u, > ~ .... ~ 10'----~-----1----1----1----f----i------f~--t---t---r-~ ' . -_::. z . ~ .I. ' , ~ ,•• "j 3. O o • ~IREO \VAT ER : . · ·: It :.~. . ... I . ·:/. : :••/:/, 1,; ' •'; ·:. ~ I .0 . • 50 ·.100 ' . 1so. · 200 ·2so • 300 Jso .':.; :, TEfA p EaAT u nE - D EG ~ EEs FA Ii REN Ht:l T ' . . -:.'.\~_\' - . /,'1 I1 • I< ! ~ .-i \,:, . , : • , • . ·. •• I. • .. ' ·. :. .. ... . ·,· . _, •. - • . • • . • • ~. 400 • .. -~so soo · .. I ~- ;: 4 sso • ,_ ., • I • ! II I I I .\ - CHART Viscosity/TemperatureComparisons - · Note - LOA.. Log Scale : TEXT - - 6ramatic reduction with temperat~re1ncrease • r.o~rarisonw~thAthabasca- other heavy·oils · - Comparison with conventional crude .. Redi•1atertype Recovery of Heavy.'1i1 requires improving its ability to movewithin the reservoir - Oil movement is dependent on reduc_ing viscosity Visco~ity reduction achieved by: - Heating alone - or .- Heating combinedwith - Natural Gas Injec_tion and/or ~ Solvents and/or ... Emulsifiers If""'.,,-. ... ..:._.; ....... ,.J . :, DENSITY OF COLD LAKE O.IL & WATER VS. TEN\PERATURE ... 1.020 "' " IJ .,......(...,.. .... ...._ I',.._- ·~--- 1.000 .980 -~ .... ~ "' "' " ~ r-... -- SOLUTION ~ r;:-...._It .2% NaCl (data available) ~ ~~ ~ ~ ~ ~ ~- ~ ...... ... ~ ""'~ '~ " ' " ·' ~ .960 ~ ~ ► ..... en .940 z .. . - - I'( ~ ~·"-- ' " COLD LAKE- OIL' w .-FORMATION WATER . (extrapolated) 0 ~~ ~ - ~ .920 ' " ~ r\. ~ "' DISTILLED ., ' i I t ' ·- ~...... . •0 -- 200 ◄ ..T!:MPER• ~ l t . --~E ..(0 F.) ~ . . I i I l " ~., \ ~~ \ \ ~"' ~ . ! W I •ol "~ WATER'.,JI\ 300 • V) ' ~~ I 100 -z : ~~ . . .860 I . .,_ "'" "~ ~~ I. . . >- .: r\. .900 .880 j• 400 • ·-- .J -- .. -. • ---- CHART- Density/Temoerature Comparisons - Note - Comparisonof Cold Lake crude with ~ater - Graph intersections versus temperature {60°F and 300°F) TEXT - Effective oil-water separation requi.res gravit,Y separation - Maximum Cold Lake oil-water density difference occurs between 150 - 230°F - Oil-water separation equipment is o~~rated at 200° to 220°F in the range of maximum density difference and lower viscosity r- -.T- · , /AA Y PILOT :' I r--~~ · . __ i _,'f! 06 to e I a;, / /15~ I b~ . :n'· -6 [ ~2. I VJ. 4. M • , - 0 •,· ! 1 -l ·1 · . _. , 123 .1 011 160 ~ 1 -, F,:z ,, ,, J\) 1 t 1_f:f_.l••o--!-t. 0 2 C, ! ? 4 3 I SEC. 28 ' R.3 ¼ ACRE - PILOT ·❖· If ,,ftPERI A L O I l LI f vHTED -1:r -} SEC. 27 HC. 22 T. 64 . 1 . . -,. A-,.. I~•-\ t) 1o Ac·R E · PILOT .. e .• ..,.-. . . .,....._ REVIE !4 OF PILOT\•!ORK AT COLOLAKE • .- • MAP - Well Configuration TEXT 1. Ethel Pilots 1964 - 70 1. Stimulation Pilot (10~22) - Early injectivity (4 wells) · · 2~ . 10..:acre Pilot {9-22) _ (l4 wel1s) · '\ tests and st~am stimulation ·trials - Steam stimulation evaluation ~ Well completion techniques In-Situ combustion Stimulation -Aids (natural gas) Stimulation with interwell communication · 3s 1¼ acre Pilot (15-22) (9 wells) Steam Flood Evaluation .Override flooding (gas cap)· •· Bottomwater zone flooding ,· - On-Trendflooding (NE-SW preferred flow direction ) As a result of pilot work to 1970, we concluded Satisfactory injection rates with high pressure A definite NE-SW preferred - flow direction exists . - Underlyinp water _i_s detrim~ntal to stimu1ati on recovery Gas injection --benefits-oil production " Emulsion problems can be overcomewith chemicals • In-Situ combustion causes severe equip~ent damageand emulsion. problems · 2, · MayPilot 1972 '(23 wells) \J ,, ~ :To incorporate · thP. best ideas, to date, and .~ To obtain high quality data leadin~ to comnercial operati on ., .. Conti_nuationiS' _necessary to evaluate long term performance , IJ:h_9 I. Pl~ f'f·· •' ( R.3 VI.4l'1t\. IMA.Y_AfiQ __ · ._ . tE·M ING ·-~P.fto ·ts . . ·- .. . . ..----. . .. I ·- .. ..,.. . . . . . \ ~ I 1101 :1 ·t ' :r. /2-3 0 13 ............_c:Jt.PI - ,1 ·.·.·__:, I ' . _.. ' · . •· I ··· :, , ' • ,.,·: . , , < • • • • ' :• • • •, • • • ' • 1 • ' ,,. ' . ,;:t . • •· ~;, 0 lrn 0··' . ..•.,. .''.'... . .. <. . I/ Ip . AD ·. . A :. ,.,., I . , .. I/. . .. .. ' 0.· .·.. .:'·,_ :·-' ·1/;· '.·- .· :..::' ·:J·.... ' ,-i ... ' .;. :-: ,. ..,,,: . ,.,.. '._,,. ' . I .~··· .... . ' , --·.... . . . ._._ ..··:" .. ..·· ·.. . _·. .:>--:. ..., .. ..··.. ·:..,. ·,:·; . . . ..,':. ,.· ·.: ·.._...:., . • ' .:,: ' V, · · -- /s 30 \~ '2' .·.·; · ,_.--~.-.:.=··· - 0 . ; '< : -:>-i . \ . .. · . · · 130 ,. · · . . ···· · " ·. o : :_) . ·/.. . , . , . ·. ' . /6.-28 . \ ' _· ,7- • • ., • • · ,. :' , ;19 ·· ' ::·, : , ":: ,• ·.,: _;, . • • •• . : :· '. . ,3,.-,.·,,,. . ·, • • • ., • • • . . • ; ,..... . 118 ·· ms:rc, ..·· s{'.~,;H/10-27\341 · .. I · · ·· · · · . . 'f· . . __ .;;. . •boo__ ISt'c" ___ .-.,;6 - ,,.... \'('y ~«' ·, i .,.,,.,, ./· . : ' .. / . . . . . . •. ., !T.65 •• ' . · ,.-. · • . ' . 11MILE ·· · ' ,_. /MAY PILOT I ' ·· "1 -.; . .••,· I . I ·.. ~ ·· · .. \.. .. ·_ . --..,,_ :.:·-~· :.:.:.-~;/•;·-:'>,::f:!"r;'.; . : ::_:: /,::::_. e:::,-"": .~.:·'_'; :.~ ~·: .~.:_ _. ·:-: . .. □ 1PLANT '!'E-i· H· - 127 15 IT 64 , EL . I .. I .·.··-..,.., , /LAKE .,... . -.. ,,I • • MAP - Mayand LemingPilots TEXT - LemingPilot - 1975 ... To prov·ide a better statistical basis for a commercial (56 wells) schemebased on steam stimulation, well pro~uctivity, oil · recovery, operating cost - To evaluate newdrilling, concepts. completion, designs and operating · -supply 4,200 BPDto ·strathcona Refinery - -Capital cost• · $15 million ..,,·Operating cost -~ $1.9 million/yro [1975}. •- Consists of 8 pads of 7 wells each on 7el5 acre spacing - A seven~spot pattern with 600 feet between wells · ~ 1,040 feet ___ _f)_etw_~e_n_wel_l_s_Jn ___t~e. _dj~e~_t1_onof pre_f~rred _Jr:~cturing .. p _----~ 600___f~_e;t __ Q.~tweertweU s__ac;r_os _s___t_r~D~ ..... . __ " . ~-- · CRUDE TREATING PLANT COIL- WATER - GAS SEPARATION) OIL ·si-oRAGE OIL ~~,_L_ ··--~~~~::~~ c~ J...---,,... ti) 'i:M'> .. <( (!) DISPOSALWELL ;. 0: w t- ..J < ~ 0 t-------=si'---- + ..J GAS SUPPLY WELLS ·o w ----- 0 ti) a: (!) :) <( (..) SCHEMATIC DRAWING 0-F ' COLD LAKE PRODUCTION PROCESS INJECTION PRODUCTION WELLS l l STEAM ...___ V I . (';. 1·•', · _. ... . ·. · • ·...: ~ ;. • • • .",~r;:<• :'•>:\- ' . STEAM GENERATION ; .. ~ . - . . ·<-., :, · ... . ~·., ·. .··.· .. · _- _; :, . :: ~ . , ~ ... ~ ,, '··.-:" i .. ,_,. ..... -- ... t, I \, '-. f::!~' ".; :;, . :, ·, · ..t,yA~~ ·· :·_\:',:··:·'.·._:_:· . ·'. '. ~ -~·,' ... . . -'i ;·· ·~. _. · ":.,.:y--:-.. ,.-·.•,:.:. :,:, : .. •, ·, ·. , . :.' ,,... -~ 'C' ZONE (MANNVILLE SAND) ' " .. <:•/ .'' • ·..,• _, : I ~ • -.';, ~ • :-: •\:. >\_\ ·.~·>;;.' : .·:· ·:';~ :>;' .... ::~f•;,.;: •:;?~ ::/·• . ~-.:.'.-·_-:~-~ :,:l: :; \/ ;:j•:-'. (/:::· ·/''.. ' '.'. .::- :'.~ ::;•• ·:;':'.:;::::>•:·~ '.:: :;:) ·•. ! \ '· :...'·; '• MARKE • CHART - Schematicof Pilot Facilities ...- • ~ TEXT- Refer to ProcessFlowDiagrams RawWater - treat andmanufacturehigh pressure steam ~ use produFed011, natural gas as fuel Inject steam, natural gas into ProductionWells Place wel.]son production after suitable heating cycle Separate oil, water and natural gas at TreatmentPlant Oil to storage - truck to market burn portion as ·fuel Gase Inject with steam Burnas fuel Water- Disposeintd water bearing.formation a J l __- ~ ~. I& , .CAS ISJl~•:ON ,. ,, ----------4 WATER I • OlSPOSAi ,,_ __ um111 S!UM BOILER QEAEMTOll SOFTENER , ....,. _______ t~MING f'~ANT •$CJiEMATle wms .,____ ..., , ,..INJ:CTION ST,>-14 ~ '-- ' ~ ....._-.,,.· TYPICAL LEMIN·G WELLCOMPLETION L••60' SURFACE PIPE10¾ 1.iOO' CASING5½ N8O 20# /FT, BTC • TUBING3½ J55 EUE9.3#/FT, 0 < . .,,;..;~· ,..:.--:-•·. (i 'J "• . \ ·' -~ ;) -1 ; • _ . _ . .. . , . r ____ ;; ·y_ - __ ,•-... . .,,, .._,,,., -., -. ~--. • • • .,. ,_ ' . • -• .- - 77 I· • .- ..... 4 ., J_.- r : : ' ,,,,; , ",,, . .·, I' ·,-::d • ·•: -. 600'•--------:i • ·, .; . 1•,,, . f;".• .. !~~'·L\~ ..).. ': J (;,; f . ;} 1°::'qlL 160' . • t• • • I ,.., .,J -: •· ~.-:: -" - : ... ; I -.~ . : :·• ..· .... ,".,'1 . . · .i l.. I tJJ ,, -4 • -• ' .. ·; , i . 1' ' 11'• ·~ ,, . ., .,I • 1 I • • , , : .. , t " ·• ·-· , • ~•"""':"''" ·"l,,.) ,, ,,,1..!, ..,I, , •. ' _. ., : ,_;4. 1 \• ,. " t ~ t ;-.• • !i J _V<, .; l I .,,.i..r•~ :;... •., : ;1 -L ·, '· "" I·• ,•1· • . . I• :' ·, ~ •• • :, . ':. I .... ' •, .... ,:: , . . \' ,' . .... ·. . :··, .' .•• : ' ·,:•:·.~ '•' 1 ... •· ,; • ·• •• . JI ,. , ~ '., ,~:.~: . ,'·r,~~;,:;::,' .,' ... ' I·:. ~:· ·:..·.: ~ ~-. i ~ .. -..'.'. .'....,....-,.',._... -- .. .• ...,..--. ! . ,I I , \' .. 1· 'I ~,: .' ; - • .:• ,, .• I!.. • .. -· • '. . ' '• . _,, ...., --- " PUMPJAC:~ • , WtLI. t ♦ i ♦I I i ♦ I 1 #3 #◄ #I #a #J . ~ VENT ·SCRUaBU L~ ' I • #2 111111n I I- I I I I r l +( : #1 :I I I I J J I OAS STEAM I • SAT. BLDG. I~ _l-.. PRO0'N. SEPAc._ TEST ' SCHEMATIC OF LEMINGSATELLITE TYPICAL LEMINGSATELilTE.'.f · :-'1 , '·) •• 1 -.~ ji \: t/ ~ ~- LEASE "- --__,. .. ....,,,,,~ ...,, - - =~ ._ . . : · : . TYPICALSTEAM STIMULATION PERFORMANCE . . .. ' . \~ ,.. ,1 ,''J '· ·;. .. :• ;f·' , .• i /· i '·..,.,..: ·.... · 400 J ••· • ••• •._... i .-; •I . ~ I ·.·· ~ l :300 ,... I J . ····- - INJECTION STEAM GAS ' ~ 200--· 45,013 INJECTIONi 4i992 l I . i . ' OIL I 1 20 , 40 1 c; a , GO .3,818 a 80 . •1.·,.,_ :"' I ) 1 ·. 120 ..• 100 .t • .. 1 , ' .! J. , , . . ,:• .··• ..•. • ~ • ·. • ~.. .: ' .. ) 1 • · • j· PRODUCTION OIL . WATER 1 , BBLSj' . ! I , l . 180 •· _:_.i 200 ~ )' • ' ··,i· .t , .... .- •: ; . 8 ·, ~ ., ,! i . i ', j , 20,413 . 1 220 : • ' .1 I :.: •• . . ··. . , 1 ·· .. ·,. BBL$ 12,737 . , t . 240 ...:~. 2GO 280 ' . . .. .,~ .' 'i , • · . 140 : : .. . 160 ' ! ... ·, • , DAYS ·. , I ~ ' BBLS . . ..···• . 88LS · . ,. l ' . ,:;.. ;.,.:· .• ,.' .l -.·•.. ! .' ... . •... i. '. ." ._'I .l. I ·:·l ····r ,. ·->-·.. .· · WATER·• 14,530 S,O25 0 PRODUCTION ; . ·,· . • ,. MSCF)---1 60,310 c... •. i . ·1 100 1 · GAS J-e-~ BBLS f 0I ; • I STEAM MSCF -+ OBLS ) . ••i 1: ,-..·. ! < I • ..• .. • • -· - RECOVERY AND RECOVERY RATE ' CHART - Typical SteamStimulationJerfor~ance TEXT - SteamStimulation - Present Process - Injection/Production cycle performanc~dependent on: - Ability to distribute heat in the formation - Amountof heat injected. influences: - ~ate of recovery - Ultimate Recovery- avera·ge well recovery of 100 M.barrels by stimulation over 5 years - Stimulation Aid - Natural Gas Injection -- O_pera ting Cost - SteamDisplacement - - Involves establishing corrmunication ·of the injected steam betweenwells through the formationo Continuousinjection will displace the oil from the formation into producing wells, This technique sho~ld significantly improverecovery of oi1 in placeo . - There are several . . .unresolvedparameters . . - Maximum well spacingdimensionto permitcommunication ~ Optimum steam rate, producti~nrate, we11spacing - Water/gaszone~. .,...,, ~ ,, ~ .. ,.. -...