Nova Scotia Exploration Economics Model www.indeva.com SOEP Venture Production Centre Deep Panuke Production Centre Goldboro Gas Plant Deepwater Oil Floating Production Storage and Offloading (FPSO) SPAR Deepwater Gas Production System Semi-Submersible Deepwater Gas Production System Gas Subsea to Infrastructure Deepwater Oil Cylindrical FPSO Oil and Gas Exploration Economics Model SPAR Deepwater Gas Production System Shallow Water Minimal Process Gas Platform
Transcript
Nova Scotia Exploration Economics Model www.indeva.com
SOEP Venture Production Centre
Deep Panuke Production Centre
Goldboro Gas Plant
Deepwater Oil Floating Production Storage and Offloading (FPSO)
SPAR Deepwater Gas Production System Semi-Submersible Deepwater Gas Production System
Gas Subsea to Infrastructure Deepwater Oil Cylindrical FPSO
Oil and Gas Exploration Economics Model
SPAR Deepwater Gas Production SystemShallow Water Minimal Process Gas Platform
Nova Scotia Exploration Economics Model www.indeva.com
Zoom and Scroll to Explore Map. It is recommended that Users Minimize the Ribbon (right click in menu area) and Hide the Formula Bar (deselect View Formula Bar) to Maximise Viewing Area
Nova Scotia Department of Energy Exploration Economics Model 04/08/2023
Nova Scotia Exploration Economics Model www.indeva.com
No. Page Description HyperLink
1 Introduction
Evaluation Section
2
3
4 Evaluation
5 Cash Flow
6 Thresholds
7 Sensitivities
8
9 Price Charts The Price Charts Page compares the Nominal and Real Oil and Henry Hub Cas Price Scenarios
Assumptions and Overrides
9
10
11
12
13 Overrides
Model Calculation Pages14 Exploration The Exploration Page shows the calculation of seismic, wildcat and appraisal exploration costs and schedule
15 Development The Development Page shows the calculation of development costs and schedule
16 Production The Production Page shows the calculation of production profiles
17 Revenue The Revenue Page shows the calculation of revenues
18 Operations The Operations Page shows the calculation of Operating costs
19 Abandonment The Abandonment Page shows the calculation of the field abandonment date
20 Royalty The Royalty Page shows the calculation of Royalty
21 Federal Tax The Federal Tax Page shows the calculation of Federal Tax
22 Provincial Tax The Provincial Tax Page shows the calculation of Provincial Tax
23The Success Case Cash Flow Page shows the calculation of Cash flow in the case the project proceeds to development and production
24The risked Cash Flow show the cash flow risked by the probability of the appropriate stage occurring
25The Selected Economics Page show the prices, exchange rate, inflation and interest rate for the selected economic scenario
User Calculation Pages26 User Pages Five User Pages are provided for user's own calculations
This model provides screening economics for evaluation of exploration prospects in the Nova Scotia offshore. The model incorporates a development schedule and cost estimation sub-model that is linked to a production profile sub-model that is dependent on the timing of the wells from the development model. Pre-tax cash flows are calculated and used to calculate royalties and taxes and to Evaluate the prospect at the specified discount rate. You can navigate this model using the Tabs, and on each page you can also click on the blue link to navigate to this Guide or the main Input page, you can also navigate from this Page to all Other Pages. The model is organised in five Sections that are color coded, the Introduction and Guide are in Yellow, the main Evaluation section is in Red, the Assumptions and Overrides are in Orange, the Model Calculation pages are in Light Blue and the last pages are for User Modelling and are in Green
Basic Model Inputs
The basic model inputs are defined in the page Input. Input cells are shown with blue text against a white background. Most inputs have an associated floating note that appears when the cell is selected. Changing these inputs will automatically adjust the evaluated results of the model. The model can be run simply by selecting parameters in this page, or after refining the model to different levels as detailed in the next section. A basic evaluation requires that you define the current Stage of the Prospect - Seismic, Wildcat, Appraisal Development Plan or Development and assign the relevant probabilities of going from one stage to the next.
