Petroleum economics and reserves classification

In March, Prairie Crest's board must approve the year's capital budget. Lena prepares the case for the northern unit: four wells at about 8 million dollars each, gathering lines and a pad battery. The board will ask what the wells are worth today, how long they take to pay back, what could go wrong and how the project compares with others competing for the same money. The company's banks and shareholders will also see the result, because the new wells add to the reserves that Prairie Crest reports each year under US securities rules. This lesson introduces the economics of oil and gas projects and the system used to classify and report reserves. PET-450 Petroleum Economics and Reserves Evaluation goes much further.

Cash flow

An oil and gas project is evaluated on its cash flow: the money coming in from selling oil and gas minus the money going out, year by year. Revenue is production times the price received, which is the benchmark price adjusted for quality and transport. From revenue the company pays royalties to the mineral owner, production taxes where they apply, operating costs such as power, chemicals, labor, repairs and water disposal, and income taxes. Capital costs, for drilling, completion and facilities, come at the start. Abandonment and reclamation costs come at the end. The net cash flow in each year is what the project contributes to the company.

Royalties in North Dakota are set by each lease, commonly 16 to 20 percent of gross revenue for Bakken wells, and a well may have dozens of royalty owners with fractional interests. The state also levies two production taxes on oil: a gross production tax and an oil extraction tax, each 5 percent of the value of the oil under current law, with part of the revenue shared with counties and tribal governments. On federal and tribal minerals, federal royalty rules apply. Companies also pay income taxes, and US tax law lets producers deduct intangible drilling costs, such as labor and fluids, in the year they are spent, which improves early cash flow.

Time value of money

A dollar received today is worth more than a dollar received in ten years, because it can be invested in the meantime. To compare cash flows at different times, engineers discount them back to the present at a chosen rate, which reflects the company's cost of capital and the project's risk. The net present value (NPV) is the sum of the discounted cash flows:

A project with a positive NPV at the company's discount rate adds value; a negative NPV destroys it. Oil and gas companies commonly use discount rates of 8 to 15 percent, and reserve reports present values at several rates, with 10 percent the most quoted. The internal rate of return (IRR) is the discount rate at which NPV equals zero; it measures the project's return as a percentage. Payout is the time it takes for cumulative undiscounted cash flow to turn positive. Short payouts matter in tight oil, where most of a well's value comes in its first two or three years.

# Monthly cash flow for one new well (oilfield units, US dollars)
qi, b, Di, Dterm = 850.0, 1.2, 1.8, 0.08     # bbl/d, hyperbolic b, initial and terminal decline per year
capex, abandon = 8.0e6, 0.15e6               # dollars at month 0 and at end of life
opex_fixed, opex_var = 9000.0, 9.0           # dollars per month, dollars per bbl (incl. water disposal)
royalty, prod_tax = 0.1875, 0.10             # lease royalty; state gross production + extraction taxes
income_tax = 0.21                            # simplified federal rate on positive cash flow
months, econ_limit = 360, 10.0               # bbl/d

def rate(t_years):
    D = Di / (1 + b * Di * t_years)
    if D > Dterm:
        return qi / (1 + b * Di * t_years) ** (1 / b)
    t_sw = (Di / Dterm - 1) / (b * Di)
    q_sw = qi / (1 + b * Di * t_sw) ** (1 / b)
    return q_sw * 2.718281828 ** (-Dterm * (t_years - t_sw))

def evaluate(price, rate_disc=0.10):
    cum_cash, npv, payout, prod, flows = -capex, -capex, None, 0.0, [-capex]
    for m in range(1, months + 1):
        q = rate((m - 0.5) / 12)
        if q < econ_limit:
            break
        vol = q * 30.4
        rev = vol * price
        net = rev * (1 - royalty) * (1 - prod_tax)
        cash = net - opex_fixed - opex_var * vol
        cash -= max(cash, 0) * income_tax
        prod += vol
        flows.append(cash)
        cum_cash += cash
        npv += cash / (1 + rate_disc) ** (m / 12)
        if payout is None and cum_cash > 0:
            payout = m
    flows.append(-abandon)
    npv -= abandon / (1 + rate_disc) ** ((m + 1) / 12)
    return npv, payout, prod, m, flows