-... - - - -~-- --~·- ' . NEARTERMPLANS -. •,., 1975 ..._,... l_ ' Drill and equi,p 14 additional wells at Lemingto maintain deliverability in 1976. Continue data gathering and analys_is .of May Pilot Performance Obtain results' analyze . l ,' LemingPil~ot P~rforma 'nce ' Increased emphasison thermal and production efficiency Screening studies and evaluation of alternate recovery processes 1976 Drill 19 additional wells to maintain deliverability -in 1977 and 1978 Preliminary engineering for newrecovery processes .... - . -- ·-··-.. .lfil - -- · Construct one or morenewrecovery pilots : rJ ,· ' , ·· ...; ...~ ~.1. ·~} : I(., ;\ r' ' C j C· ~ 'n . ., .?-:~ "J~ . ;.~' ~~;.:.:~~: :·:~~:: ...1 · ;;, ._ . .\ ,(, , ·, ,. ... t .. ·, } ., I • '• •~ • I :.: • .. •J ~~ :·i_ ..... •-·~.' .- h ) ' ~ ' ·•·-, • • SUMv1ARY Although costly, techniques for heavy oil recovery have been demonstrated Current pilot operations are directed at establishing - Production rate capability Resource recovery - Improvedthermal and production efficiency Continuing research will examine - Newrecovery methodconcepts Laboratory studies Field pilot demonstrations of newconcepts Commercialschemeswill be dependent on • - Improvedtechnology - requires lead times of 10 to 20 years Higher crude oil prices Reasonable sharing of revenues b~ Governments Longterm stability of GovernmentRegulations A reasonable profit motivation · • ◄- Industry Review D~KINl"N SECURITIES HARRIS THE HEAVY OIL DEPOSITS OF WESTERN CANADA A FUEL FOR THE FUTURE GROWTH OF THE CANADIAN PETROLEUM INDUSTRY OCTOBER, 1974 THEHEAVY OIL DEPOSITS OFWESTERN CANADA A FUELFORTHEFUTURE GROWTH OFTHECANADIAN PETROLEUM INDUSTRY October, 1974 TABLE OF CONTENTS Page No. SUMMARY ANDRECOMMENDATION INTRODUCTION ATHABASCA OIL SANDS DEPOSIT COLD LAKE OIL SANDS DEPOSIT PEACE RIVEROIL SANDS DEPOSIT WABASCA OIL SANDS DEPOSIT LLOYDMINSTER AREA HEAVY OIL DEPOSITS FUTURE DEVELOPMENT ECONOMICS GRAPHS 1. SUPPLY OFSYNTHETIC OIL 2. CANADIAN DOMESTIC DEMAND FOROIL 3. SUPPLY OF CANADIAN OIL Established Areas of Productive Capacity 4. SUPPLY OF CANADIAN OIL Established Areas with Limitations 5. SUPPLY OF CANADIAN OIL Established Areas with Limitations, Oil Sands and Frontier Areas. REFERENCE TABLES I HeavyOil Deposits of Western Canada II Oil Sand Projects Data Summary III Canadian Oil Production Forecast IV, Canadian Domestic DemandForecast V Established Areas Reserves at December31, 1973 VI Established Areas Reserves and Production Forecast VII Oil Sands Project Cash Flow Forecast VIII Discounted Rate of Return Calculation IX HeavyOil Leveraged Companies APPENDICES I Current Information II Bituminous Sands Leases Ownership - Athabasca Deposit III Oil Sands Leases Ownership - South Athabasca, Cold Lake, Peace River and WabascaDeposits IV Oil Sands Permits Ownership - Cold Lake and Peace River Deposits INSERT Mapof the Oil Sands Deposits l 3 6 9 11 12 12 14 21 14 15 16 18 20 SUMMAR Y ANDRECOMMENDATIONS . The world energy balance has been seriously aggravated by the actions of the OPECmembercountries during the past year which h~ve brought the era of cheap energy from the vast oil reserves in the Middle Ea~t.t o an abrupt end. As North America strives for energy self-su!fic,ency, the development of the heavy oil reserves in Western Canada ~s e~pected to be a priority item. Conventional crude oil produc~ion_,s peaking in Alberta while Saskatchewan and British Colum~,a fields have been declining for several years. In the Canadian front1e~s the lack of a major discovery to date precludes significant product,o~ before the mid-1980 s and further emphasizes the need for accelera~1ng_the de~elopment of the heavy oil deposits. While representation 1n an 011 sands project, be it surface mining or in-situ, enha~ces the growth prospects for a Canadian oil companyit can under no c,r~umstance be considered a low risk venture or a guaranteed econom,c_success. However, the oil sands have a most important role to p~a~ 1n_the future of the Canadian Petroleum Industry and we recommend part1c1pat1on through either of the following four companies whose strong exposure in the oil sands areas, as detailed in reference Table IX, is complemented by an aggressive domestic and, in some areas, international exploration programme: 1 Imperia1 Oi1 BP Canada Husky Oil NumacOil and Gas Obviously potential oil resources do not become supply available to the consumer, and earnings available to shareholders, unless they are developed. The timing of future crude oil supply will depend upon the rate at which the massive oil sands projects can be brought on stream as well as the level at which exploration proceeds in the frontier areas. This will be subject to numerous physical constr~ints as well as the business and geologic risks perceived by the oil companies whose judgements are based upon predictions of future crude oil prices, provincial and federal government and industry revenue sharing, stability of government regulations, prospective markets, etc. There is no doubt that Canada will require significant crude oil supply additions in the near future: total deman~is foreca~t at approximately 2.2 million barrels ~er day by 19~0 while the availa~le_ supply from conventional sources will have declined to about 1.5 million barrels per day. If Canada does not wish to be faced with a serious petroleum shortage by the mid-1980's.and up to 69%dependent upon Venezuela and the Middle East cou~tries, production ~ust come from several new Canadian sources: This can_only be rea~ized through a continuation of the competitive enterprise system with a clear understandi ng of the role of the basic !actors o! price, ma~ket and share ?f reward between the public and the_investo~ if the massive sums of capital and considerable technical expertise required to develop these new re sources is to be available. - 1 - The federal-provincial confrontation over taxation of revenue from mineral resources, not only in Western Canada but also in the Atlantic provinces, must be resolved as soon as possible. This dispute has created major uncertainty in industry as well as considerable damage in the Canadian capital market which will be expected to raise a significant portion of the capital funds required. Investor confidence in the natural resource sector has been seriously eroded by the intrusion of various levels of government during the past year and it must be restored if Canada is to realize the potential of its vast undeveloped natural resources. Of particular importance to the future of the oil sands will be the Alberta Government's position paper on oil sands development which is expected within the next month. This document should spell out the ground rules for development so that serious problems regarding the environment, construction and production may be avoided. Although several new projects have been approved by the Alberta Energy Resources Conservation Board, only the Syncrude plant has received the final approval from the Alberta Cabinet. Approval came after lengthy negotiations which led to the pioneering 50%profit sharing agreement as well as an option for the government to acquire a 20%working interest in the project upon completion. Similar agreements will have to be reached for all future oil sands projects and initial developments suggest that a 50%Canadian participation may be a government goal. J. D. McCleary, P. Geol. October, 1974. - 2 - ◄ INTRODUCTION .f. tH~avyoil occurrences in Western Canada fall into two broad cl ass, ,ca ions· oil sands dep0 1·t d Ll . . depending upon th h . ~ s an oydm1nster type accumulations, t e c aracterist,cs of the crude they contain. This ~ep~~b a~sesses the potential of the four principal oil sands deposits ~~ Llera~ namely Athabasca, Cold Lake, Peace River and Wabascaplus e oydmin~ter a~ea. The Alberta Energy Resources Conservation Board (Board), def~ne~ 011 sands as those having a "highly viscous crude not recover~ble 1~ its natural state through a well by ordinary production methods · Th1s_hydrocar~on material is designated as bitumen and has a napthene base, is black 1n colour and contains a characteristically high perc~ntage of sulphur, nitrogen and base metals. Relative to the conventiona~ly produced crude oils, it is heavy, averaging about 10 degrees ~PI gravity th~oughout the Athabasca deposit. The gravity of the bitumen in the Peace River deposits to the west is similar while in the Cold Lake ~rea, the heavy hydrocarbons are transitional in properties between the bitumen of the Athabasca oil sands and the heavy crude oil of the Lloydminster area of the south. See reference Table I for a descriptive summaryof the various deposits. The total proved initial in place reserves of bitumen are estimated to be 895 billion barrels; however, the Board considers that the ultimate in place reserves from the presently delineated oil sands deposits in Alberta will approach 1,000 billion barrels. In the Board's opinion, after reviewing possible recovery techniques and deposit characteristics, the ultimate potential recoverable reserves of crude bitumen at an average recovery of 33% are approximately 330 billion barrels, and of synthetic crude at 75% volume conversion, close to 250 billion barrels. The importance of the oil sands as a future petroleum source for Canada and the United States cannot be over-emphasized at this time. Even the estimated 26.5 billion barrels of proven reserves which are recoverable via open-pit mining operation~ (i~no~ing the total 250 billion barrels potentially recoverable with insitu processes) are significant in the context of knownworldwide oil accumulations as illustrated below: Potential Recoverable Recoverable Recoverable Synthetic Conventional Synthetic Reserves Reserves Reserves Region (Billion Barrels) North America 51 Established Areas 250 26.5 Alberta Oil Sands N.A. 80 Oil Shales Central & South America 32 Established Areas 200 Orinoco Heavy Oil Belt Western Europe Middle East Africa Asia - Pacific Rim Soviet Bloc & China Total 16 350 67 16 103 635 - 3 - There are two basic and distinct methods for recovering bitumen from oil sands deposits: open pit mining and in-situ processes which must be used where overburden thickness exceeds about 200 feet. Openpit mining of the oil sands coupled with hot-water extraction of the bitumen is presently in commercial use at the Great Canadian Oil Sands operation and a similar procedure will be used by Syncrude Canada, Shell, Petrofina and HomeOil. This method consists of the following major steps: 1. Land clearing, muskeg and overburden removal. 2. Mining of oil sands via bucket wheel excavator or dragline. 3. Transporting sands by conveyor systems or trains to bitumen extractor facilities. 