Input
Development Options
Dependent on the whether the main product is oil or gas and whether the prospect is in deep or shallow water, the user can select from a number of development options. The available development options are described on the Page Devel Options Developments
The basic Model Evaluation is also displayed on the Inputs Page. Dependent on the current exploration stage, the expected value of proceeding together with the cost of the next stage is shown on the Decision Flow diagram. The Evaluation Table shows the Discounted and Risked (weighted by the change of occurrence) contributions of each revenue and cost category to the expected value, and the "Waterfall" chart show visually how these contribute to NPV
Input
The Cash Flow page shows a chart of the contribution of each revenue and cost category to cash flow for the success case, and to the left show the contribution of each to success case and fully risked cases (weighted by the probability of occurrence) both undiscounted and discounted
Cashflow
The Threshold page shows the expected value of the current case varying for Recoverable Reserves, Reservoir Depth and Economics Scenario and by exploration stage. For each exploration stage it shows the threshold field size, reservoir depth and economic scenario at which it economic to proceed.
Thresholds
The Sensitivity Page enables Sensitivity Multipliers to be defined for critical parameters and displays "tornado" plots of the range of outcomes for NPV, IRR, Discounted Return on Investment Ratio (the ratio of the risked discounted cash flow to the risked discounted total project investment) and Committed Discounted Return on Investment Ratio (the ratio of the discounted cash flow to the discounted commitment for the next exploration stage)
Sensitivities
Government Take
The Government Take Page shows the percentage Government Take for three categories, Royalty, Federal Tax and Provincial Tax for Varying Price and Reserves Cases
Government_Take
Price_Charts
Assumptions and Overrides
The model works at a number of levels. Before making an evaluation you may wish to first adjust the Economic Scenarios for Gas and Oil Prices and Inflation in page Economic Assumptions (see below). You may also wish to create your own Cost Set (set of unit costs) for the cost model in page Cost Assumptions, and further can adjust the schedule and production assumptions used for development in page Sched & Prod Assumptions. Finally, for specific prospects if you have more firm estimates you can override the costs and production profile for the next or subsequent stage (i.e. Seismic, Wildcat, Appraisal, Development) or if you wish all future stages, to do this go to page Overrides.
Economic Assumptions
The economic model allows the development of five independent scenarios for the oil, gas and gas liquids (liquids associated with gas) prices, US$ / CAD exchange rate, cost inflation and interest rates. These can then be selected from within the main model, and the results for each Scenario are compared in the Thresholds and Sensitivities pages. This page also allows the definition of the netback differentials, in order to calculate the gas, oil and condensate prices at the field export point.
Economics
Cost Assumptions
The cost sub-model utilises unit rates from the page Cost Assumptions. The unit rates are organised in cost sets, the cost sets are definable by the user of the model and each unit rate is defined separately for shallow and deep water. The Base Nova Scotia Department of Energy cost set provided is based on actual costs experienced and drilling performance for shallow water developments from the three developments to date adjusted for industry and raw materials cost inflation. For deep water developments greater than 200 metre water depth they are based on a screening development study which compared developments worldwide and developed scenarios for possible development. The Base NS Dept of Energy Cost Set is thus highly representative of likely costs in the Nova Scotia offshore. Users / companies are also able to set up their own cost set(s) if they wish to modify certain of the unit rates, particularly for market sensitive resources such as drilling rigs.
