ECON 366: Energy Economics

class: center, middle, inverse, title-slide

.title[
# ECON 366: Energy Economics
]
.subtitle[
## Topic 2.4: Oil and Gas Project Valuation
]
.author[
### Andrew Leach, Professor of Economics and Law
]
.date[
### <a href="mailto:aleach@ualberta.ca"> aleach@ualberta.ca</a> <a href="https://github.com/leachandrew"> leachandrew</a> <a href="https://twitter.com/andrew_leach"> @andrew_leach</a> 
]

---

# Net Present Value and other project finance metrics

Recall the idea of a net present value of a stream of profits `$\Pi_t$` for `$n$` time periods indexed by `$t$`:
`$$NPV=\sum_{t=1}^n \frac{1}{(1+r)^t}\Pi_t$$`

This concept forms the basis of a number of important measures used to evaluate projects:
- `$NPV_k$`, the net present value at a k% rate of discount e.g. `$NPV_{10}$`
- *payback* is the number of periods `$n$` it takes for `$NPV_0$` to be positive (i.e `$r=0$`)
- *discounted payback* is the number of periods `$n$` it takes for `$NPV_k>0$` for `$k>0$` 
  - (i.e for some `$r>0$`, usually 10%)
- *internal rate of return* (IRR) is the rate `$k$` such that `$NPV_k$` = 0
- *supply cost* or *break even oil price* is the price at which `$NPV_k=0$`, usually reported for `$NPV_{10}=0$`

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# Net Present Value and other project finance metrics

Recall the idea of a net present value of a stream of profits `$\Pi_t$` for `$n$` time periods indexed by `$t$`:
`$$NPV=\sum_{t=1}^n \frac{1}{(1+r)^t}\Pi_t$$`

- Why might an oil company use *payback* or *discounted payback as a metric?

- Does *break even* mean what you think it means?

- Which metric would you prefer?

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# Net Present Value and other project finance metrics

Recall the idea of a net present value of a stream of profits `$\Pi_t$` for `$n$` time periods indexed by `$t$`:
`$$NPV=\sum_{t=1}^n \frac{1}{(1+r)^t}\Pi_t$$`

This deck looks at the last modification to that formula: the *supply cost* for an oil project.
- *supply cost* or *break even oil price* is the price at which `$NPV_k=0$`, usually reported for `$NPV_{10}=0$`

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# Supply Cost

Let `$p$` be the price of oil
  - `$p$` is usually a benchmark, WTI or Brent
  - `$p$` could also be implied plant-gate bitumen prices, for example

Now, allow the stream of profits to be a function of prices `$p$` for each time t, denoted by `$\Pi_t(p_t)$`, and let the supply cost be given by:
`$$\text{Supply cost}=\{\bar{p_t}\}^n_{t=1} \ni \sum_{t=1}^n \frac{1}{(1+r)^t}\Pi_t(\bar{p_t})=0$$`
i.e. `$\{\bar{p_t}\}^n_{t=1}$` is the set of constant *real* (or, increasing nominal) oil prices chosen such that the net present value of the project is zero, usually for `$r=10%$` or `$r=12%$`
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# Oil Sands Project Economics

What does an oil sands investment involve?
- Purchase a lease
- Seek regulatory approval
- Build an extraction facility
- Burn diesel and/or natural gas
- Use chemicals
- Produce bitumen
- Purchase diluent
- Ship and sell diluted bitumen
- Reclaim/remediate land and tailings

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# Oil Sands Project Economics

What does an oil sands investment involve for our purposes today?
- Build an extraction facility
- Burn diesel and/or natural gas
- Use chemicals
- Produce bitumen
- Purchase diluent
- Ship and sell diluted bitumen

A simplified version of the problem

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# The basic approach to a financial model
What do I need to know to assess the NPV (or other metrics) for this project?
- Construction costs and schedules
- Operating and maintenance costs
- Output
- Prices
- Fiscal regimes (taxes and royalties)
- Financing

Initially, let’s worry about the big ones
- Prices
- Output
- Capital, operating and maintenance

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# What am I selling?
- Oilsands projects produce bitumen (not a homogeneous commodity, but we’ll treat it as such for today)
- In order to be transported by pipeline, bitumen must be diluted
- Diluted bitumen trades roughly on par with heavy oil
- Heavy oil trades at a discount to light oil due to its lower value to refiners
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# Recall this graph of oil sands pricing?