4. Separation of bitumen from sand by the hot water flotation process. The bitumen is recovered, dried and ultimately refined into synthetic crude oil. 5. Transporting residual sand water emulsion to settling and then moving sand into mined out area. 6. Reclamation of the mined out area to return it to near its natural state. ponds OPEN PIT MINING PROJECT PROCESS FLOW DIAGRAM ,tlMAIY IITUMEN FIOTH IOTAIY ___.. CONDIT IONING OIUMS OI L Sl!CONOAIY FIOTH SECONOAIY flOTH SETTLU SANO fUD IITUMfN FROTH 0UU0IATION IITUMEN STEAM WATEI I IITUMfN UPGIAOING SYNTHfTIC CIUDt OIL COlt ltCYCLtD WAHi SAND SLUUY TO TAILINGS POND - 4 - SULPHUI The overburden thickness in the case of a large portion of the Athabasca deposit and the entire Cold Lake Peace River Wabascaand Lloydminster deposits is too great for mining and thus fhe bitumen must be extracted without removing the sand or overburden. This is achieved by different types of "in-situ" processes. Noneof the currently deve)oped proc~sses are considered to be commercial at present. In-situ extr~ct1on may involve non-thermal techniques, principally the addition of a d1lutent to the reservoir, or thermal techniques involving hot water or high pressure steam injection into the reservoir, or thirdly combustion or nuclear explosion in the reservoir. These methods are principally . directed towards reducing the viscosity of the bitumen or heavy crud~ in order to cause it to flow to production wells where it can be mechanically pumpedto the surface. The bitumen is similar to that produced by the open-pit mining and hot water extraction technique, and is subsequently upgraded to a marketable product. IN SITU RECOVERY PROJECT PROCESS FLOW DIAGRAM V -z ~2 FIELD at< <~L____ Ou FIELD --1__________ PLANT PIPELINE HYDROTREATING ..,L. ____ _,_ ____ _ 00 IU~ 0 r-------, I I HYDROTREATING I I I I I t SYNTHETIC I CRUDE I----, BITUMEN &WATER PROCESS UNITS PIPELINE II) II) IU V 0 Qt A. EDMONTON I I ..!.!!.!:E.. WELLS STATIONS GATHERING : I FIELD SULPHUR 7 FIELD STEAM ~ L ______ I I I I .JI EFFLUENT DISPOSAL COOLING WATER 1 2 OTHERS AUXILIARI~ BLDG . SHOPS TANKS etc. - 5 - BITUMEN DILUENT AND DILUENT 3 DRY BITUMEN • SOUR DISTILLATE 5 6 7 8 FUEL WATER FIELD STEAM EFFL. DISPOSAL SULPHUR ATHABASCA OIL SANDS DEPOSIT General Comments This deposit underlines 9,000 square miles in ~orthea~tern Alberta and contains some 626 million barrels of crude bitumen in place or 70% of the total evaluated oil sands reserves. Except for localized out-crops occurring along the Athabasca River and its tributaries, t~e oil sands are covered by overburden which varies in thickness according to topography. North of township 90, in the vicinity of the Athabasca River, it is 100 feet or less, while to the east, south west and north, the thickness increases to 600', l ,500 1 , l ,600 1 and 2,000' respectively. Overburden is a major factor in determining the method to be used for recovering the natural bitumen resource. The commercial production of some 72 million barrels of synthetic crude over the past five years at Great Canadian Oil Sands Ltd., plant in the Athabasca deposit utilizing mining and surface extraction methods has made it possible to identify the proved reserves recoverable by these methods. The Alberta Board now considers that recovery of crude bitumen by mining operations is proved to an overburden depth not to exceed 150 feet provided that the ratio of overburden depth to average pay thickness does not exceed one. For the purpose of evaluating average pay, the thickness is discounted by that portion of the pay which has a crude bitumen saturation of 5% or less by weight. Of the in-place reserves of 74 billion barrels in the 0-150 feet overburden range the Alberta Board has estimated the total proved crude bitumen and synthetic crude oil reserves at 38 billion barrels and 26.5 billion barrels respectively. Three possible development regions which occur within the Athabasca deposits are illustrated on the enclosed map according to the oil sand pay thickness and depth of overburden as defined below: Mineable Area Sands underlay less than 150 feet of overburden. The bitumen occurring with this region will probably be recovered by surface mining and will continue to commandpriority attention by developers for at least the next ten years. Reserves - In Place Proved Recoverable 74 billion barrels bitumen 38 billion barrels bitumen 26.5 billion barrels synthetic crude In-situ Recovery Area Sands underlay more than 500 feet of overburden. The bitumen from this region will be recovered most probably by some fonn of in-situ technology. In-situ techniques are undergoing extensive experimentation and could reach commercial maturity within a few years. - 6 - Reserves - In Place Potent i al Recoverable 417 bill i on barrels bitumen 83 bi ll i on barrels bitumen 58 billio n barrels synthetic crude Future Development Area b rd sa nds underlay more than 150 fe et and le ss than 500 feet of o~er u en. ~evelopments in this region deferred pendi ng the evolution 0 an appropriate recovery method. Reserves - In Place Potential Recoverable 135 billion bar rel s bi t umen Not recoverable wit h present technology. Recent Developments Mineable Area . Commercial development of the Athabasca deposit has been the a, m_of sev~ral companies during the past 50 years. In 1930 the Internat1ona~ B1tume~ Companybecame the first firm to exploit the sands comm ercially which resulted in the extraction of several thousand barrels of tar. In 1936 and 1937 Abasand Oils Ltd. constructed a 250 ton-perday and a 400 ton-per-day separation plant near Fort McMurray,but both pla nts were destroyed by fire shortly after completion. The only commercial operation at the present time is the Great Canadian Oil Sands Limited plant which produces between 50,000 and 52,000 barrels per day at peak capacity. Approval has been received to expand this to 65,000 barrels per day within the next two years. In addition, Syncrude Canada Ltd. is proceeding with the construction of a 125,000 barrel per day plant scheduled to commenceoperations in late 1977 or early 1978. A third company, Shell Canada Limited, has received approval from the Board for a 100,000 barrel per day recovery project. The decision is subject to confirmation by the Provincial cabinet. The application of a fourth group operated by Petrofina Canada for a permit to construct a 122,500 barrel per day plant has been heard and a decision is expected later this year. HomeOil and Alminex are currently presenting their plans for a 103,000 barrel per day plant to the Board. Several other groups are continuing feasibility studies to examine various mining, extraction, upgrading and transportation techniques for the recovery of bitumen reserves underlaying their leases. Chevron, Union BP Canada Can-Amera(Shaheen Resources), Ashland and Ameradaare belie~ed to be a~ong those with sufficient mineable ore reserves to supply a 100 000 barrel per day synthetic crude plant. According to some observe;s the second generation plants to be built around 1980 in the oil sands may have a capacity of 200,000 barrels per day or more. - 7 - which Det a,·1 s Of th e Great Canadian Oil Sands miningdoper~tion proJects by has been on stream since mid-1967 as well as the propose Pt f. Syncrude Canada Ltd., Shell Canada - Shell Exp~orer! th e e ro ,~abl Canada group and HomeOil - Alminex are summarized 1n Reference a e I I. In-situ Area Present technology indicates that overburd~n depths should be at least 500' in order to safely contain the reservoir pressures generated by an in-situ recovery scheme. Reserves in the 500 :ee~ plus category total about 417 billion barrels, and thus some 135 b1ll1on barrels or 21% of the in place reserves which fall into the 150-500 foot ?verbu rden depth interval are apparently undevelopable pending the evolution of an appropriate recovery method. A major experimental in-situ test has been operated for several years by AmocoCanada in the Gregoire Lake on Crown Lease No. 7~.. The Companyhas invested about $9 million and plans to spend an add1t1onal $13 million on its field programme. Amocorefers to its process as the COFCAW process, meaning Combination of forward combusion and waterflood The detailed results of the tests are confidential; however, oil recoveries as high as 40% have been recorded from experimental models utilizing this process. A second experimental project is operated by Texaco Exploration on Lease No. 51, immediately south of Fort McMurray. 11 11 • In 1963, Shell Canada made application for approval of an insitu method of recovering the bitumen underlying CrownLease No. 's 26, 42, 53 and 45. Initial operations were scheduled to begin on Lease No. 53 which Shell estimated contained total reserves in producible sands of 4.4 billion barrels of bitumen while in the whole of its leases, reserves were estimated at 11.4 billion barrels. Results of a pilot programme utilizing a technique for creating horizontal fractures at the base of the oil sands followed by injection through a central well of heated aqueous alkaline solutions and steam resulted in up to 30% recovery of the original oil in place. The proposed commercial project, subject to a successful two year scaled down initial stage operation, would be designed to produce 97,000 barrels of synthetic crude per day from 130,000 barrels of raw bitumen. The applciation was turned down by the Board at that time because of concern that the conventional crude oil industry in Alberta would lose some of its markets to these new sources of supply. Ten years later the situation has completely turned around with conventional oil production now unable to meet market demands. Shell, however, has not re-applied for approval of this project. Apparently the Companyfeels that its mining project on Lease 13 is more economical ' at this time. In the southern portion of the Athabasca deposit as shown on the enclosed map NumacOil and Gas has established the presence of a thick sand body which the companyestimates contains in place bitumen reserves of 20 billion barrels or more. Evaluation drilling is continuing on this property and an in-situ recovery pilot plant may be operational by the end of 1975. - 8 - COLDLAKEOIL SANDS DEP OSIT General Commen ts The Cold Lake oil sands deposit illustrated on the enclosed map is overlain by about 1,500 feet of overburden and covers an area of almost 3,500 square miles in east central Alberta. With this depth of overburden the bitumen must be recovered via in-situ techniques. T?ta~ proved in-place reserves are estimated by the Board to be 164 bill ion barrels, none of which as yet are classed as proved recoverable. How e~er, using an overall 20% bitumen recovery factor and a 70% conver sion, the deposit could yield up to 33 billion barrels of bitumen and 23 billion barrels of synthetic crude oil. The mode of occurrence of the bitumen reserves has been classified into three broad categories as defined below: Massive or Rich Areas where more than two-thirds of the total oil sand occurs i n one or more thick zones, i.e. greater than 40 feet. Reserves - In Place Potential Recoverable 65 billion barrels bitumen 13 billion barrels bitumen 9 billion barrels synthetic crude Intermediate