Costs
Production and Schedule
Assumptions
The production and cost models utilises the logic in the Sched &Prod page to determine a number of factors including production rate, the number wells and construction rates. If desired these factors can be adjusted to reflect a company's experience and judgement. Schedule
As a company gets close to executing an exploration stage, for instance seismic or a wildcat well, the company's estimate of that stage may become refined as detail cost estimates are made and later proposals are requested and contracts awarded. At this point the model provides for a Company to Override the Costs and in some case the timings of a stage, for the development stage the production profile may also be overridden. Typically it would be expected that only the currently proposed stage is overridden and the remainder of the model is calculated from the assumptions set in the costs, and schedule and production pages. Overrides are set in the page Overrides, for each stage the costs can be set to "Model Calculated" or "Model Override" Override
Nova Scotia Exploration Economics Model www.indeva.com
Shallow and Deep Water area of Nova Scotia Offshore
Shallow Water Gas Field Options Less than 200 metres water depth options
Fixed Platform
Jack-up
Subsea to Infrastructure
Minimum Processing Platform
Deepwater Gas Field Greater than 200 metre water depth options
Semi / SPAR
Subsea to Infrastructure
Shallow Water Oil Field Less than 200 metre water depth
FPSO
Leased FPSO
Deepwater Oil Field Greater than 200 Metres
FPSO
GuideInput
1. Sable Island area. This is a mature area with two producing projects: 1. the Sable Offshore Energy Project, which produces gas from four gas fields, with a central facility at the Thebaud field and an export pipeline to a gas plant at Goldboro, which in turn sends gas through the Maritimes and North East pipeline to the USA, and liquids to the Point Tupper fractionation Plant; 2. the Deep Panuke project which produces gas through a parallel pipeline to Goldboro and which also flows into with the Maritimes and North east pipeline. There are a number of smaller and gas discoveries prospects in the region of Sable Island that could potentially produce into the existing infrastructure. There is also potential for small to medium sized oil discoveries. The Sable Island area lies on the continental shelf and water depths are in the main in the range 40 metres to 100 metres, environmental conditions are relatively similar to the Central North Sea with 100 year maximum wave height reported to be in the range 20 to 24 metres (OceanWeather Inc), the area to the south of Sable Island remains free of sea ice all year round.
2. Deepwater Exploration. These lie principally on the continental slope to the South West and West South West of Sable Island, the prospects closest to Sable Island are most likely to be gas prone and those further to the West are more likely to be oil prone. The deepwater exploration lies in water depths of between 1500 metres and 3500 metres and environmental conditions are similar to the Northern North Sea / Norwegian Sea with 100 year return period maximum wave heights reported to be in the range 26 to 28 metre (OceanWeather Inc). Potential export routes for gas are either to existing offshore infrastructure at SOEP or Deep Panuke, or directly to Shore possibly close to Halifax or to Goldboro.
This model provides costing and economic analysis for a number of development alternatives dependent on principle product and water depth, with the Sable Island area being classified as less than 200 metres and the deepwater as more than 200 metres as described below
This is a full production facility with gas processing, it is intended for larger discoveries above 500bcf, gas can be exported to shore or to existing infrastructure, in which case the model assumes a tariff is paid to the infrastructure owners.
This is a full production facility with the same options as the Fixed Platform, it is moveable and has the possibility of reuse after field cessation
The field is produced wholly subsea and connected to a mother platform, which performs primary processing and exports via an existing pipeline. It is assumed that all processing on the mother field is charged by a tariff to the sending field.
The field is produced through a minimum facility platform with water knock-out and methanol injection capability and exported to a mother facility for export by pipeline to shore. The mother facility charges a tariff to the sending facility for transport, secondary processing and possibly compression
This is a floating production facility solution with subsea production wells connected to one or more manifolds and tied back to the surface facility via risers. Export is assumed via a steel catenary riser although other solutions are possible. Export is either to existing infrastructure or direct to shore. The base plan is for a deep draft semisubmersible as the floating production facility but a likely cost-competitive alternative is a SPAR, possibly one being designed for the Aasta Hansteen development in 1400 metres water depth in the Norwegian Sea. It has been assumed that the facility will be a pure production facility, and that any wellwork is preformed by a separate vessel. Another possibility that could be considered would be a larger system with a drilling rig and mooring system designed to reposition the facility over the wells for reentry and wellwork such as employed by Shell on Perdido the world's deepest producing facility.
This option flows gas from a deepwater field subsea to an existing infrastructure and for onward processing and transport to Goldboro. There are a number of fields worldwide that flow gas subsea directly to shore up to 140 kilometres and a number of others are being planned. Deepwater gas offshore Nova Scotia will most likely be discovered within 80 kilometres of existing infrastructure and this option assumes the gas is exported to infrastructure, the gas will require to be dry, less than 10 - 15 bbls / mscf . As with the shallow water gas a tariff is paid to the transporting and processing facility.
This is a Floating Production and Storage System, most likely ship-shaped although a cylindrical SEVAN design system would be an alternative cost competitive design. Oil is produced from subsea wells and is offloaded onto dedicated shuttle tankers, since there are no existing tankers operating off Nova Scotia it is assumed that the tanker(s) are purchased and dedicated to the operation.
