T&T s Petroleum Upstream Sector A view of the Next 50 years

Transcription

1 5 years of Managing for Development in an Ever Changing Economic Environment T&T s Petroleum Upstream Sector A view of the Next 5 years By Allan Russell, Petroleum Geosciences, UWI Part-time lecturer Rajesh Bududass

2 Aim and Statement of Purpose The object of this paper is to : Present a view of the future role of energy projects in Trinidad and Tobago s (T&T s) revenue base over a 5-year forecast period. Determine at a high level the feasibility of these projects and their requirements. Situational Analysis T&T has exported crude oil for over 1 years and began exportation of natural gas as LNG in There is also a large petrochemical industrial base for natural gas that has developed over the past 3 years. The starting point for these industries locally is the abundant supply of oil and gas relative to the country demand profiles. Oil and gas are finite resources and present production levels are forecasted to decline; natural gas has a proved lifetime of 12 years at the current rates of consumption (Ref: Ryder Scott Reserves Report 211). In 211, crude oil production has declined to 91,919 b/d (Source MEEA in 211) and unless new sources are put on to production, this decline will continue. T&T is currently largely dependent on the sales derived from oil and gas for government revenues. 2

3 Country Imperatives Main requirements for energy can be simplified as: Security of Supply ( for Power Generation, Transportation and Local consumption) Generation (Sales of crude oil or refined products, natural gas as LNG, Petrochemicals, etc) Energy Efficiency (emissions, alternate energy sources) Participation in International Ventures to help replace declining domestic supply (use of technical skills to find / produce new resources internationally) 3

4 Current Model of the Economy Heavily dependent on Natural resource economic rents US $ Millions 211 Income 7,339.4 Energy Based 422 Corporation 2,488.9 Withholding Tax 14.3 Royalties Oil impost 15.5 Unemployment levy Excise duties 15.1 Petrochemicals Non Energy Based 312 Non Energy Corporation Ta 41. Personal Income Taxes 78.5 VAT Other 1, MUSD 3911 MUSD Expenditure 7,51.8 Current 6,471.4 Wages 1,125.8 Goods and Services 1,15.1 Interest Payments Transfers and Subsidies 3,911. Other 1,3.4 Central Bank Data 422 MUSD 751 MUSD Ref: Gregory Mc Guire Nov 25 Accounting for the Petro Dollar Transforming Economy requires implementation of the MMCID rules: (M)aximise Value Added - For an exporter (producer) like T&T we need to get highest value for resource. (M)easure and (C)apture Economic Rents Efficiently (I)nvest Economic Rents (D)iversify Economy over time Ref: Dr. Dennis Pantin - Accounting for the Petro Dollar 25 4

5 T&T Country- Income + Expenditure (211) 211 Income MUSD Income Comments: 312, 43% 422, 57% Energy Based Non Energy Based 57% of T%T s income is derived from Oil and Gas Non Energy Based Income comprises - Non Energy Corporation Taxes : 5% - Personal Income Taxes : 11% - VAT :11% - Other :16% Source : Central Bank Data vs. Expenditure Expenditure MUSD 6, TT M$ vs. Expenditure 5, 1,3.4, 14% 1,125.8, 15% 4, 1,15.1, 13% Wages 3, 3,911., 52% 419.6, 6% Goods and Services Interest Payments Transfers and Subsidies 2, 1, Other Expenditure Comments: 52% of income goes to transfers and subsidies which almost equates to current income from the Oil and Gas sector Transfers Wages Goods Interest Capital 5

6 T&T Oil and Gas Reserves Position Commercial Reserves at 1/1/212 (p+p) Location Init Init Rem Rem Liquids Gas Liquids Gas (mmbbl) (bcf) (mmbbl) (bcf) Angostura Blocks 1(a) & 1(b) BP East & West Blocks Central Block East Coast Marine Area Galeota Block Minor Fields North Coast Marine Area Osprey Pelican Petrotrin Offshore Area Petrotrin Onshore Area Primera Operated Onshore Fields SECC Block Toucan TSP Area Total Source: Wood M ackenzie 11% of liquids reserves remaining Excludes Heavy Oil and Tar Sands 6