Embraces those areas where one-third to two-thirds of the total oil sand exists in thick zones. Reserves - In Place 83 billion barrels bitumen Potential Recoverable : 16.6 billion barrels bitumen 11.6 billion barrels synthetic crude Dispersed or Lean Encompasses the areas where less than one-third of the total oil sand occurs within thick zones. Reserves - In Place 16 billion barrels bitumen Potential Recoverable : 3.2 billion barrels bitumen 2.2 billion barrels synthetic crude The Board employed oil saturation cut-off limits as well as the thickness criteria above to exclude bitumen considered to be unrecoverable by any foreseeable technology. Weexpect ~evelopm~nt will concentrate in the massive and to a les~er extent the intermediate saturation areas which are most attra~tive for a s~condary recovery scheme at this time. Generally speaking, the massive sand areas have - 9 - a production potential of 8-9,000 barrels per day per s~cti~n (640 acres), as compared to 3-4,000 barrels per day per section in the intermediate saturation areas. Recent Developments Since late 1964, Imperial Oil has been engaged i~ expe~imental in-situ operations on its Cold Lake properties which contain estimated in place reserves of bitumen in the 30 billion barrel range. Al~ost all of the effort has been devoted to trials of steam recovery techniques. The work was discontinued briefly in 1970-71 however, but was reactivated in the fall of 1971, when Imperial built the Maypilot with 23 wells spaced about 500 feet apart on a five acre spacing pattern. App~oximately half of the wells are utilized as injectors at any one time while the balance are producing about l ,500 barrels per day of bitumen which is trucked to Lloydminster for sale. The company is now constructing a new facility called the Leming pilot on a tract of land about four miles from the Maysite. Whenthis new 56 well test comes into full production it will be producing as much as 4,000 barrels per day, excluding about l ,200 barrels per day which would be utilized as fuel for steam generation. This latter pilot will cost approximately $14 million and come on stream late in 1974. Imperial feels that a two to three year test period will be required to determine if a commercial operation using this technique is feasible. ~everal other operators have conducted experimental projects at Cold Lake in the past including BP Canada which is throught to have the most attractive acreage spread after Imperial. The companyestimates that bitumen reserves in place under its property are in the order of seven billion barrels. Great Plains, Yellowknife Bear, Mobil Oil, Texaco Exploration, Amocoand AmeradaHess have also investigated thermal in-situ recovery techniques in this deposit. The Great Plains - Yellowknife Bear team with interests of 35%and 65% respectively may have their third experimental steam injection project underway by the summerof 1975. The size is still under consideration, with in-place bitumen reserves thought to be in the range of 700 million barrels. MurphyOil has acquired interests in several acreage blocks in the south Cold Lake area and is installing an experimental thermal steam flood this year. Union Texas of Canada (a division of Allied Chemical Corporation) plans to produce bitumen from a depth of about 1,400 feet with permitted maximumproduction set a 1,000 b/d although actual production is expected to run around 500 b/d. Included in the programmeare sixteen wells plus construction of a thermal plant. Canadian Industrial Gas and Oil will evaluate its oil sands lease No. 60 in the Cold Lake deposit jointly with Marubeni Corp. and Fuyo Petroleum DevelopmentCorp. of Japan. A study _will be conducted to determine the feasibility of in-situ production from this property which could have in place bitumen reserves of 2 billion barrels. The - 10 - esti~ated $20_mi~lion evalaution programmeto be operated by CIGOLwill cons~st of dr~ll1ng 50 exploratory wells by June, 1975, engineering ~tudies and P~lo! operations. The Marubeni Group will earn a 50%interest in the lease if 1t completes $16.5 million of the total expenditures. CIGOLh~s alre~d~ reserved some key pieces of equipment for a prototype ~roduct,on fac1l1ty that would be based on the pilot plant, assuming it is successful, and would increase the experimental output of 500 barrels per day to 2,000 barrels a day of oil after 1978. The pilot projects now under construction are expected to show what th~ wells can produce on a sustained basis and permit a realistic evalua!1on of !he risks involved before undertaking a large scale commercial operation. This would probably see daily production rates of up to 100,000 barrels achieved through a number of separate recovery systems o! be!ween 25,000 and 50,000 barrels a day capacity. At the present time 1t appears that several more years of experimentation are required be!ore an~ decisions are made and it will be the early 1980 s before any maJor proJects could be on stream. 1 PEACERIVEROIL SANDS DEPOSIT General Comments The Peace Ri ver oil sands deposit illustrated on the enclosed map underli es approximately 1,800 square miles in north central Alberta, approximat ely 250 miles northwest of Edmonton. Proven in-place bitu men reserves have been estimated by the Board at 50 billion barrels, none of which ar e considered as proved recoverable. However, at a 20% bitumen rec overy via an in-situ scheme and 70% conversion it could yield up to seven bil l ion barrels of synthetic crude. Recent Developments Consi derable field testing and laboratory work by the team of Shell Canada and Shell Explorer Limited, (a subsidiary of Shell Oil Company), has resulted in the development of a steam-based recovery process which could provide an.efficient means of crude bitumen recovery from the Peace River accumulations where they hold some 160,000 acres of oil sands leases. The new process, which has been tailored to the reservoir situation at Peace Riv~r wh~re a thin re~atively high-wate~ saturation zone underlies the thick bitumen zone, involves a conventional steam drive approach until steam breakthro~gh, !allowed by pr~ssurization and depletion cycles to recover the format,~n b1tume~. The ~,lot test currently being designed is expected to be_,n_oper~t,on by mid-1976 at an initial installation cost of some $33 m1ll1on with total cost for a nine year run expected to amount to $85 million. For the pilot confi guration of the pressure cycle steam drive process a pattern of seven 7 acre-7 - 11 - ation calls for 48 wells: 24 oil spot has been selected. T~e_oP~:onwells 12 pressure and/or temperature production wells, 7 steam inJec ~ls and 3 water disposal wells. Maximum observation wel~s, 2 fueldg:sO ~e ab~ut 250 barrels daily per producing oil production ,s ~xpecte e 40% and 70% of the oil-in-place are well while recoveries of betwee~ Confirmation of the subsurface anticipat~d ~a~ed ~n model st ud~~~ined with an improved economic and st pro~e~s v1ab~l1ty 1n the te ~ the commitmentto a commercial venture pol1t1cal climate could lead t ·t . 1982 and a full-sca l e project on of some 100,000 barrel per capac, Y 1n stream in 1985. WABASCA OIL SANDS DEPOSITS General Comments The Wabascaoil sands deposit illustrated on th e enclosed map underlies approximately 1,600 square miles.immediate ly west of the large Athabasca accumulation. Again these deposits are t o? deep for recovery by mining. Proved in-place bitumen reserves are est imated to be 54 billion barrels none of which are considered as proved recoverable at this time. How~ver,a 20% bitumen recovery and 70% conversion would yield about seven billion barrels of synthetic crude oi l. Recent Developments Exploration drilling and geologic al evaluation programmeshave defined prospective boundaries of this deposit although no major in-situ test programmeshave been undertaken to dat e. The Board has given approval to Gulf Oil Canada for recovery of bitumen and other products from the deposit through a scheme which involves the drilling of two wells about 850 feet deep. Steam will be injected into both wells at the maximum rate the wells wil l accept for one month and then production tested up to 50 b/d of oil and 50 b/d of water. LLOYDMINSTER AREA HEAV Y OIL DEPOSITS General Comme nts . The Lloydminster accumulations underlie an area of some 5,000 square m~l~s al on~ the Alberta-Saskatchewan border. Reserves maybe rather m1n1scu l e 1n comparison to the oil sands However because secondary rec?very operations are further advan~ed they ~re of importance to producers 1n t he area Tot 1 01· 1 • ' h bil lion barrel ran h.1 · a reserves 1n place are in the tree nology are esti mat~~ :t reserves utilizing present tech;;on 0re~~~~rable 1?n ~arrels or 8%. Accumulated produc as of Decem ber 31 1972 ' was m1ll1on barrels. Enhanced recovery 1:~1o s~he~es may yield an additional 40%of the oil in place or about one billion barrels. These finds produce by conventional methods, i.e. the we~l~ are cased and the oil is mechanically pumpedto the surface. Initial daily rates vary between 20 and 75 barrels although some wells have tested as high as 200 barrels per day. Output may decline to about 10 barrels per day within five years although enhanced recovery schemes such as waterfloods and in-situ combustion can maintain initial production rates over a much longer period as well as increase the ultimate recovery substantially. Recent Developments . Commercial exploitation of the heavy oil fields in the Lloydminster area has been pioneered by Husky Oil. In 1963, the Company developed a process of blending approximately 20%natural gas condensate with 80% heavy gravity asphaltic crude oil thereby enabling it to ship the asphaltic crude long distances by pipeline. Husky subsequently constructed a pipeline which interconnects with Interprovincial 'soil pipeline south of Lloydminster. Throughput capacity of its system is 50,000 barrels per day of blended crude with present daily rates in the range of 30,000 barrels per day. A second pipeline system, also interconnecting with IPL, was constructed by the Murphy-CanadianReserve team in 1971. This line has a capacity of some 14,000 barrels per day and is currently averaging close to 10,000 barrels per day. Husky Oil controls over 50%of the present productive capacity and potential acreage in the Lloydminster area and_has increased its production from an average of 800 ~arrels per da~ in ~962 to ~l,000 barrels per day in 1973. Other maJor producers in this area include Canadian Reserve and MurphyOil with production of about 4,000 and 2,000 barrels per day respectively. - 13 - FUTURE DEVELOPMENT Oil Sands Presently proved mineable reserves in the Alberta Oil Sands are adequate to support 20 to 30 plants of 100-15~,000 barrels per day capacity and producing 3 million barrels per day.. Ultimat~l~, however, commonprocessing facilities will likely develop with capacities up to 300,000 or 400,000 b/d serving several satellite mines, because of ~he excessive cost of building integrated facilities on every lease. Up ~o th is rate_res~rves would not be limiting and no new technology would ~e required. What.is limiting, however, is the availability of capital, equipmen!, manufacturing facilities design and other professional services, con~tr~ct~on, labour and operating ' personnel. The magnitude of these factors is indicated by the approximate requirements for a 100,000 barrel per day plant. 