For shorter life fields a leased Floating Production and Storage System is considered, the production vessel and shuttle tankers are leased for the duration of the field
As with shallow water a Floating Production and Storage System is utilised, it has a detachable turret and mooring system and is of double hulled design, most likely a new built ship-shaped design similar to BP's Skarv FPSO due to shortly commence production in the Norwegian Sea, although a cylindrical SEVAN design system would be an alternative cost competitive design. Oil is produced from subsea wells and is stored on the vessel (assumed 1 million barrels) and offloaded onto dedicated shuttle tankers, since there are no existing tankers operating off Nova Scotia it is assumed that the tanker(s) are purchased and dedicated to the operation.
Huntingdon Field FPSO UK North Sea
Skarv Field FPSO Norwegian Sea
Chinook / Cascade FPSO development 2400 metres Gulf of Mexico
Aasta Hansteen Field SPAR 1400 metres Norwegian Sea
Ormen Lange 140 km to shore Barents Sea
Deep-draft Semi-Submersible
Nova Scotia Exploration Economics Model www.indeva.com
Depth Range Well Type Field / Prospect Well Operator Rig Latitude Longitude Spud Date MD (m) Total days
The Table Below shows the Analysis of Well Exploration Drilling in the Nova Scotia Offshore from 2000 to 2006, Base Drilling Times in Page Cost Assumptions and the Well Time Multiplier (based on Pressure) on Page Sched & Prod Assumptions are based on an analysis of this data. Source: Nova Scotia Department of Energy, Exploration Drilling Performance Review 2012
Water Depth (m)
Pre-spud days
Spud to TD days
Post Drill days
No of Hole
Sections
ROP (m/day)
No. Question
1 How do I Evaluate a Prospect in Basic Mode?
2 How do I change the Prices in the Model?
3
4
5 Can I override Costs derived by the Model?
6
7
8
9
10
How are the Costs Derived in the model and how can I change the assumptions?
How does the model determine the number of Wells? How do I adjust the assumptions?
Does the model calculate Tariffs? How do I define Tariff Rates in the model?
How are the well drilling and completion times calculated? Can I adjust these?
11
12
13
14
15
16
17
18
19
20
Answer
Go to the Sheet Input, and adjust the parameters for the Prospect in the second column according to the instructions in each cell. The expected discounted values are shown in the right hand side of the Sheet. You can adjust the Parameters and see how this affects the expected value. The Cash flow for the Success Case is shown on the Next Sheet and Sensitivities on the subsequent Three Sheets
There are five economics scenarios, that define assumptions for prices, inflation, interest rates and exchange rates. Different Scenarios can be selected in the fourth row of Sheet Input. Each of the scenarios can be modified and renamed in the sheet Economic Assumptions
The model has algorithms for exploration, development and operations dependent on the parameters entered in Sheet Input and the Units Costs entered in Sheet Cost Assumptions. There are five available set of Unit Costs defined in Cost Assumptions, the first is not modifiable (it is the Nova Scotia DOE set), the other four can be modified by the user, and selected in the fifth row of Sheet Input
The model has algorithms for the number of appraisal and development wells, these can be adjusted by adjusting the parameters and tables in sheet Sched & Cost Assumptions
Yes, but it is only recommended for the current phase where you have cost estimates, e.g. if you are in Wildcat phase, you may have a cost estimate for the Well and the model algorithms can be overwritten in Sheet Overrides. It is not recommended that you adjust subsequent phases (although it is not prevented) because you will lose the benefits of the Thresholds and Sensitivities sheets.
The model calculates tariffs for cases where the prospect gas is sent through a third party facility and / or pipeline. The rates for the tariffs are defined in the Rows 139 to 143 of the Sheet Cost Assumptions, the Tariffs Rates can be varied by type of service provided.