Now we need to solve for the top of the yellow: the implied value of bitumen at the plant gate

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# Derived value of bitumen
How much is a barrel of bitumen worth?
- Start with the price of a barrel of WCS at Hardisty – $US 56, or $CA 75 per barrel
- Now, what do I need to do to get bitumen from my site to Hardisty in WCS-form?
- A barrel of WCS is (approximately) 30% diluent, 70% bitumen
  - I need to purchase .3 barrels of diluent at Hardisty, for a price of $110/bbl, or $33 diluent cost 
  - I need to ship that to my site, at a cost of $1/bbl, or $0.30 total cost
  - I need to ship one barrel of WCS-equivalent to Hardisty, at a cost of $1.50
- My net revenue from the sale of a barrel of WCS equivalent is (75-33-0.30-1.50)=40.20
What's the implied value of a barrel of bitumen at site?

$$\frac{\$75-\$33-\$0.30-\$1.50}{0.7\text{ bbl bitumen}}=\frac{\$40.20}{0.7 \text{ bbl bitumen}}=\frac{\$57.43}{\text{bbl bitumen}}$$

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# Pricing in the model template

<img src="model_prices.png" width="1200px" style="display: block; margin: auto;" />
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# Sproule Prices

You can access the latest Sproule forecast [here](https://sproule.com/wp-content/uploads/2024/01/2023-12-Escalated-2.xlsx).
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# Sproule Prices

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# Production
- Production timelines will vary by facility, resource type, production technology, etc.
- Production drives the revenue side of your cash flow model
- Oil sands facilities tend to have a long ramp-up (3-4 years for mines, 1-2 years for in-situ) followed by stable production at or close to nameplate capacity for 25-50 years depending on the facility
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# Production

<img src="kirby.png" width="800px" style="display: block; margin: auto;" />
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# Production and revenue in the model template

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# Initial capital and construction costs (including land)

Expressed in cost *per flowing barrel*:

`$$\frac{\text{Project capital up-front capital cost (dollars)}}{\text{Project daily production capacity (barrels per day)}}$$`

> For example: Firebag 4 total cost was $1.7 billion for 42,500 b/d of capacity = $40,000 per *flowing barrel*

Think of the oil production from a facility as an annuity, and the cost *per flowing barrel* as the up-front payment to access that annuity for a term equal to the project life.

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# Capital cost inflation was once a major risk

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# Project operating costs and fiscal policies

You can access the data [here](https://open.alberta.ca/opendata/alberta-oil-sands-royalty-data1) and some background on oil sands royalties [here](https://www.alberta.ca/royalty-oil-sands.aspx). The [historical data](https://www.alberta.ca/historical-royalty-revenue-data.aspx) and the [Alberta Revenue Workbook](https://open.alberta.ca/dataset/382b7a1e-9c34-47c7-9531-38e67ca5441d/resource/370f9030-2d9d-48de-8f81-6e9addabd4b4/download/energy_royalty_revenue_workbook.xlsx) are going to be used in upcoming data exercises.

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# Mining Production

# In Situ Production

# Mining Revenue per Barrel

<img src="oil_proj_files/figure-html/mines rev-1.png" style="display: block; margin: auto;" />
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# In Situ Revenue Per Barrel

<img src="oil_proj_files/figure-html/in situ rev-1.png" style="display: block; margin: auto;" />
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# Sustaining capital costs

- Ongoing investment for maintenance of large facilities, including pipelines, well-pads, etc.
- Sustaining capital cost captures large expenditures, so does not include all maintenance
- Typical values are between $10-12/bbl produced for SAGD facilities, and $6-8 per barrel produced for mining operations

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# Operating costs
- Traditionally separated into gas and non-gas operating costs
- Natural gas is the single largest component for SAGD facilities.
- Some cost figures will also report labour costs as separate components of operating and sustaining capital expenditures
- Highly variable at the facility level
  - SAGD facilities tend to be in the $5-15/bbl range
  - Mining facilities have increased significantly, to $25-30/bbl (bitumen) ranges, with $40-50/bbl SCO costs in some years
  - Kearl, the only mine to not upgrade bitumen, had reported operating costs at $36-40/bbl, those decreased by about $10/bbl when the next phase came online
  - Fort Hills is...well not good

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# Mining Operating Costs

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# In Situ Operating Costs

<img src="oil_proj_files/figure-html/in situ op costs-1.png" style="display: block; margin: auto;" />
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# Fiscal policies