800 million 1973 dollars 200 million 1973 dollars 800 man years 5,000 man years 1,500 men Total capital Specialized equipment Design and professional services Construction labour Operating personnel Furthermore, a substantial lead time from project conception to start of production is necessary - five or six years as well as careful scheduling to avoid conflict with other projects during the actual three to five year construction period. A forecast of the manner in which synthetic crude oil production ~ay be de~eloped to 1990 is illustrated in Graph l. Considerable risks are involved 1n such long range projections; however, a goal of 650,000 barrels per day by 1985 and 1,100,000 barrels per day by 1990 seems achievable. GRAPH 1 SUPPLY OF SYNTHETIC OIL 2000 1800 1600 ~ 1400 0 "' .,, .., w CL 1200 w 1000 ,p" 800 ~...-"".'. 600 400 ./ --~ ·~ ----- 200 0 I 972 1974 - ~ :-.-2nd ~ llotrofin• ----- ... 01 V Jrc "' "' di <( n in,ng In Sit 0 "' z<( .,, 5th Min ng 0 In Sit, ::, or Home 0 :r: ... Syn rude C bid Lok Area GCO! 1976 1978 1980 1982 REFERENCE TABLE Ill - 14 - 1984 1986 1988 1990 An assessment of the role of the oil sands in meeting Canada's future petroleum demandas illustrated on Graph 2 would not be complete without reviewing the expected performance of the conventional oil industry as well as the potential of the frontier areas. GRAPH 2 CANADIANOIL DEMAND 3600 3400 3200 .,,,,,,- .,r 3000 .J~ ...~ 2800 ....~ 2600 _,,,,,,,,,. 2400 1'c:TAL ~ CJ NADIA! D:MANDl 2200 - ....~ --~ ... w "' ,_,,,,,.- 2000 ../~ ~ 1800 1600 - ~ ~~ -V' "' "' "' < co ..J w / ....- ..,,,-I""' 0 1400 l.--- _.......... , ----- 1200 - ---- 1000 · - 800 ..-- ---- pEMA 1.. -r Np•~ . ....-- - ~ - ""6!'!""'_ < i,..--- "' ::> 0 ... :I: - 600 400 200 0 1972 1974 1976 1978 1980 1982 REFERENCE TABLE IV - 15 - 1984 1986 1988 a "' z 1990 Conventional Oil Supplies The potential supply of conventional crude from established areas~ under limits of productive c~pacity only, is_il~ustrated in Graph 3; daily production reaches a peak 1n 1975 at 2.1 m1ll1on barrels which is sustained until 1978 thereafter declining noticeably. This projection incorporates only estimated reserve additions from revisions, extensions and new discoveries at about the 1972 level for 1973 and 1974, then declining at about 2.5% annually. GRAPH 3 SUPPLY OF CANADIAN OIL --·- '- 3600 -., --· - -- ..- -.,.. ,.,.. .. - - 1--- 3400 3200 3000 2800 2600 2400 2200 ct: 1800 / , w ............. ....... / 2000 "' i' ./ 1600 0. .,, ..J w ct: ct: <( cD ....~ " " 1'.. 1400 ... 0 "' 0 z .,, <( , 'i-........ 1200 ... """"" .......... CON VEN IONj~L O L 1000 ::> 0 :I: ~ __,,, ........... 800 ........... r--,....., 600 400 200 0 1972 1974 1976 1978 1980 1982 198,4 REFERENCETABLESV AND VI - 16 - 1986 1988 1990 . Proved remaining reserves of crude oil equivalent for established areas 1n Canada as of the end of 1973 were 8.5 billion barrels. See Refer~nc~ Table V for details. The reserves are the Canadian Petroleum Assoc1at1on_ (CPA) estimates. These do not include so-called "tertiary" rese~ves which may be recoverable by the application of some of the more exoti~ methods_of_enhanced recovery, e.g. in-situ combustion, steam flooding and miscible flooding with solvents or LPG's. Sources in the United States have estimated that production costs for many tertiary recovery processes are in the five to seven do~lar p~r ~a~rel range. Assuming a similar cost structure, wellhead pr1c~s s1gn1f1cantly higher than the present $6.50 per barrel will be required to make such reserves economic in Canada. However, given the potential magnitude of these reserves, Alberta could yield up to an additional four billion barrels which represents about seven years supply at Canada's current rate of consumption; special government incentives may be made available for companies willing to undertake such projects to cushion the expected decline in conventional oil production during the next few years. In Alberta the present discovered oil-in-place reserves have been estimated at 33 billion barrels. Of that, 11 billion barrels or 33% are deemed proved recoverable some of which has already been produced. Tertiary recovery methods could boost recoverable reserves to around 15 billion or 45%of the oil-in-place. Taking into account the possibility that a maximumexport limitation of about one million barrels per day and a requirement that the oil reserves-life index be maintained at no less than 10 years, is adopted by the National Energy Board, we can see no significant boost in conventional production from the established areas. Annual output of conventional oil and pentanes plus, appears to have peaked at about 2.0 million barrels per day. Alberta, which accounts for about 80%of Canada's total production, is at 95%of operational capacity now as a result of the unprecedented export demand_wh~chhas push~d daily production from 0.8 million barrels in 1968 to 1 .7 million barrels in 1973. Unfortunately during this period new discoveries were u~able to keep . pace with the increased production and pro~ed conventional _re~erves in Alberta declined from 8.1 billion ba~rels in ~968 to 7.6_billi~n barrels today. As illustrated in ~ra~h 4 daily Canadian production,_wi~h the previously described restrictions, would ~v~rage about ~,.9 million barrels during the period 1974-1977, declining to about 800,000 barrels per day in 1990. - 17 - GRAPH 4 SUPPLY OF CANADIAN OIL 3600 ,- ........... ,, .....,.,,.n ,oC'AC ~11uc11y_ ,.. ""' ON EXPC RT Qi: OIL AT 050 3400 R.L~. of 3200 WITi-1 MBPI• r11LIT.aTnJ.IC! II NMUM AN Ml 10 ' EARS 3000 2800 2600 2400 2200 QI! w Q. 2000 .,, ... - w QI! QI! ~ 1800 / < / CD u. 0 1600 .,, 1400 < .,, ::::, a z 0 :i: 1200 ,~ 1000 ODNVI NTl<~NAl 011 I- ---r--......,_ 800 600 400 200 0 1972 1974 1976 1978 1980 1982 1984 REFERENCETABLESV AND VI - 18 - 1986 1988 1990 Frontier Oil Supplies . An as~ess~ent of the petroleum potential of the Canadian fr ont i er areas is highly speculative at this time because of the limited geological ~nowledge available. However, initial drilling results in t he Mackenzie Delta, Arctic Islands and Offshore Eastcoast have confirmed the presence of hydrocarbon bearing reservoirs and thus lessened the ri sk in making such projections. The estimates prepared by the Geological Survey of Canada (GSC) and quoted in "Energy Policy for Canada - Phase 1 constitute a reasonable assessment of the potential undiscovered crude oil resources of Canada. In evaluating these large relatively unexplored regions the GSCconsidered an estimate of the volume of sediments, their richness or petroleum generating potential as well as comparisons with knownoil producing areas elsewhere in the world within a probability framework in order to compensate for the lack of hard data in any one basin. Following are the highlights of this assessment: 11 The mean probable potential for conventional crude oil resources for Canada is about 100 billion barrels. Of this 16 billion found, essentially barrels (including NGL's) have already been all in the Western Canadian basin. About 4 billion barrels of crude oil remain to be found in Western Canada, and because it will likely occur in small pools, it will be difficult and costly to find. About 80 billion barrels of Canada's undiscovered oil potential is located in frontier areas. Of the frontier potential 63 billion barrels is located offshore, much of it in areas where the technology to explore and develop does not yet exist. The volume of supply that may be availab~e f~om Canada's frontier areas is illustrated on Graph 5. Production ~s ~xpected to commencein the early 1980's increasing t? ab?ut 1.5 m1ll1on_barrels_per da b 1990. While the finding and explo1ta~1on co~ts of this.new 011 wi11 1e considerably higher than those associated w,t~ convent~onal reserves of Western Canada it i~ !elt ~hat th~ potenkt,athlfor d1scto~erys high product1v1ty fields w,11 ma e ese opera ion of lar~e reser~es, First roduction is expected to come from the econom,ca~lytviab~e.most lik~ly the Nova Scotia shelf where several oil o!fshore_ ashcoasb, n made to date with the Mackenzie Delta, on and discoveries ave ee '. , offshore, having an impact by th e mid-l 9BOs. - 19 - GRAPH 5 SUPPLY OF CANADIAN OIL 3600 ~ .... ~.,, 3400 HEIAVY OIL / ,,,r NORTHWEST. ERRIroRIE s Mjl INLAIID, YU koN, IBEAUit'ORT, ANIJ vr ~r1Vll(t:. E~STc;DASl. /.,,,. 3200 3000 V 2800 I / I/ 2600 2400 FRbNTIER AREAS I 2200 V ~ 1800 - - ,, 2000 /,/ I QC w a. Cl) TOTI L SUPP Y ..I w QC ct: <:( di _l----"- 1// IL 0 II' Cl) 1600 0 z <:( OIL SAND' Cl) 1400 :::, 0 ::c .... 1200 1000 CONV NTl!DNAI 011 800 600 400 200 0 1972 1974 1976 1978 1980 1982 1984 REFERENCETABLES111,VAND VI - 20 - 1986 1988 1990 ECONOMICS OF OIL SANDS PRODUCTION General Comments . O~r economic analysis summarized in Table VII is based on proJect capital and ?Perating cost data available from the Syncrude, Shell Canada, Petrofina Canada and HomeOil applications to the Board as ~ell as ~he G~eat C~nadian Oil Sands 1973 annual report and supplementary 1nformat1on filed with the Alberta government. Development Schedule . Wehave ~ssumed that detailed engineering activities, including pilot pla~t operations.an~ project design have been completed and field constru~tio~ would begin in 1974 with preliminary plant operations commencingin 1978. Economic Parameters (1) Project life The economics are based on a facility producing approximately 125,000 barrels of synthetic crude per day for 25 years. (2) Products and Prices Weassume that two saleable products, 30 degree AP! gravity synthetic crude and elemental sulphur are produced. The numerous unpredictable factors influencing world oil markets put any price projection at risk. However, we have made the following assumptions: Synthetic crude will have access to the world commodityprice for crude oil. Today's synthetic crude price of $7.00 per barrel will escalate on the average at 5%annually to 1998 when it reaches $22.58 per barrel and then remains constant for the balance of the project life. No net income has been assumed from the sale of sulphur which would be produced at a daily rate of about 800 tons. (3) Royalty With respect to Alberta government involvement we have_assu~ed a similar arrangement to the Syn~rude agreemen~wh~reby the_Prov,nce 1s a joint venture participant and i~ return for ,ts interest,~ the le~s~s and leased substances, is to receive 50%of the pre-tax profits remaining after deducting from total revenues e~ch year: - 21 - 1. 