Well drilling times per metre are input in rows 27 to 38 of the Sheet Cost Assumptions, these can vary for deep and shallow water. An additional multiplier factor on well times is defined in Rows 63 to 65 of Sheet Sched & Prod Assumptions, which adjusts for whether the reservoir is Normally Pressured, OverPressured or GeoPressured. These times and factors are derived from the drilling history Sheet with adjustments for assumed performance improvements
HyperLink
Input
Economics
Costs
Schedule
Override
Costs
Costs
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Inputs Prospect X Decision Flow Note: NPV and Costs in $m discounted to 1-Apr-23Evaluation Parameters
Discount Rate 10% Complete 1-Jul-2012 6-Apr-2013 26-Oct-2014 16-Aug-2016Discount To Current Month Run Seismic Drill Wildcat
35%Appraise Reservoir
75%Plan Development
100%Develop Field
Scenario 5 : Flat Real NPV Cost NPV Cost NPV Cost NPV Cost NPV CostNS Dept of Energy : NS DOE #VALUE! 0.0 1804.2 0.0 5154.9 0.0 6873.1 0.0 6873.1 0.0
Project ParametersProject Name Prospect X Prospect X Summary Evaluation Parameters Prospect X Value Waterfall Chart ($M)Current Project Stage WildcatStart Date 1-Jul-2012 Overall Chance of Development 26.2%Product Type Oil First Production Date 4-Nov-2018Mean Reserves (mmbbl) 300 FALSE Abandonment Date 1-Mar-2043Water Depth (metres) 2000 15 Discount Date 1-Apr-2023
Development Method FPSO FALSE Risked Discounted Values ($M)Gas Export Type To Infrastructure FALSE Associated Gas Revenue $ 274.9 Gas Export Distance (km) 250 FALSE Oil Revenue $ 4,406.4 Pipeline Percent Deepwater 30% Total Revenue $ 4,681.4
Technical Parameters Development Drilling $ - Reservoir Depth (m MSL) 4500 FALSE Operations $ -712.7 Reservoir Complexity Medium Royalty $ -1,362.2 Areal Extent Factor Medium Provincial Income Tax $ -369.9 Reservoir Pressure Normally Pressured Federal Income Tax $ -421.9 Gas Calorific Value (btu/scf) 1040 FALSE Abandonment $ -13.7 GOR (scf/bbl) 3333.3 100000 Total Costs $ -2,880.5
Gas Type Sweet NPV @ 10.0 % ($M) $ 1,797.7 Keep Appraisal Wells ? Yes Internal rate of Return ###
Tax / Royalty Parameters Discounted Return on Investment #DIV/0!Small Reserves for Royalty No Committed Disc. Return on Investment NAHigh Risk for Royalty NoFlow-through for Tax Yes
TRUE
Guide
Economic ScenarioCost Set
Risk Parameters (Chance of Proceeding to Next Stage)
Gas Rev
enue
Liquids R
even
ue
Seism
ic
Wild
cat
Appraisa
l
Develo
pment P
lanning
Facili
ties &
Pipelines
Develo
pment D
rilling
Operations
Royalty
Provin
cial In
come T
ax
Federa
l Inco
me Tax
Abandonmen
tNPV
0.0
500.0
1000.0
1500.0
2000.0
2500.0
3000.0
3500.0
4000.0
4500.0
5000.0
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Cash Flow
Evaluation ParametersStart Date Probability
Discount Rate 10%Discount To 1-Apr-23 Associated Gas Sales (bcf) 4-Nov-18 949.0 26.2% 249.1 Economic Scenario Scenario 5 : Flat Real Oil Sales (mbbl) 4-Nov-18 297.6 26.2% 78.1 Cost Set NS Dept of Energy : NS DOE Associated Gas Revenue 2,594.1 1,047.4 26.2% 681.0
Technical ParametersProduct Type Oil Economics ScenarioMean Reserves (mmbbl) 300 Flat Real Base - 1.5%/y Base Base +1.5% /y Base + 3%/yReservoir Depth (m MSL) 4500 Seismic 2152.3 1452.6 1710.0 2055.8 2535.3Reservoir Complexity Medium Wildcat 1797.7 1113.1 1342.1 1686.7 2120.3Areal Extent Factor Medium Appraisal 4488.3 2636.3 3333.2 4208.6 5299.2Reservoir Pressure Normally Pressured Development Planning 4433.4 2526.0 3245.3 4142.9 5264.6Gas Calorific Value (btu/scf) 1040 Development Start 3106.8 1699.3 2226.8 2886.8 3714.3Liquid Yield (bbl/mcf) 3333.3
Gas Type Sweet How to Interpret:Water Depth (metres) 2000
Tax / Royalty ParametersSmall Reserves for Royalty NoHigh Risk for Royalty NoFlow-through for Tax Yes
GuideInput
These tables show the NPV (at the selected discount rate) that would be assessed for the different stages of exploration / development for variations about the currently defined case for each of recoverable reserves, reservoir depth and economics scenario. Negative NPVs are shown in yellow, positive NPVs in green, given a suitable discount rate, the boundary between the two may be seen as the Threshold at which it is financially viable to proceed with the next stage of exploration / development. The order of the economic scenarios can be changed .