- Oil sands were, for a long time, the most interesting royalty issue in the province
- Historically, oil sands operations were marginal projects
- Significant dependence on the price of oil
- Role for government to encourage investment to create jobs, stimulate the economy
- *Generic oil sands royalty regime* imposed royalty rates at a fixed 1% of gross revenues until the project costs had been recovered, 25%  of net revenues afterwards
- 2008 regime introduced a sliding scale for both the base rate and the post-payout rate based on prices
  - Environmental *costs* were recognized as project costs after 2008
- 2015 Royalty Review largely left oil sands royalties unchanged
- Long run oil price outlook may make new projects challenging regardless of royalty structure

> What makes a *good* royalty regime?
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# Oil Sands Royalties

- Base royalty rate of 1% for $55/bbl and below, increasing linearly to 9% for $120/bbl
- Post-payout royalty rate of 25% up to $55/bbl, and increasing linearly to 40% for $120/bbl and above

Royalties depend on oil prices, but *what* oil price, *when* and *where*? 
- the WTI (Cushing) price for a given month, expressed in Canadian currency, calculated as the product of:

a.    the simple average of the WTI prices for the trading days of the preceding month expressed in American currency, and
    
    b.    the simple average of the daily actual USD/CAD (noon) exchange rates for that month.

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# Net Revenue Calculation
What's the net revenue for the purposes of royalty calculations?

> The amount by which the project's revenue exceeds allowed costs, minus other net proceeds. Net revenue can never be below zero.

> Calculated as Gross Revenue – Operating Costs – Capital Costs – Return Allowance – Other Costs + Other Net Proceeds.

Financing costs are exempt from net revenue calculations
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# Payout Calculation
How do you know if a project has paid back its initial investment and you're paying a net or a gross revenue royalty?

> Project payout occurs when a project’s cumulative revenues first equal or exceed its cumulative costs. Royalties are typically higher in the post-payout phase. **Once a project achieves payout it remains in the post-payout phase**.

> Payout calculation assumes unrecovered capital costs are carried at the Government Long Term Bond Rate. Think of a virtual line of credit where all expenses are spent via the line, and all revenues deposits to pay back the line. When the line is *paid off*, the project has reached *payout*.

Projects always pay the greater of the calculated net or gross revenue royalty
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# Gross Revenue Royalty

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# Net Revenue Royalty

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# Payment of Royalties
- Always has been “in-kind” for conventional, “in cash” for oil sands
- Government had not wanted to be in the upgrading/refining business, and so did not accept bitumen in lieu of cash

Under the 2008 royalty regime:
>	“The government intends to have a portion of its royalty share of bitumen in-kind commercially upgraded to higher value products in the province. The government wants to hear from companies interested in buying bitumen from the province for upgrading and other value-added activities in Alberta.”

For our purposes, that's not really important, but it does matter for producers.

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# Mining Royalties

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# In Situ Royalties

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# Mining unrecovered capital costs

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# In Situ Unrecovered Capital Costs

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# Mining Operating Profits (Post-Royalty)

<img src="oil_proj_files/figure-html/mine net profits-1.png" style="display: block; margin: auto;" />
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# In Situ Operating Profits

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# Taxes

Main tax policies include
- Federal and provincial corporate taxes
  - Capital cost allowance
  - CDE and CEE
- Other issues affect junior oil and gas companies a lot more than oil sands firms
  - e.g. flow-through shares and tax losses
  
We won't go into details on corporate taxes, but they are calculated in your model

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# The inutition in the model: commodity prices

<img src="sensitivity_oil_gas.png" width="1000px" style="display: block; margin: auto;" />
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# The inutition in the model: differentials

<img src="sensitivity_oil_hld.png" width="1000px" style="display: block; margin: auto;" />
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# Supply cost basics
- the particular project in the model I've given you has a supply cost of about $40/bbl WTI
- supply costs will vary (all else equal) with:
  - heavy oil differential (+, higher diff means higher WTI price needed)
  - CAD (+, stronger CAD (fewer CAD per USD) means higher WTI price needed)
  - gas prices (+, higher gas price means higher WTI price needed)
  - capital costs (+, higher Capital cost means higher WTI price needed)
  - operating costs (+, higher op costs means higher WTI price needed)
  - taxes and royalties (+, higher taxes mean higher WTI price needed)

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# Supply Costs in Practice

<img src="aer_bitumen.png" width="1000px" style="display: block; margin: auto;" />
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# Supply Costs in Practice

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# Key concept review

- Netback bitumen pricing
- Royalty regimes for oil sands and non-oil sands extraction in Alberta