2. 3. Operating Costs Depreciation or recovery of capital An allowance for capital employed equivalent to 6% on total capital employed. The province, through the Alberta Energy Company,also has an irrevocable option to acquire up to a 20% interest in the Syncrude project up to the commencementof production. (4) Income Taxes Federal income tax is payable starting in the sixth year of production and has been calculated at a rate of 40% of net profits after deduction of Alberta's 50% share of profits. A commitment to this effect regarding the Syncrude joint venture was received from the Federal government in December, 1973, and has been confirmed recently by the Finance Minister. Even if the budget proposals should be reintroduced the federal tax system will provide additional tax incentives for development of the oil sands. These measures apparently ensure that total net production revenues from such projects would equal original investment before any federal income taxes become payable. The substantial investment in the original recovery and processing facilities would also earn depletion in a manner similar to exploration and development expenditures. (5) Operating Costs The average annual operating costs are estimated to be $105 million at the start-up in 1978 increasing to about $400 million in the final year of the project. (6) Capital Costs Based on detailed engineering design estimates, total preproduction expenditure requirements are estimated at about one billion dollars as of December31, 1977. The industrial components of this cost estimate are as follows: $ Million Mining Extraction, Froth Treatment and Diluent Recovery Upgrading Utilities and Offsites Working Capital Preparation and Miscellaneous Cost Construction Interest Total - 22 - 300 150 250 100 50 50 100 l ,000 Additional expendit mining tra nsportation system ur~sffor ex~ension and relocation of the about $290 million during thean _or ~quipment replacement amount to proJect s 25 year life. (7) Escalat ion Inflation and oth . both th e project costs a nd er economi~ factors are expected to cause on hist orical average es 1P;?duct prices_to escalate with time. Based ponent parts these c~ a ions for capital and operating cost comand 4% per ye expen~itures are estimated to escalate at about 5% ar, respectively. 0 1 consid ered ~0 t~e absence of ~ny long term historical data that were e representative of future trends the price of oil was atssumed todescal~t: at 5% annually from $7.00 pe; barrel in 1974 through o 1993 an remaining flat thereafter. Conclusions . . Three widely accepte~ measures of value or indices of profitabi lity used by the petroleum industry to evaluate prospective investments are: Payout Period: this is the length of time required for cash flow to return the initial investment. It simply tells managementhow long the investment will remain unrecovered and therefore, at risk. Historically a general rule for acceptability of a project was two to three years especially among independent operators with limited working capital. However, major oil companies having adequate funds are more concerned with continuity of long term operation. Profit After Payout Per Dollar Invested: this gives consideration to the potential magnitude of ultimate cash flow from a project but it gives no regard to the timing of income received. Discounted Rate of Return: this is the percentage of the unamortized investment which can be considered as profit from each year's cash operating income and s!ill leave_amo~nts tha! w~ll exactly retire the investment during ,ts economic life. This ,s calculated by finding the discount_f~c~or ~hich yields_a present value of future income equal to the 1n1t1al investment, 1.e. the present value of net cash flow equals zero. Most compani~s agree that the rate should be around 15%particularly at a time when the return on low risk investments such as good quality bonds is in excess of 10%. - 23 - In the case of the oil sands project detailed and VIII the indices are as follows: Payout period Profit after payout per dollar invested Rate of return in Tables VII 8.3 years $3.03 13% It is obvious from these figures that the proposed project provides only a minimumreturn over a long period of time. The risks in forecasting future oil prices coupled with the technological problems which will have to be overcome in the initial years are significant. Companies planning the large expenditures in what must still be considered pioneering ventures are by no means assured to turning a profit and in our opinion the potential returns have been reduced to a minimum acceptable level. For the large integrated companies the oil sands should ensure a source of supply for their refining and marketing operations and in the case of the major leaseholders offer an opportunity to economize through development of satellite operations in the future. - 24 - TABLE1 HEAVY OIL DEPOSITS OF WESTERN CANADA PROVED RESERVES ANDGENERAL CHARACTERISTICS* Overburden Depth Interval (Feet) Deposit Athabasca Cold Lake A B C Peace River Wabasca A B Ll oydmini s ter TOTALS 0-150 150-250 150-2000 1000-2000 1000-2000 1000-2000 1000-2500 250-2000 1000-2500 1200-2500 Area Extent (M Acres l 490 270 5,260 l ,800 650 710 l, 180 764 1,000 _]_,200 15,054 Bitumen Or Heavy Oil In Place (Billion Bbls ) 74 47 506 118 0 Sulphur Weight% 38,000 6-8 8-10 l 0-12 3-4 Recoverable Synthetic Crude Oil (MMBbls*) 26,500 5 33 14 51 31 23 9 5 7-13 4-5 J 14-16 2-3 900 * Data mainly drived from AERCBReport, December31, 1973. M denotes thousands of acres. MM Bbls denotes millions of barrels. Gravity API Recoverable Crude or Bitumen (Ml·1 Bbls*) 240 38,240 26,500 TABLEII OIL SANDSPROJECTS DATASUMMARY Capi tal Cost Estimate (1973 dollars) Reserves in place Mining Recovery Factor Recoverable Reserves UNITS OPERATOR $Million GCOS(1) Initial Plant 260 Billion bbls of bitumen. % Billion bbls of bitumen. Years * TPCD **BPCD BPCD S'(NCRUDE (2 )_ SHELL(3) PETROFINA CANADA (4} HOM E OIL COMPANY (5) Expanded Plant 900 710 850 956 (1974 dollar~ 1.0 2.4 3.7 3.4 1. 6 87 0.9 87 2. l 88 3.3 94 3.2 92 1.5 41 225,000 140,000 125,000 Spring 1974 Jan, 1978 Jan, 1982 75 200,000 121,000 100,000 Jan, 1976 Jan, 1980 Jan, 1982 52 255,000 153,500 122,500 Jan, 1978 July, 1982 July, 1984 29 203,000 123,000 103, 000 July, 1978 July, 1982 July, 1985 Reserve Life Oil Sands Mined Bitumen Recovered Synthetic Crude Produced Commence- Const. First Production Full-scale Production CALCULATED UNITRATIOS Capital cost per daily bbl of synthetic production (1973 dollars) 41 93,000 58,000 45,000 Sept. 1964 Aug. 1967 1971 28 140,000 85,000 65,000 $5,800 $4,500 $7,000 $7,100 $6,800 Bbls of bitumen recovered per ton of oil sand Bbls synthetic crude recovered per bbl of bitumen Bbls synthetic crude produced per ton oil sand 0.62 0.61 0.62 0.61 0.60 $9,282 (1974 dollars) 0.61 0.78 0.76 0.89 0.83 0.80 0.84 0.48 0.46 0.56 0.50 0.48 0.51 * ** (l ) {2) (3) (4) (5) n.a. Tons per calendar day Barrels per calendar day Participant - Great Canadian Oil Sands - 100%, however Sun Oi1 Company owns 96% of the commonshares. Part icipants - Atlantic Richfield Canada Ltd. - 30%, Canada Cities Service Ltd. - 30%, Imperia 1 Oil Ltd. - 30%, Gu1f Oil Canada L_td. - 10%. The Alberta Government has an option to acquire a 20%working interest in this project at cost. Participants - She11 Canada Ltd. - 50%, Shell Explorer Ltd. (a wholly owned subsidiary of Shell Oi1 Company)- 50%. Participants - Petrofina Canada - 35.3%, Pacific Petroleums - 32.7%, HBOG - 14.6%, Murphy Oil Canada - 10.5%, CanDel Oi1 - 6.9%. Particir .....t.s - HomeOil Company- 87.5%, Alminex Limited - 12.5%. TJ\BLE I II CANADIAN OIL PRODUCTION FORECAST (Thousands of Barre l s/ Day ) Year 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 l 988 1989 1990 Esta blished Reserves Expor t of oil: 1050 MBPD Mini mum R.L.I. for oil: 10 tears 1,646 1,910 1,885 1,930 1,905 1,780 1,670 l ,570 l ,475 l ,390 1,300 l ,220 l , 150 l ,080 l, 015 955 900 845 795 Synthetic and Heav1 Oil 52 52 55 60 65 65 115 155 220 300 400 450 600 675 775 900 l ,000 1 ..050 l ,200 Source: Gulf Oil Canada Imperial Oil Alberta Energy Resources Conservation Board Syncrude Canada N.W.T. &Beaufort Sea 3 3 3 3 3 3 3 3 3 3 3 3 3 500 600 700 800 900 900 East Coast Offshore - - - - - 100 150 200 250 300 350 400 450 500 500 500 Total 1,701 1,965 1,943 l, 993 l ,973 l ,848 l, 788 1,728 l ,798 1,843 1,903 1,923 2,053 2,605 2,790 3,005 3,200 3,295 3,395 TABLE IV CANADIAN OIL DEMAND FORECAST (Thousandsof Barrels Per Day) Year 1972 1973 1974 1975 1976 1977 1978 1979 1980 1985 1990 \-.lestof Ottawa Valley East of Ottawa Valley Total Canadian Oi.1 Demand 776 820 880 900 920 940 990 1,050 l, l 00 1,300 1,550 816 833 950 1,000 1,055 1,120 1,160 1.190 1,235 1,430 1,700 1,592 1,653 1,830 1,900 1,975 2,060 2,150 2,240 2,335 2,730 3,250 · SOURCE:Alberta Energy Resources Conservation Board Oilweek Gulf Oil Canada TABLEV ESTABLISHED AREASRESERVES ORIGINAL IN PLACE,ULTIMATE & REMAINING AT DECEMBER 31, 1973 Provinces Crude Oi1 Northwest Territories British Columbia Alberta Saskatchewan Manitoba Ontario Other Eastern Canada Total Canada ORGINAL IN PLACE Proved Probable* 500 1,250 33,352 9,605 667 187 18 45,579 Natural Gas Liquids British Columbia Alberta Saskatchewan Total Canada 500 l ,260 33,912 9,912 680 194 18 46,476 ULTIMATE RESERVES Probable* Proved (Million Barrels) 90 60 435 480 11,369 12,423 1,889 2,066 145 167 61 63 l 2 13,960 15,291 61 2,314 27 2,402 63 2,501 29 2,593 Approximately 50%of the natural gas liquids are CS plus; thus, the 011 and equivalent reserves are: * Includes proved reserves. Source: CPAReserves Committee REMAINING RESERVES Probable* Proved 42 205 6,784 589 44 10 - 72 251 7,839 766 66 13 2 7,674 9,008 40 1,547 1,595 41 1,734 10 1,785 8,471 9,901 8 TABLEVI ESTABLISHEDAREASRESERVES ANDPR00UCTION FORECAST CRUDE OIL ANDPrnTANESPLUS Reserves MMBbls. * Remainin 1 8,764 8,316 7,846 7,304 6,750 6, 194 5,6 45 5, 147 4,694 4,285 3,905 3,561 3,252 2,981 2,740 2,520 2,327 2, 157 2,010 Production (l) Dai l y Annual Year Additio ns Original Remainin 2 (M Bbl s*l (MM Bbls.*) 1972 199 15,675 8,764 1,646 602 1973 249 15,924 8,316 1,910 697 1974 247 16, 171 7,875 1,965 717 1975 235 16, 405 7,406 2, 131 777 1976 226 16,6 32 6,937 2, 131 780 1977 214 16, 846 6,501 2,111 770 1978 205 17,051 6,096 2,065 754 .... 1979 198 17,249 5,721 1,906 696 1980 190 17,439 5,373 1,759 643 1981 182 17,621 5,048 l , 621 591 1982 168 17,789 4,7 41 1,500 548 1983 161 17,950 4, 457 1,381 505 1984 153 18, 103 4,190 1,262 462 1985 146 18,249 3,942 1 , 143 417 1986 140 18,3 89 3,712 1, 043 381 1987 125 18,514 3,488 947 345 1938 123 18, 637 3,282 864 316 1989 117 18,754 3,091 786 287 1990 114 18,868 2,915 715 261 ~ l ~ Bbls deno~es_thousan ds of barre l s, MM Bbls denotes millions of barre l s No restr1ct1ons on exports . · (2) Export of oil limi te d t o 1050 MBPDplu s mi ni mum RLI of 10 year s. Source: Gulf Oil Canada • Production (2) Reserve Annual Daily Life Index (M Bbls*) (MM Bbls.