Nova Scotia Exploration Economics Model www.indeva.com
Tax / Royalty ParametersSmall Reserves for Royalty NoHigh Risk for Royalty NoFlow-through for Tax Yes
Guide
Input
The Charts show the results of applying conventional sensitivity analysis to multipliers (where appropriate over the full time range) to the various factors in the model. The sensitivity multipliers may be adjusted in the input cells in the upper left hand corner of this sheet, depending on the speed of processor the charts may take a few seconds to respond to the changes.
Reserves
Oil Price
Gas Price
Exploration Costs
Development Costs
Operating Costs
Chance of Development
0% 1000000000000% 2000000000000%
Sensitivity of IRR
Reserves
Oil Price
Gas Price
Exploration Costs
Development Costs
Operating Costs
Chance of Development
0 500 1000 1500 2000 2500 3000
Sensitivity of NPV
Reserves
Oil Price
Gas Price
Exploration Costs
Development Costs
Operating Costs
Chance of Development
0 2 4 6 8 10 12
Sensitivity of DROI
Reserves
Oil Price
Gas Price
Exploration Costs
Development Costs
Operating Costs
Chance of Development
0 5 10 15 20 25
Sensitivity of Committed DROI
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X
Discount Rate 10%Discount To 1-Apr-23Economic Scenario Flat RealCost Set NS DOE
Project ParametersStart Date 1-Jul-12Development Method FPSOInfrastructure Type To InfrastructureExport Distance (km) 250Pipeline Percent Deepwater 30%
Nova Scotia Exploration Economics Model www.indeva.com
General Cost & Time Assumptions Selected Set
NS Dept of Energy Set1 Set2 Set3 Set4 NS Dept of EnergyName NS DOE Example NS DOEEstimate Date 1-Apr-12 5-Apr-12 Apr-12Switch from Shallow to Deepwater metres 200 200 Deepwater
Shallow Water Deep Water Shallow Water Deep Water Shallow Water Deep Water Shallow Water Deep Water Shallow Water Deep Water Set No. 1Index 2
Seismic & Fixed TimesSeismic Program Time days 90.0 90.0 90.0 90.0 90.0Seismic Program Cost K$ 7,500.0 7,500.0 7,500.0 7,500.0 7500.0Seismic Processing Time days 180.0 180.0 180.0 180.0 180.0Seismic Processing Cost K$ 3,500.0 3,500.0 3,500.0 3,500.0 3500.0Processing to Wildcat Time days 120.0 120.0 120.0 120.0 120.0Wildcat Review Time days 90.0 90.0 90.0 90.0 90.0Widcat Review Cost K$ 500.0 500.0 500.0 500.0 500.0Wildcat to Appraisal Time days 120.0 120.0 120.0 120.0 120.0Appraisal Review Time days 30.0 30.0 30.0 30.0 30.0Appraisal Review Cost K$ 350.0 350.0 350.0 350.0 350.0Time Between Appraisal Wells days 90.0 90.0 90.0 90.0 90.0Appraisal to Preliminary Engineering days 180.0 180.0 180.0 180.0 180.0Prelim Eng & Regulatory Prep days 300.0 300.0 300.0 300.0 300.0Regulatory Approval days 180.0 180.0 180.0 180.0 180.0Rig Rate $/day 250,000.0 450,000.0 250,000.0 450,000.0 450000.0
Exploration / Appraisal Well DrillingFixed Cost per well K$ 4,000.00 12,000.00 4,000.0 12,000.0 12000.0Fixed Cost per metre $/metre 2,300.00 3,400.00 2,300.0 3,400.0 3400.0Variable Cost per day (non-rig) $/day 180,000.00 230,000.00 180,000.0 230,000.0 230000.0Fixed days days 21.00 24.00 21.0 24.0 24.0Average metres / day metre/day 78.00 55.00 78.0 55.0 55.0
Development Well DrillingFixed Cost per well K$ 3,000.00 6,000.00 3,000.0 6,000.0 6000.0Fixed Cost per metre $/metre 2,300.00 3,200.00 2,300.0 3,200.0 3200.0Variable Cost per day (non-rig) $/day 180,000.00 230,000.00 180,000.0 230,000.0 230000.0Fixed days days 2.00 3.00 2.0 3.0 3.0Average metres / day metre/day 90.00 65.00 90.0 65.0 65.0