7 T&T Oil and Gas Production Historical ( ) Base Forecast 25, 2, 15, 1, 5, Trinidad and Tobago Crude Oil Production bopd Base Oil Forecast Base TSP Fields Base Oil Forecast Major Oil Milestones: Land production began in late 18 s Marine production started in 195 s Peak production in k b/d Decline of 8% post 211 (author s estimate) Condensate production of circa 35 Kbpd drops off as gas fields decline Projections of future production rates were done using this decline assumption Remaining 2P Oil reserves ~ 388 mbbls Gas Production MMscfd 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, Gas Production Forecast Remaining 2P Gas reserves ~ 17.5 tcf New Finds in Existing Basins to supplement Petrochemical, Light Manufacturing and Power going forward. Major Gas Milestones: Train 1 ends in 218 Train 2 ends in 221 Train 3 ends in 223 Train 4 ends in 227 Source: MEEI, Wood Mackenzie 7

8 Future Sources of Reserves and Resource Opportunities in T&T Maintain Efficient levels of Base(existing) oil production Enhanced Oil Recovery projects can add 7% - 1% additional recovery from known land reservoirs Marine Small fields < 35 mmbls recoverable resources Heavy Oil projects for shallow heavy oil on land and offshore Deep Water Oil or Gas field exploration finds Tar sands mining on land Other Shale Oil and Gas Hydrates? 8

9 Development of Possible Options Produce Base Efficiently Marine and Land Pursue growth options Enhanced Oil Recovery Small Marine Field Development Heavy Oil Find HC Oil Deep Water Petrochemical Expansion Tar Sands Deep Failure Gas Refinery Upgrade Current reserves remain constant and production follows its natural or contracted path Budget deficits Currency pressures International Joint Ventures Debt Financing and International Assistance Social Pressures 1. High Value Gas Marketing 2. LNG Contract Extension 3. Expand Petrochemical Chain 9

10 T&T Next 5 year Estimated Forecast with Projects Trinidad Oil Production bopd Trinidad Oil Production bopd 12, 14, 1, 12, 8, 6, 4, 1, 8, 6, 4, 2, 2, Base Oil EOR Small Field Heavy Oil Deep water Series Base Oil EOR Small Field Heavy Oil Deep water Series3 1, 8, 6, 4, 2, - bopd EOR Project Land Fields Steam/ CO2 etc , 35, 3, 25, 2, 15, 1, 5, - bopd 5 East Cost 35 mbbls small field Analog Small Field Project , 35, 3, 25, 2, 15, 1, 5, - bopd and Dev profile Analog to Ecopetrol Llanos Heavy Oil Project Heavy Oil Production EOR Land 5 Small Field mbbls projects Heavy Oil Project Land OOIP 1535 mbbls RF= 7%, 17 mbbls D cost = 5 $/bbl, O Cost= 1 $/bbl 4 years for development Oil price discount = 15 $ New Small Field OOIP 43 mbbls RF= 4%,175 mbbls ; 35 mbbls/ field D cost = 1 $/bbl, O Cost= 15 $/bbl 4 years for 1 st field Every 2 years another, EC= 1 bopd OOIP 2 billion bbls RF= 25%, 5 mbbls D cost = 6 $/bbl, O Cost= 1 $/bbl 5 years for development Refinery Upgrade = 1 M$ Oil Price Discount = 1$/bbl 1

11 T&T Next 5 year Forecast Estimated Forecast with Projects 25, 2, 15, 1, 5, 12, 1, 8, 6, 4, 2, - Assumes Deep Water finds Oil bopd Trinidad Oil Production bopd Base Oil EOR Small Field Heavy Oil Deep water Series3 Production based on Teak Field Deep water Project Cost based on Campos Basin Central Pole Project Analog Deep Water 1 18, 16, 14, 12, 1, 8, 6, 4, 2, Tar Sands dev will only occur if Deep Water does not find HC 6, 5, 4, 3, 2, 1, bopd Trinidad Oil Production bopd Base Oil EOR Small Field Heavy Oil Deep water Series3 Tar Sand Project and Dev profile Suncor analog Athabasca, Heavy Oil Project OOIP 1 billion bbls RF= 5%, 5 mbbls D cost = 5 $/bbl, O Cost= 1 $/bbl 7-1 years for development OOIP 2 billion bbls RF= 15%, 3 mbbls D cost = 8 $/bbl, O Cost= 18 $/bbl 7-1 years for development Oil Price Discount = 1$/bbl 11