*} 601 15(Years)l,646 12 l, 910 697 1,885 688 11 1,930 704 9 1,905 9 695 8 1,780 650 7 1,670 610 7 1,570 573 7 l,475 538 7 1,390 507 7 1, 300 475 7 1 , 220 445 l , 150 7 420 7 1,080 394 7 1,015 370 7 955 349 7 900 329 8 845 8 795 308 290 Reserve Life Index 15 12 ll 11 10 10 lO 10 10 10 10 10 10 10 10 10 10 10 10 I8_BLEVI l FORECAST OF OIL PROCUCTION, INCOME ANDPRESENTWORTH FORA 125,000 8/0 OIL SANOSMININGPROJECT OIL PRICE $7 .00/88L. ESCALATING 5%/YEAR Caeital Exe~nditures Production Synthetic Beginning End or Daily Annua1 Crude Price of Year Additions Year 000 ' s Mill. Year ~ ~ ...wt1_ ~ Bbls. $/Bbl. 1974 7. 00 75 7.35 76 7. 72 77 8.10 78 Revenue Operatin g Amort i za t ion Costs of Capital ~ ~ iMM Interest Allowance Profit (Loss) --1!ii_.J!1L Loss Carried Forward iw.1 Profits to be Shared Alta. Gov't. so:.;Interest Net Profit Before Tax Net Profit (1) ~ 1"'1 $:-'M SMM 30. 9 1022. 6 so 18.3 8.51 155.7 79 105 . 7 5.8 1028.4 57.1 90 32.9 8. 93 293 . 8 80 124.8 6.4 55.9 105 113.1 106.0 53.0 53.0 53.0 105 115 991.7 81 11.7 1034.8 1046. ·5 82 35.1 1081.6 38.3 9.85 169.0 377 .3 84.5 84 . S 143.3 84.5 138. 5 52. 3 6.4 181. 7 ll8. 9 13.2 181. 7 5.3 10.34 90. 9 434.3 90.8 149. 6 90. 8 143.1 51. 4 11.7 233.3 118.3 13. 1 233.3 4.6 116.6 116. 7 ll6 . 7 51.6 209.1 209. I 104.6 104. S 62. 7 50.7 247.5 247.5 123. 7 123.8 74.3 265.5 265.5 132.8 132.7 79. 6 43.8 10.85 475.2 158.0 125 45.6 11.40 519.8 164. 8 56.8 56.5 ~5. 1 119.7 13.3 4. 1 52.0 144.5 16. l 4.0 181.8 2.6 3.8 5. 7 161.3 161.5 17.9 185. 1 17 .9 3.3 125 45.6 11. 97 545.8 174.8 57.1 48.4 1141.9 125 45.6 12.57 573.2 57 .1 285.S 142.7 601.9 142.8 58.3 46.0 44.0 285.5 13.20 184.6 192.7 85. 7 188.8 306. 9 306.9 153. 5 153.4 58.5 60.3 41.9 40. 1 194. 3 329. 5 349.8 329.S 349. 8 164. 7 174,9 164. 8 92.0 98.9 199.3 1.8 197.5 26. 1 174. 9 104. 9 38. 1 35.5 25. 1 375.0 187. 5 180.2 187 .5 20. 7 112.5 210.9 1.3 397. 7 425.8 198. 9 212. 9 209.6 193. 8 212.9 20.9 33.0 375.0 397 .7 425.8 205,3 119.3 127. 7 135. 9 215. 6 222.0 229. l 235.8 243 . 9 5.0 6. J 11.7 210.6 215.9 217 .4 10.9 235. 8 233. 0 18.3 16.3 14. 3 13. 5 11.6 19.0 1160. 9 125 45.6 88 89 1.8 25. l 1162. 7 125 45.6 13.86 1187 .8 125 45.6 14: 56 632.0 663. 9 90 91 1. 3 5.0 1189.1 1194.1 125 125 45.6 45.6 60.3 6. 1 1200.2 125 45.6 696.8 731.4 768.4 223.4 92 15.28 16. 04 16.85 237 .4 248.3 60.8 61.3 93 94 95 11. 7 125 125 125 45.6 45.6 45.6 17 .69 18. 57 19. 50 806.7 846.8 889.2 260.5 272.4 285.0 62.5 62. 5 63.9 30. 7 28.2 25.6 453 . 0 483.7 514. 7 453.0 483. 7 514.7 226.5 226. 5 10.9 1 211. 9 1211. 9 1222.B 241.8 257.4 96 l.3 20.8 1224. l 1244.9 125 125 5.5 4.3 1250.4 1254. 7 10.4 13.4 1265. l 1278. 5 1278.5 125 125 125 125 125 45.6 45.6 45.6 45.6 45.6 45. 6 45.6 20.48 21. 50 22.58 22. 58 22. 58 22.58 22.58 933. 9 980.4 1029. 6 1029.6 1029.6 1029. 6 1029.6 ~98.7 312. 5 327 .8 343.5 359.3 376.4 394.5 64.0 67 .5 68.6 69. 7 73. l 79.9 79.8 23. 0 20.6 18.2 15.2 12.3 9.5 6.0 548.2 579.8 615. 0 601.2 584.9 563.8 549.3 548.2 579.8 615.0 601.2 584.9 563.8 549.3 274. l 289. 9 307. 5 300.6 292.4 281.9 274.7 241.9 257 . 3 274. l 289.9 307 .5 300.b 292.5 281.9 274.6 2C2. l 213. 7 -- -- -- -- --- -- -- 991.7 -- 286.8 1278.5 1080.0 17433.8 -- 5890. l 1278. 5 - -- 889.3 -- 9375.9 7.1 9375. 9 -- 4688.0 4687 .9 (3) 168. 1 212.6 1141.9 87 {2) 1.0 4.8 · 38.3 120 {l) 1. 9 10.3 42.0 1136. 2 02 92.8 ~J....ill_ 169.0 1133. 6 99 2000 01 17.2 5.8 ~MM Present Value Cash Flow 54.0 2.6 97 98 3'0.9 Net Cash flow 136. 3 52.0 5.7 50.0 108.9 Prod. Loan Repayment {3) 359.3 84 86 7.1 ~MM Additional Capital · Expenditures ~MM 9.38 83 85 (7. 1) Tota 1 Cash Flqw (2) Income tax has been calculated at 40% on pretax assumed that no tax is payable until total net investment. This occurs at the end of the fifth has been made for depletion which the original may earn. Total cash flow is equal to net profit and t he interest allowance. Repaid from 90% of cash flow. profits, however i t has been operating revenue equals original year of production. No allowan~e recovery and processing facilities plus amortization of capital (depreciation) 145. l 154. 4 164. 5 173.9 184.5 180. 4 175.5 169. l 164.8 -- 2950.7 251.5 262.0 271.3 265.3 260.9 258.5 250.6 -- 5153,2 57.5 19.0 1.3 20.8 286 . 8 21.3 26.6 250.2 241.2 265. 8 261.0 5.5 4.3 10.4 13. 4 -- 131.3 175.3 10.8 9.0 8.7 7.4 6.2 5.2 250.5 245. 1 250.6 -- -- 991.7 3874. 7 4.7 -- 272.5 TOTALDISCOUNTED CASHFLOW• 272. 5 PRESENT VALUEPER BARRi::L • 25. 2 CENTS AVERAGE CRUDEPRICE • $1&.14/B~l. AVERAGE PROFIT PER llBL • $2.73 YEAR 1974 75 76 77 78 79 1980 81 82 83 84 85 86 87 88 89 1990 91 92 93 94 95 96 97 98 99 2000 01 TABLE VIII OF RETURN CALCULATION RATE ADJUSTED TOTAL CASH FLOW INITIAL CASH FLO~ $MM INVESTMENT $MM 150.0 200.0 350.0 291.7 30.9 5.8 6.4 11. 7 35. l 52.0 2. 6 5.7 19. 0 1.8 25. 1 1.3 5.0 6. l 11. 7 10.9 1.3 20.8 5.5 4.3 l 0. 4 13.4 1278.5 (1 ) Payout period (143.0) (173.4) (275. 8) (209.0) 50.0 l 08. 9 138. 5 143. 1 168. 1 212.6 181.8 185.1 188.8 194.3 199.3 205.3 210.9 215.6 222.0 229.1 235.8 243.9 251.5 262.0 271.3 265.3 260.9 258.5 250.6 (150.0) (200.0) (350.0) (291. 7) 19. 1 l 03. l 132. 1 131.4 133.0 160.6 179.2 179.4 188.8 175. 3 197. 5 180.2 . 209. 6 210.6 215.9 217.4 235.8 233.0 250.2 241.2 265.8 261. 0 250.-5 245. l 250.6 5153.2 3874.7 229.5 = 12. 4 61. 0 71. l 64.3 59.2 64.9 65.9 60.0 57.4 48.4 49.6 41. 1 43.5 39.7 37.0 33.9 33.4 30.0 29.3 25.7 25.7 22.9 20.0 17.8 16.5 8 + 57.5 195. 0 Profit after payout per$ invested $3874.7 1278.5 (3) iMM $MM 02 (2) PRESENT VALUE 10% Rate of return= = 8.3 = $3.03 -- (139,9) (162.2) (246.9) (178.9) 1o.2 47.8 53.3 46.l 40.6 42.6 41.4 36.0 32.9 26.6 26.l 20.7 20.9 18.3 16.3 14.3 13.5 11.6 10.8 9.0 8.7 7.4 6.2 5.2 4.7 -- (156,7) years per$ invested 10%+ (229.5 X 5%) = 13.0% 386.2 15% •1 HEAVYOIL DSH&PEstimated Gross-in-Place milTionoarrels Athabasca Shares Outstanding (OOO's) Canadian Oils 1973 Net Oil 1 's prod' n bbls/day) n( Potential-Mining Areas (3) 150' of overburden In-situ Areas 500' of overburden ill Heav DSH~PEstimated Cold Lake Massive Sand Other Areas ~ Peace River Wabasca L loydmi nster Barrels Per Share Daily Mining Heavy Oi1 Production Potentia1 Annual to 1990 Net Earnings Per Share @ $2. 73/bbl Net Profit In-situ iQQQ'...tl 50,000 36,500 7,300 14,600 58,400 6,570 18,250 15,695 36,500 1. 7 .2 1.3 .4 1.0 .9 1.6 .4 4.64 .55 3.55 1.09 2. 73 2.46 4.37 1.09 14,600 1.0 2.73 3,650 3,650 .3 .82 .2 .55 23,725 16,425 24,820 .8 2.0 1.3 2.18 5.46 3.55 4,745 .6 1.64 2.18 Bbls/Share Integr ated BP Canada Gulf Husky IPlperial Oil ftzrphy Pacific Petrofina She 11 Canada Texaco Canada Total Union 21,004 45,493 11,502 130,117 6,274 21,323 9,975 91,007 9,715 12,784 14,396 25,700 125,000 44,000 275,000 7,900 53,800 29,900G 94, lOOG 41 ,300G 6,600G 34,500 20,628 14,406 21,644 8,548 11,218 28,746 8,142 18,999 31,215 31,600 22,300 12,700 35,800 30,500 50,000 36,000 77,900 50,600 5,400 1,800 5,500 800 4,000 2,700 3,400 10,000 N.A. N.A. 2,000 33,000 N.A. 4,000 38,000 1,000 N.A. N.A. N.A. 8,400 8,000 N.A. N.A. N.A. N.A. 2,000 N.A. N.A. N.A. 3,000 1,500 N.A. 733 127 348 588 128 234 271 163 823 50,000 20 ,ODO 104 40,000 60,000 13,000 50,000 43,000 50,000 40,000(4) 100,000 5,000(4) 50,000 Intennedi ate Aquitaine Ashland Cigol Canadian Superior Dome Great Canadian Home Hudson's Bay PanCanadian 600 1,500 1,500 N.A. 102 104 92 117 N.A. 42 307 258 2,000 1,000 1,200 2,500 4,900 10,000 10,000 65,000(6) 45,000(5) 68,000 Junior Alminex Can-Amera Candel Canadian Export Canadian Reserve Chieftain Development Numac Pennant- Puma Qi 1s Weco Development Westcoast Petroleum Yellowknife Bear 7,646 2,140 4,177 8,169 9,613 3,031 4,326 2,292 4,828 7,372 4,814 7,600 Nil 5,400 1,700 6,500 Nil 1,700 Est. 427 966 930 Nil 700 700 500 100 N.A. 500 N.A. N.A. 10,000 1,300 650 N.A. N.A. N.A. N.A. 6,500 N.A. N.A. 92 327 120 12 52 396 2,312 13,000 9,000 176 135 3,285 .8 5,000(4) 1,825 .2 .55 20,000(5) 7,300 1.7 4.64 5,000 1,825 .4 l.09 50,000 .3 American Oi1s Amerada Hess Amoco,(Std. Indiana) Atlantic Richfield Belco Petroleum Chevron Cities Service General American Mobil Shell Oil Sun Oil Tenneco Texaco Inc. Others (3) 21,661 69,802 46,640 7,500 169,839 26,867 6,305 101,856 67,365 36,834 68,235 271,896 214,733 876,712 656,400 40,547 227,500 28,700 506,000 630,137 418,916 98,200 2,290,000 5,400 5,500 8,000 38,000 N.A. N. A. N. A. 5,000 5,500 1,900 3,400 1,200 2,500 68,200 N.A. 38,000 7,000 60,000 18,250 21,900 .5 .82 1.37 29 1,619 40,000 60,000 14,600 21,900 .1 .8 .27 2.18 87 220 141 50,000 36,500 .5 1.37 23,725 .1 N.A. N.A. N.A. 3,000 8,400 4,000 23,200 10,000 201,500 249 208 933 N.A. N.A. 60,450 N.A. N.A. N.A. 2,000 6,000 85 N.A. 45,000 791,000 2,500 !!Qill (1) (2) All figures are based upon gross interests before ,'oyalty or direct government participat,on. In the Syncrude project which is the only scheme to re ceive final approval to date, the province of Alberta has an option t o acquire a 20% working interest at cost up to and including that date which is six months after start of production or Decetnber 31, 1982, whichever is the earlier . We expect the option to be exercised and look for similar type arrangements in all future projects with the possibility of a higher level of govemnent participatio n l ike ly. Reserves have been estimated on the basis of the respective b>mpany acreage positions within the oil sa nds deposits as 11111pped by the AERCBin their various oil sands reports. of mining projects 50,000 (3) See Table II for details ( 4) Includes projected Lloydmins ter area product ion for Husky, Canadian Reserve and Murphy of 30,000 barrels, 5,000 barre'ls and 5,000 barrels re spectively. announced to date. (5) Assuming HomeOil and Numacwill reduce their respective by 50% before the projects are brought on production. (6) Includes present oil sands production of about 50,000 barrels. interests 20,000 405,000(4) .2:1 APPENDIXI Current Information BP Canada Husky Oil Imeerial Oil Numac 21, 007,424 9,682, 825 130, 117, 139 4,325,566 1974 1974 Price Range Shares Outstandin g High 17.75 23.75 42.63 20.25 Low Recent 10.50 13.38 25.00 7.00 l 0.63 14.63 26. 00 8.13 Estimated Earni ngsl'.Shr. Dividend .24 .50 .80 1.80 3.75 2.70 . 95 ( l ) - Price/Earnings Low High Recent 5.8 3.6 9.3 7.4 9.7 6.3 15.8 21.3 5.9 3.9 9.6 8.6 Past eerformance Price R9~ High Low BP Canada Husky Oil Imeeri a 1 Oil Num ac 1973 Price/Earnings Low Dividend Earnings 1.32 2 .17 1. 76 . 79 15.8 13.8 28. 1 30.4 (1) 8.0 8.5 14.7 16. 0 11. 9 11.2 21.4 23.2 .89 1.27 1.22 .72 21.3 15.4 41.6 33. 0 (l) 13. 2 11. l 24. 2 17. 5 17.3 13. 3 32.9 25.3 .75 1.09 1.10 .53 15.8 17. 5 29.4 25.0 (1) 14. 8 12.8 16. 9 13. 2 15.3 15. 2 23.2 19. l . 53 .67 .85 .4 5 23. l 26.7 23.9 (1) 1o. 1 16. 