Well CompletionFixed Cost per well K$ 700.00 700.00 700.0 700.0 700.0Fixed Cost per metre $/metre 900.00 900.00 900.0 900.0 900.0Variable Cost per day (non-rig) $/day 50,000.00 80,000.00 50,000.0 80,000.0 80000.0Fixed days days 2.00 3.00 2.0 3.0 3.0Average metres / day metre/day 600.00 600.00 600.0 600.0 600.0Reenter & clean keeper days 4.00 4.00 4.0 4.0 4.0Renenter predrill days 2.00 2.00 2.0 2.0 2.0
Calculated Calculated Calculated Selected Selected Selected Selected Selected Count Start End Start Year Start Year End Year Historic appraisal cost risk adjustment factor 91.7%Depth Duration Lag Cost ($K) Start Date Duration End Date Lag Cost ($M) Year Year Percent Cost Cost Costs ($M)
Seismic Seismic Total Wildcat Wildcat Total Appraisal Appraisal Appraisal Appraisal Appraisal Total Seismic Wildcat Appraisal Total Seismic Wildcat Appraisal Total CEE Roy Pre-devProcessing Seismic Review Wildcat Well 1 Well 2 Well 3 Well 4 Well 5 Appraisal Exploration 0.0% 100.0% 32.1% Exploration 0.0%
The cost risk factor for appraisal is adjusted to account for some abortive appraisal programs requiring less wells. It is assumed that the number of wells in abortive programs is uniformly distributed between 1 and n, where n is the number of wells in the successful program. The equation for the factor is (where p is the probability of proceeding to development planning) : p+(1-p)*(n+1)/(2*n)
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Development Schedule and Costs Model
Start DateOverride Prelim Eng 0Preliminary Engineering 26-Oct-14 Year MonthSubmit for Regulatory Approval 22-Aug-15 2016 2Development Approval 18-Feb-16Development Start 16-Aug-16
Year 1 Year 2 Year 1 Year 2Preliminary Engineering Cost 10900.0 K$ 2014 2015 2,398 8,502
Drilling & Completion `drill complete
days cost ($K) days cost ($K)No. Of Wells 26 Gas Volume 999.99 bcfKeeper Appraisal Wells 3Platform Keeper Wells 0 12.4 9,531 Subsea Keeper Wells 3 11.2 8,868 No. Of New Wells 23No. Of New D&C wells 0 53.0 52,440 8.4 8,086 No. Of Predrill Wells 0 53.0 52,440 10.4 9,146 New Subsea Wells (D&C) 23 53.0 52,440 8.4 7,411 Drill Time Drill Cost Flowline TotalNo. Of Subsea Wells 26 Straight Well Cost 41 42,194 18,000 60,194
Deviated Well Cost 53 52,440 52,440 Method Deviated
No. Of Drilling Centres 3 WellsPlatform Centres 0 0 Not used - always deviated in clusters!Subsea Centres 3 9 9 8 0 0Subsea Keeper Wells 1 1 1 0 0Depths and Lengths
Av Deviated Well Measured Depth 3,250 metresAv Straight Well Depth 2,500 metresAv Subsea Flowline Bundle Length 6 kmIntrafield Bundle Length 10 kmExport Pipeline Length 250 km
% at start-up 50%Well Program and Cost Phasing
number time cost ($K) Start Date End Date wells at Year1 Year2 Year3 Year4 Year 5 Year6 Year7 Cost Cost Cost Cost Cost Cost Cost Total1st prod
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Gas and Liquids Production Model
Production Date 4-Nov-18Production Year 2018Production Month 11Reserves 300 mmbblTime to Plateau 98.3 Daysmin - no plateau 682.1 DaysInitial Rate 44.26 MBOPDPlateau Rate 82.19 MBOPDadjusted Plateau Rate 82.19Reserves end Plateau 120.00 mmbblDecline per Year 15.0%Ramp Rate 0.38604 MBOPD/Dexponential factor 0.00045decline length 8295.1