def irr(flows):
    lo, hi = 0.0, 10.0          # search positive rates only
    for _ in range(200):
        mid = (lo + hi) / 2
        v = sum(f / (1 + mid) ** (i / 12) for i, f in enumerate(flows))
        lo, hi = (mid, hi) if v > 0 else (lo, mid)
    return mid

for price in (50, 60, 70):                   # realized dollars per barrel after differential
    npv, payout, prod, life, flows = evaluate(price)
    print(f"price {price} $/bbl: NPV10 {npv / 1e6:5.2f} M$, IRR {irr(flows):5.0%}, payout {payout} months, "
          f"EUR {prod / 1000:,.0f} thousand bbl over {life / 12:.0f} years")

price 50 $/bbl: NPV10  1.98 M$, IRR   19%, payout 45 months, EUR 817 thousand bbl over 30 years
price 60 $/bbl: NPV10  4.85 M$, IRR   35%, payout 28 months, EUR 817 thousand bbl over 30 years
price 70 $/bbl: NPV10  7.73 M$, IRR   55%, payout 20 months, EUR 817 thousand bbl over 30 years

The program shows the shape of tight-oil economics: a large negative cash flow at the start, payout within two to four years at most prices and a long tail of smaller cash flows. It also shows how sensitive the answer is to price. Engineers run sensitivities on price, costs, initial rate and decline, and present the results as a tornado chart that ranks which uncertainty matters most. In most tight-oil evaluations, oil price and initial rate dominate.

Reserves and resources

Reserves are estimated quantities of oil and gas that are expected to be recovered commercially from known accumulations, from a given date forward, under defined conditions. Each word matters. Commercially means a project to recover them must be economic, approved or reasonably certain to be approved, with access to markets. Known accumulations means they have been discovered by wells. Defined conditions means the price, cost and regulatory assumptions are stated. Oil that has been discovered but is not yet commercial, perhaps because there is no pipeline or the price is too low, is classified as contingent resources. Oil that has not been discovered but is expected from mapped prospects is prospective resources.

Within reserves, the categories describe uncertainty. Proved reserves (1P) are those that can be estimated with reasonable certainty; when probabilistic methods are used, there should be at least a 90 percent chance that the quantity actually recovered will equal or exceed the estimate. Probable reserves are additional quantities that are as likely as not to be recovered; proved plus probable (2P) has at least a 50 percent chance. Possible reserves are less likely still; proved plus probable plus possible (3P) has at least a 10 percent chance. Reserves are also split by development status: proved developed producing, proved developed non-producing and proved undeveloped, which need new wells or major spending.

The framework most companies follow is the Petroleum Resources Management System (PRMS), maintained by the Society of Petroleum Engineers with other professional societies. Its most recent full edition dates from 2018, with application guidelines updated since. National securities regulators set the rules for what public companies must disclose, and they build on PRMS concepts with important differences.

In the United States, the Securities and Exchange Commission (SEC) sets the rules, last overhauled in its 2008 modernization of oil and gas reporting. Public companies must disclose proved reserves; probable and possible reserves are optional, and few report them. Reserves must be economic at a price equal to the unweighted average of the first-day-of-the-month prices over the previous twelve months, held flat, not at forecast prices. Proved undeveloped reserves generally must be scheduled for drilling within five years. Companies also disclose a standardized measure of discounted future net cash flows at 10 percent, and many hire independent engineering firms to prepare or audit their estimates.

Price assumptions and risk

No input to an economic evaluation is more uncertain than price. Oil prices have swung from under 20 dollars to over 140 dollars a barrel within a few years, and gas prices are just as volatile. Companies use a planning price deck, often a set of forecasts from independent evaluators, and test projects at low and high cases. Many producers hedge part of their production for the next year or two with futures, swaps or options, locking in prices that protect their cash flow and capital program. Lenders base their credit limits on the value of a company's reserves at conservative prices, so a price collapse can shrink a company's borrowing capacity just when it needs cash.

Other risks are also built into the analysis. Geological risk, the chance that a well is poorer than expected, is handled with chances of success and ranges of outcome. Cost overruns, delays in pipeline access, regulatory changes, carbon costs and abandonment liabilities all affect value. Comparing projects on risked NPV, NPV per dollar invested and payout lets managers build a portfolio that balances quick returns, long-life production and exposure to price.