12 Methodology and Assumptions of Analysis Estimated Cash flows were developed for each resource Investment and operating expenditures taken from analogue fields for each resource Crude Oil Price is forecasted at 1 $US/bbl not escalated for simplicity, Discount Factor = 1% Economic Model : For each year Oil Price * Volume = Project = Development Cost + Operating Expenditures Annual Annual Project = Shareable Shareable is distributed between and Operator by allowing the operator to generate a reasonable return and the rest goes to the government. Analysis does not consider market shocks. Operator can be state. Market Oil Price Discount or Premium for Specs (+/-) Economic Model Effective Oil Price Oil Volume Forecast (-) Development (-) Operating (=) Shareable Operator Share to generate return > cost of capital 12

13 Results and Findings Enhanced Oil Recovery (EOR) Development Operating Shareable s Share, million $ Take, Contractor IRR, % 8, ,49 7,868 4,721 6% 15% Fiscal System Required with ~ 6% take Technology for development required through University/ Foreign Operator partnership with State entities 1, bopd EOR Project 3 25 M$ EOR Cash Flow Compostiton 8, 6, , 2, Land Fields Steam/ CO2 etc EOR Land -5 O Cost -1 D Take -15 Contractor Land OOIP 1535 mbbls RF= 7%, 17 mbbls D cost = 5 $/bbl, O Cost= 1 $/bbl 4 years for development Oil discount = 15 $ 13

14 Results and Findings Heavy Oil Development Operating Shareable s Share, million $ Take, Contractor IRR, % 44,236 4, 4,915 35,321 17,64 45% 15% Fiscal System Required with ~ 45% - 5% take Heavy Oil Value Chain to be developed Refinery upgrade required Technology for development required through University/ Foreign technology provider. 4, bopd 2, 1,5 1, , M$ Cash Flow Compostiton -1,5 O Cost D Take -2, Contractor , 3, 25, 2, 15, 1, 5, - Analog to Ecopetrol Llanos Heavy Oil Project Heavy Oil Project Heavy Oil Production OOIP 2 billion bbls RF= 25%, 5 mbbls D cost = 6 $/bbl, O Cost= 1 $/bbl 5 years for development Refinery Upgrade = 1 M$ Oil Discount = 1$/bbl 14

15 Results and Findings Marine Small Fields Remaining Small Fields carry Exploration risk Low Cost Minimum Facility Structures required for development Since most of the existing fields are operated by MNC s it is expected that these projects may be conducted through FDI s 4, bopd 1,4 1,2 1, Development 17,545 1,75 or 35 per field M$ Small Fields Cash Flow Compostiton Operating O Cost -4 D Take -6 Contractor Shareable s Share, million $ Take, Contractor IRR, % 2,632 13,898 9,869 71% 15% 35, 3, 25, 2, 15, 1, 5, - 5 East Cost 35 mbbls small field Analog Small Field Project Small Field mbbls projects OOIP 43 mbbls RF= 4%,175 mbbls ; 35 mbbls/ field D cost = 1 $/bbl, O Cost= 15 $/bbl 4 years for 1 st field Every 2 years another, EC= 1 bopd 15

