casemark/evaluating-upstream-energy-assets

Evaluating Upstream Energy Assets

Assesses upstream oil and gas assets with reserve estimation, production decline curves, and net asset value modeling.

When To Use

• Evaluating an acquisition or divestiture of producing properties, PDP reserves, or undeveloped acreage
• Reviewing a third-party reserve report (e.g., from DeGolyer & MacNaughton, Ryder Scott, or Netherland Sewell)
• Building or auditing a net asset value (NAV) model for an E&P company or asset package
• Benchmarking production decline rates against type curves for a given basin or formation
• Underwriting reserve-based lending (RBL) or mezzanine capital for upstream operators

Inputs To Gather

• Reserve report: Proved (1P), proved + probable (2P), and proved + probable + possible (3P) volumes by category (PDP, PDNP, PUD) [VERIFY classification methodology — SPE-PRMS vs. SEC definitions]
• Production history: Monthly oil, gas, and NGL volumes by well or lease, ideally 24+ months
• Decline curve parameters: Initial production (IP) rates, b-factor, Di (initial decline rate), terminal decline rate
• Commodity price assumptions: Strip pricing or flat-price scenarios for WTI, Henry Hub, and relevant basis differentials
• Operating cost data: Lease operating expense (LOE) per BOE, workover frequency and cost, G&A allocation
• Capital program: Drilling & completion (D&C) cost per well, number of planned PUD locations, AFE detail if available
• Fiscal terms: Royalty burden, net revenue interest (NRI), severance/ad valorem tax rates [VERIFY by state/jurisdiction], any overriding royalty interests (ORRIs)
• Acreage position: Held-by-production (HBP) status, lease expirations, continuous drilling obligations

Workflow

1. Classify reserves and reconcile volumes

   • Map reserves into PDP, PDNP, and PUD categories
   • Reconcile operator-reported reserves against third-party engineer estimates
   • Flag any reserve bookings that lack offset well support or rely on analogy from distant formations
   • Note the R/P ratio (reserves-to-production) for reasonableness — PDP R/P above 15 years or below 3 years warrants scrutiny

2. Fit decline curves to production data

   • Plot monthly production on a semi-log or log-log scale to identify decline regime (exponential, hyperbolic, harmonic)
   • Fit Arps decline parameters (b-factor, Di) to historical data; flag if b > 2.0 (physically implausible for boundary-dominated flow)
   • For unconventional wells (shale/tight), consider modified hyperbolic with a terminal decline switch (typically 5–8% annual)
   • Compare fitted EUR (estimated ultimate recovery) per well against reserve report EURs — variance > 15% needs explanation

3. Build the net asset value (NAV) model

   • Project production volumes by category using fitted decline curves for PDP and type curves for PUD
   • Apply commodity price deck (strip, management case, or stress case) with appropriate basis differentials and quality adjustments (API gravity, BTU content)
   • Deduct LOE, G&A, production taxes, and capital expenditures for PUD development
   • Discount net cash flows at 10% (SEC PV-10 standard) and at risk-adjusted rates (typically 12–20% depending on reserve category):
     • PDP: 10–12%
     • PDNP: 12–15%
     • PUD: 15–20%+ depending on development certainty
   • Deduct net debt, asset retirement obligations (ARO), and corporate overhead to arrive at equity NAV

4. Stress-test key assumptions

   • Run commodity price sensitivities (±$10/bbl WTI, ±$0.50/MMBtu gas)
   • Vary D&C costs ±15% to test PUD economics breakeven
   • Assess impact of accelerated decline (b-factor reduction) on PDP value
   • Evaluate lease expiration risk — quantify acreage at risk and associated PUD value exposure

5. Assess operational and geological risk factors

   • Well concentration: single-well or single-pad dependency
   • Midstream constraints: takeaway capacity, gas processing agreements, flaring limitations [VERIFY local regulations]
   • Water disposal: SWD well access, induced seismicity risk in sensitive basins (e.g., Oklahoma, parts of Permian)
   • Environmental/regulatory: plugging liability, bonding requirements, emissions compliance [VERIFY state-specific rules]
   • Operator quality: track record on cycle times, capital discipline, and LOE management

Output

The evaluation report should include:

• Executive summary: Asset overview, headline NAV range, key value drivers and risks
• Reserve summary table: Volumes by category (oil/gas/NGL) with SEC and strip-price PV-10
• Decline curve exhibit: Production plots with fitted parameters and EUR comparison vs. reserve report
• NAV waterfall: PDP value → add PDNP → add PUD → deduct ARO/debt → equity NAV, shown at multiple price/discount rate scenarios
• Sensitivity matrix: NAV under commodity price, cost, and decline rate variations
• Risk register: Itemized geological, operational, regulatory, and fiscal risks with materiality assessment
• Recommendation: Buy/pass/conditional with identified diligence items

Quality Checks

• Confirm reserve classifications align with SEC or SPE-PRMS definitions as appropriate [VERIFY which standard applies]
• Verify that decline curve fits use sufficient production history (minimum 6 months post-flush for unconventionals)
• Check that NRI and royalty burden sum correctly across all interests (working interest × (1 − royalty burden) = NRI)
• Ensure D&C cost assumptions reflect current service cost environment, not stale AFEs
• Validate that the price deck matches the stated date and source (NYMEX strip, OPIS, internal forecast)
• Confirm ARO estimates are based on current plugging cost data, not outdated flat assumptions
• Cross-check NAV output against recent comparable transactions ($/BOE, $/acre, $/flowing barrel) for reasonableness