5 10.0 16.6 21.6 17 .0 20.87 30.00 49.50 24. 00 10.62 18.37 25.87 12.62 . 15 .15 . 80 19.00 19. 50 50. 75 23.75 11. 75 14. 12 29.50 12.62 - - High Average ..JJZL BP Canada Husky Oil I:i112eri a 1 Oil Numac . 15 .60 _lW_ BP Canada - 11.87 19. 12 32.37 13.25 11. 12 14.00 18.62 7.00 d5 .60 BP Canada - - - Husky Oil 15. 50 22.75 10. 75 6.75 14.00 4.50 Husky Oil Imeeria 1 Oil Numac Imeeria l Oil Numac - -1.WL. . 15 . 52 1/2 - (l) - Cash Flow Per Share. APPENDIX II Bituminous Sands Leases Athabasca Deposit Only Lease No. 5,874 5 Lessee Can-AmeraExport Refining CompanyLtd. Interest 100% 6 6,440 Petrofina Canada Ltd. Pacific Petroleums Hudson's Bay Oil &Gas MurphyOil Candel Oil 7 2,866 Petrofina Canada Ltd. et al See Lease No. 6 8 1,393 Petrofina Canada Ltd. See Lease No. 6 9 5,601 Petrofina Canada Ltd. See Lease No. 6 10 11,227 Sun Oil CompanyLtd. 100% 11 2,483 Petrofina Canada Ltd. See Lease No. 6 12 4,174 Petrofina Canada Ltd. See Lease No. 6 13 49,872 14 4,177 Great Canadian Oil Sands Ltd. l 00% 15 2,094 Canadian Export Gas &Oil Ltd. 100% 16 5,824 Mobil Oil Canada Ltd. l 00% 17 49,788.2 18 l. Acreage 49,969.1 Shell Canada Ltd. Shell Explorer Ltd. 33.337% 32.713% 14.588% 10.487% 6.875% 50% 50% Canada-Cities Service Ltd. Atlantic Richfield Canada Ltd. Imperial Oil Ltd. Gulf Oil Canada Ltd. 1. 30% Hudson's Bay Oil &Gas Co. Ltd. 100% 30% 30% 10% Maybe reduced to 7.2% through option agreements with several parties including Can-Amera. 19 18,758.6 . Selburn Oil & Gas Ltd.* Baile~ Canadian As hland Exploration Ltd. 50% 50% 20 13,656.8 . Selburn Oil & Gas Ltd.* ~!~!~{an Ashland Exploration Ltd. 50% 50% 21 2,584 22 49,590.97 100% Mobil Oil Canada Ltd. See Lease Canada-Cities Service Ltd. Atlantic Richfield Canada Ltd. Imperial Oil Ltd. Gulf Oil Canada Ltd. No. 17 Standard Oil Companyof British Columbia Ltd. 2. 100% 49,941 Supertest Investments & Petroleum Ltd.** 100% 25 49,964 Union Oil Co. of Canada Ltd. 3. 100% 26 23,506 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 27 49,994 Sun Oil CompanyLtd. 100% 28 40,642 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 29 49,721.7 Canada-Cities Service Ltd. 30 37,715 HomeOil Co. Ltd. Alminex Limited 31 49,870 Canada-Cities 23 . 36,937 24 Service Ltd. See Lease No. 17 87½% 12½% See Lease No. 17 32 11,365 Canada-Cities Service Ltd. 33 22,700.75 Petrofina Canada Ltd. See Lease No. 17 See Lease No. 6 34 9,128.7 Petrofina Canada Ltd. 35 49,904. l HuskyOil Canada Ltd. 36 12,156.4 Mobil Oil Canada Ltd. See Lease No. 6 100% 100% 2. 2%overriding royalty to BP Canada. 1.6% overriding royalty to Siebens Oil &Gas. 3. 1.75%overriding royalty to Siebens Oil & Gas. 37 49,750.6 Mobil Oil Canada Ltd. 100% 38 26,339.5 Mobil Oil Canada Ltd. 100% 39 49,742.70 Aquitaine Co. of Canada Ltd. Elf Oil Exploration & Production Canada Ltd. 50% 50% 40 22,054 Imperial Oil Ltd. See Lease No. 17 41 18,491.40 Canada-Cities Service Ltd. See Lease No. 17 42 21,728.8 Bailey Selburn Oil &Gas Ltd.* 42A 16,208.6 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 43 49,784.3 Can-AmeraExport Refining Co. Ltd. Undisclosed 60% 40% 44 49,775 Texaco Exploration Canada Ltd. 45 49,730.5 Shell Canada Ltd. Shell Explorer Ltd. 46 49,750.7 Texaco Exploration Canada Ltd. 4. 100% 47 49,734.7 Texaco Exploration Canada Ltd. 4. 100% 48 46,762.9 Texaco Exploration Canada Ltd. 4. 100% 49 49,726.7 Texaco Exploration Canada Ltd. 4. 100% 50 32,824.40 Total Petroleum Co. of Canada Ltd. 100% 51 49,503 Texaco Exploration Canada Ltd. 4. 100% 52 35,109.4 Atlantic Richfield Canada Ltd. 100% 53 49,418.5 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 54 49,483.3 Atlantic Richfield Canada Ltd. Canada-Cities Service Ltd. Imperial Oil Ltd. 33 1/3% 33 1/3% 33 1/3% 55 26,001.5 Atlantic Richfield Canada Ltd. 4. Texaco Inc. owns 100%. 100% 100% 50% 50% See Lease No. 54 56 23,377 Ltd. Atlantic Richfield Canada See Lease No. 54 57 49,450.9 Ltd. Atlantic Richfield Canada See Lease No. 54 58 36,041.5 Atlantic Richfield Canada Ltd. See Lease No. 54 59 45,413.6 Atlantic Richfield Canada Ltd. See Lease No. 54 60 31,250.1 Atlantic Richfield Canada Ltd. See Lease No. 54 61 26,641.4 Atlantic Richfield Canada Ltd. See Lease No. 54 63 43,562.2 Atlantic Richfield Canada Ltd. See Lease No. 54 65 49,467.1 Atlantic Richfield Canada Ltd. See Lease No. 54 66 49,418.6 Atlantic Richfield Canada Ltd. See Lease No. 54 67 25,968.9 Regent Refining (Canada) Ltd.*** 100% 68 46,154.2 Regent Refining (Canada) Ltd.*** 100% 69 23,377 Regent Refining (Canada) Ltd.*** 100% 70 46,802.2 Atlantic Richfield Canada Ltd. See Lease No. 54 71 36,492.1 Atlantic Richfield Canada Ltd. See Lease No. 54 72 41,618.3 Atlantic , Richfield Canada Ltd. See Lease No. 54 73 49,931.2 AmocoCanada Petroleum Co. Ltd. 100% 74 23,352.7 100% 75 25,944.7 Atlantic Richfield Canada Ltd. Atlantic Richfield Canada Ltd. 76 49,836.7 77 6,086. l AmocoCanada Petroleum Co. Ltd. WoodOil Company Canadian Rhoades Oil Ltd. 100% 100% 78 36,086.1 Canada- Cities Service Ltd. See Lease No. 17 79 27,265 Atla nti c Richfield Canada Ltd. See Lease No. 54 81 41,954.4 Atl anti c Richfield Canada Ltd. See Lease No. 54 82 48,588.9 Petrofi na Canada Ltd. See Lease No. 6 84 49,378.5 Sun Oil Co. Ltd. 100% 85 49,418.8 Sun Oil Co. Ltd. l 00% Sun Oil Co. Ltd. 100% 86 4,521.91 87 49,426.9 Tenneco Oil &Minerals Ltd. 100% 88 28,438 AmeradaMinerals Corp. of Canada Ltd. 100% 89 14,937 AmeradaMinerals Corp. of Canada Ltd. 100% 90 2,916 AmeradaMinerals Corp. of Canada Ltd. 100% 91 36,3 82 Union Oil Co. of Canada Ltd. 100% * Pacific Petro leums ** BP Canada Limited *** Texaco Canada Limited APPENDIX II I Oil Sands Leases Cold Lake, Peace River &Wabasca De~osit Interest Acreagg_ Lessee 41,287.0 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 2 49,402.6 Union Oil Co. of Canada Ltd. Atlantic Richfield Canada Ltd. Canada-Cities Service Ltd. Imperial Oil Ltd. 25% 25% 25% 25% 3 16,840.6 Union Oil of Canada Ltd. 4 49,402.3 Atlantic Richfield Canada Ltd. Canada-Cities Service Ltd. Imperial Oil Ltd. 5 49,402.7 Atlantic Richfield Canada Ltd. See Lease No. 4 6 49,362.5 Atlantic Richfield Canada Ltd. See Lease No. 4 7 39,529.5 Atlantic Richfield Canada Ltd. See Lease No. 4 8 19,456.8 Atlantic Richfield Canada Ltd. See Lease No. 4 9 49,410.7 Atlantic Richfield Canada Ltd. See Lease No. 4 10 27,257.0 Atlantic Richfield Canada Ltd. See Lease No. 4 11 7,768.2 Atlantic Richfield Canada Ltd. See Lease No. 4 12 20,122.8 Atlantic Richfield Canada Ltd. See Lease No. 4 13 11,666.4 Atlantic Richfield Canada Ltd. See Lease 14 39,010.0 Lease No. See Lease No. 2 33 1/3% 33 1/3% 33 1/3% No. 4 Atlantic Richfield Canada Ltd. See Lease No. 4 15 41,610.3 Atlantic Richfield Canada Ltd. See Lease No. 4 16 49,434.9 Atlantic Richfield Canada Ltd. See Lease No. 4 17 15,544.1 Atlantic Richfield Canada Ltd. See Lease No. 4 18 46,802.2 Atlantic Richfield Canada Ltd. See Lease No. 4 19 38,969.8 Atlantic Richfield Canada Ltd. See Lease No. 4 21 46,842.8 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 22 7,768.0 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 23 4,540.2 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 24 4,688.1 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 25 7,120.2 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 26 8,752.3 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 29 49,882.5 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 30 10,532.4 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 33 14,613 AmocoCanada Petroleum Co. Ltd. 100% 34 22,089 AmocoCanada Petroleum Co. Ltd. 100% 35 18,809 Canadian Homestead Resources Ltd. Texaco Exploration Canada Ltd. 36 23,205 Amerada Minerals Corp. of Canada 100% 37 11,369 Texaco Exploration Canada Ltd. 100% 38 46,803 Gulf Oil Canada Ltd. 100% 39 28,257 Imperial Oil Ltd. 100% 40 49,603 Imperial Oil Ltd. 100% 41 49,705 Imperial Oil Ltd. 100% 42 49,739 Imperial Oil Ltd. 100% 43 10,375 Petrofina Canada Ltd. 100% 44 7,444 45 46,470 Mobil Oil Canada Ltd. 100% 46 48,587 Mobil Oil Canada Ltd. 100% 47 38,002 Mobil Oil Canada Ltd. 100% 48 38,166 Mobil Oil Canada Ltd. 100% 49 16,192 Imperial Oil Ltd. 100% 50 11,016 AmeradaMinerals Corp. of Canada 100% 51 4,528 AmeradaMinerals Corp. of Canada 100% 52 40,909 Texaco Exploration Canada Ltd. 100% 53 4,220 Sun Oil Co. Ltd. 100% 54 15,885 55 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% Canadian Industrial Gas &Oil Ltd. Suptertest Investments & Petroleum Ltd.* HannaOil DevelopmentCo. Donald Breck Lamont United Canso Oil &Gas Ltd. 50% 22½% 12½% 12½% 7½% 7,116 Shell Canada Ltd. Shell Explorer Ltd. 50% 50% 56 7,456 Union Texas of Canada Ltd. 100% 57 7,456 Union Texas of Canada Ltd. 58 100% 11,508 Mobil Oil Canada Ltd. 59 49,907 HomeOil Co. Ltd. 100% 100% 60 16,393 Canadian Industrial Gas &Oil Ltd. 61 15,245 BPOGOperations Ltd.* 62 l 0,848 BPOGOperations Ltd.* 100% 63 22,721 Westcoast Petroleum Ltd. 100% 64 49,411 Triad Oil Manitoba Ltd.* 100% 65 19,801 Kerr-McGeeCorp. Transocean Oil Inc. 66 36,969 Northern Oil Explorers Ltd. 100% 67 41,457 AmocoCanada Petroleum Co. Ltd. 100% * BPCanada Limited 100% 100% APPENDIX IV Oil Sands Permits Cold Lake and Peace River Deposits Interest Acrea~ Permittee 13 45,505 Great Northern Oil Ltd. 14 40,081 Shell Canada Ltd. Shell Explorer Ltd. 15 20,224 Mobil Oil Canada Ltd. l 00% 16 17,132 Pacific Petroleums Ltd. 100% Permit No. 100% 50% 50% NOTES (1) A~l figures are based ~P?n g'.oss interests before royalty or direct government part1c1pat1on. In the Syncrude project which is the only scheme to_receive final approval to date, the province of Alberta has ~n opt~on to acquire a 20%working interest at cost up to and 1nclud1ng that date which is six months after start of production or December31, 1982, whichever is the earlier. Weexpect the option to be exercised and look for similar type arrangements in all future projects with the possibility of a higher level of government participation likely. (2) Reserves have been estimated on the basis of the respective company acreage positions within the oil sands deposits as mapped by the AERCBin their various oil sands reports. (3) See Table II for details (4) Includes projected Lloydminster area production for Husky, Canadian Reserve and Murphy of 30,000 barrels, 5,000 barrels and 5,000 barrels respectively. (5) Assuming HomeOil and Numacwill reduce their res~ective interests by 50% before the projects are brought on production. (6) Includes present oil sands production of about 50,000 barrels. of mining projects announcedto date. The information ac c_uracy or co c~nt arned . 10 herern . has been obtained from sources whrch . we believe . reliable . but we cannot guarantee its tirne have Pos;/"P •_teness. The Company, its affiliates and their directors, offrcers and other employees may f rom time ions in the securitie s involved 0 AHYnunaer Ward, F. H· Logan, A. S. Fell, G. S. . Dembroski, J. B. Pitblado, M . H. Wrlson, . . , S. F. Hughes, D. L Erwood, J . R. Garnor