16 Results and Findings Deep Water New Basins High Exploration risk If HC is found unsure if fluid will be oil or gas Currently FDI Driven. Mid to long term 7-1 years for exploration then development If gas is found LNG expansion for sales to high price markets and Petrochemical 12, value chain expansion bopd Deep water Project 4, 3, 2, 1, M$ Development 58,355 2,5 per field Operating Shareable s Deep Water Cash Flow Compostiton Share, million $ Take, Contractor IRR, % 5,836 5,2 26,26 5% 26% 1, 8, 6, 4, 2, - Production based on Teak Field Cost based on Campos Basin Central Pole Project Analog , O Cost D Take -2, Contractor Deep Water 1 OOIP 1 billion bbls per field RF= 5%, 5 mbbls D cost = 5 $/bbl, O Cost= 1 $/bbl 7-1 years for development 16

17 Results and Findings Tar Sands Development Operating Shareable s Share, million $ Take, Contractor IRR, % 45,96 3,2 9,181 33,525 2,671 35% 12% High Operating costs Environmentally unfriendly with current technology. Needs to be mitigated with technology and planning. Land use policy to be considered. Technology for development required through University/ Foreign Operator partnership with State entities 6, bopd 2, 1,5 1, 5 M$ Cash Flow Compostiton 5, 4, 3, 2, 1, - Suncor analog Athabasca, Tar Sand Project , O Cost D Take -1,5 Contractor Heavy Oil Project OOIP 2 billion bbls RF= 15%, 3 mbbls D cost = 8 $/bbl, O Cost= 18 $/bbl 7-1 years for development Oil Discount = 1$/bbl 17

18 Summary Results from Cash flows (ranked in accordance with execution time) Contractor Contractor Contractor Contracto t M$ O Cost M$ M$ Shareable D Cost M$ D O Share Cost M$ Shareable GOTTT O Cost Take M$ M$ % Shareable M$ M$ M$ GOTTT Share NPV M$ Take M$ % GOTTT Share IRR Take % M$ Share NPV M 322 EOR 1,49 8,917 7,868 8, ,721 1, ,49 7,868 6% 7,868 4,721 3,147 4,721 6% 161 3,147 6% 15% 3,1 mall Marine Small,75 Field 2,632 17,545 13,898 17,545 1,75 9,869 1,75 2,632 2,632 13,898 71% 13,898 9,869 4,3 9,869 71% 316 4,3 71% 14% 4, il, Heavy Oil 4,915 44,236 35,321 44,236 4, 19,66 4, 4,915 4,915 35,321 56% 35,321 19,66 15,66 19,66 56% 82 15,66 56% 13% 15,6 ater (per Deep Water (per,5 field) 5,836 58,355 5,2 58,355 2,5 26,26 2,5 5,836 5,836 5,2 52% 5,2 26,26 23,76 26,263,96 52% 23,76 52% 25% 23,7,572 Totals 14, ,54 17,17 129,54 8,572 6,51 14,431 8,572 14,431 17,17 56% 17,17 6,51 46,597 6,514,374 56% 46,597 56% 46,5 4, All projects are feasible if developments are efficient, and government take is adjusted depending on the specific project type and economic requirements. Estimated 8.5 Billion USD investment is required to execute these projects. 18

19 Results and Findings 1. Deepwater success in oil will have the greatest impact 1, bopd on government revenues of 1.5 billion USD/yr in the shortest time possible (7-1 yrs) 2. Small Marine Fields < 35 million barrels of oil can achieve 35, bopd and generate government revenues of 7 Million USD/yr (3-5 yrs). Recent Fiscal adjustment provided. 3. Enhanced Oil Recovery projects can generate 8, bopd and generate 2 Million USD/yr assuming an adjustment of the Government Take. 4. Heavy Oil project will require steps of resource definition and appropriate technology. If achieved, this project can generate 35, bopd and generate 6 Million USD/yr assuming an adjustment of the Government Take. 19

20 Forecast Energy ( ) These measures could stabilize revenues over the mid term (5-1 yrs) 5, 4, 3, MUSD Projection Estimated from Upstream Energy Projects 213 Estimated Energy 213 Estimated Government Energy s ~ 3 B$ 2, 1, Petrochemical Base EOR Small Field Heavy Oil Deepwater 213 Est Energy Rev 2

21 5 years of Managing for Development in an Ever Changing Economic Environment T&T s Petroleum Upstream Sector A view of the Next 5 years