Dates Cum Prod Yearmmbbl
First Production 4-Nov-18 0.0 2018At Plateau 10-Feb-19 6.2 2019End Plateau 25-Nov-22 120.0 2022
Gas Production Associated Gas Production Fuel & Shrinkage
Year days Ramp Plateau Decline Decline Total Av rate Total Av Rate Prod Prod Gas Oilmmbbl mmbbl Days mmbbl mmbbl MBOPD/D BCF MMSCFD days ratio BCF mmbbl
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Revenue Calculations
Unrisked Revenue Pre Abandon Revenue Post Abandon Risked Revenue Post Abandonment Unrisked Post Abandon
Year Gas Gas Price Gas Revenue Oil Oil Oil Gas Liquids Gas Liquids Gas Liquids Total Gas Oil Gas Liquids Total Gas Oil Gas Liquids Total TotalSales Sales Price Revenue Sales Price Revenue Revenue Revenue Revenue Revenue Revenue Revenue Revenue Revenue Revenue RevenueBCF $/MCF $M MMBBL $/BBL $M MMBBL $/BBL $M $M $M $M $M $M 26.2% 26.2% 26.2% $M $M
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Royalty Calculation ($M)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Year Revenue Pre-Devel Capital Operating Abandonment Pre-Payout Allowable Simple Payout Months Weighted Return Allowance Payout BalancesCosts Costs Costs Cost Full-year Field Costs Closing Pre-Payout Av Bal Primary Secondary Final Primary Secondary Final
Full Year Royalty Liability at each Tier Royalty Liability at each Tier Royalty Loss To Profit for Loss Revised Repayment Royalty Royalty withPre-Payout GR Post-Payout GR Tier 1 NR Tier 2 NR Pre-Payout GR Post-Payout GR Tier 1 NR Tier 2 NR Liability Carry Back Carry Back Recovered Royalty Amount Repayment Abandon
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Federal Corporate Income Tax Calculation ($M)
Year Revenue Operating Costs Adjusted to CCA41 Costs for Adjusted to Opening CCA8 / CCA49 Resource Royalty Costs CDE CEE Profit before Loss to cb avail cb Loss to Taxable Tax Rate TaxCosts for CCA41 First Prod Balance 25% CCA8 / CCA49 First Prod Balance 8% Profit For CDE Balance 30% Loss cb/cf next period Carry Forward Profit Liability
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Provincial Corporate Income Tax Calculation ($M)
Year Revenue Operating Costs Adjusted to CCA41 Costs for Adjusted to Opening CCA8 / CCA49 Resource Royalty Costs CDE CEE Profit before Loss to cb avail cb Loss to Taxable Tax Rate TaxCosts for CCA41 First Prod Balance 25% CCA8 / CCA49 First Prod Balance 8% Profit For CDE Balance 30% Loss cb/cf next period Carry Forward Profit Liability
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Success Case Project Cash Flow ($Millions)2012
Year Gas Oil Gas Liquids Total Total Net Cash Flow Total Net Cash Flow Cumulative PayoutRevenue Revenue Revenue Revenue Cost Costs Cost Cost Costs Before Tax Income Tax Income Tax Gov. Take After Tax Cash Flow Date
Exploration Capital Abandon Operating Royalty Provincial Federal
Nova Scotia Exploration Economics Model www.indeva.com
Prospect X Fully Risked Project Cash Flow ($Millions)
Year Gas Oil Gas Liquids Total Total Net Cash Flow Total Net Cash FlowRevenue Revenue Revenue Revenue Cost Costs Cost Cost Costs Before Tax Income Tax Income Tax Gov. Take After Tax
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