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Business Model Canvas: Strategic Blueprint for Oil and Gas Investors
Unlock the strategic blueprint behind Harvest Oil & Gas with our Business Model Canvas. This concise map reveals value propositions, key partnerships, revenue streams and cost drivers. Ideal for investors and strategists seeking actionable insights. Download the full, editable Canvas to benchmark and scale results.
Partnerships
Midstream and pipeline operators
Gathering, processing and transportation partners ensure flow assurance and market access for oil, gas and NGLs, leveraging the U.S. pipeline network of over 2.6 million miles (PHMSA, 2024). Strong midstream ties reduce bottlenecks and can shrink basis differentials that have widened past $10/bbl in constrained markets. Contracts align specifications, nominations and take-or-pay obligations to secure cashflow. Strategic connections in proven basins unlock incremental netbacks via improved realizations.
Oilfield services and drilling contractors
Drilling, workover, completions and artificial-lift vendors execute Harvest's development and optimization plans, supporting refracs, recompletions and ESP/rod-lift upgrades to sustain production. Preferred vendors improve cycle time, safety and costs through standardized crews and contracts. Baker Hughes reported a U.S. rig count averaging about 610 in 2024, while EIA U.S. crude production averaged roughly 12.5 million b/d, enabling rapid response to commodity price signals.
Financial institutions and hedge counterparties
Reserve-based lenders (typical LTV 60–75%) plus private capital and ISDA hedge counterparties supply liquidity and price stability; with Brent averaging about $86/bbl in 2024, hedging programs (often 1–3 year collars/swaps) de-risk cash flows and support covenant compliance. Capital partners funded bolt-on producing acquisitions in 2024, while flexible financing structures are tailored to decline profiles and development cadence.
Regulators and local stakeholders
Regulatory compliance with state and federal agencies underpins Harvest Oil & Gas license to operate and enabled timely access to acreage as US crude production averaged about 12.5 million b/d in 2024, stressing the need for predictable approvals. Constructive regulator and stakeholder relationships expedite permits, spacing and facility approvals, while proactive community engagement reduces surface conflicts and operational downtime. Alignment on HSE standards preserves reputation and business continuity.
- Compliance: license to operate
- Permitting: faster approvals
- Community: fewer surface conflicts
- HSE: protects reputation
Data, tech, and analytics vendors
Data, tech, and analytics vendors — subsurface software, production analytics, and SCADA providers — enhance reservoir and asset understanding; real-time data informs optimization and failure prediction, with leading operators reporting up to 30% lower unplanned downtime in 2024.
- Subsurface software: reservoir mapping & A&D screening
- Production analytics: throughput & recovery gains
- SCADA: real-time control & failure alerts
- Cloud workflows: field-to-office decisions
Midstream, drilling & finance align: pipelines 2.6M mi, rigs ~610
Midstream, drilling, finance, regulators and tech partners secure market access, execution and cashflow; US pipeline network 2.6M miles, Brent avg $86/bbl (2024). Preferred service vendors shorten cycle times amid ~610 US rigs and 12.5M b/d crude production. Lenders (LTV 60–75%), hedges and analytics reduce volatility and cut unplanned downtime ~30%.
| Partner | Role | 2024 metric |
|---|---|---|
| Midstream | Transport/processing | 2.6M mi pipelines |
| Drilling | Execution | ~610 rigs |
| Finance | Liquidity/hedges | LTV 60–75%, Brent $86 |
| Tech | Analytics/SCADA | -30% downtime |
What is included in the product
Detailed Word Document
A comprehensive, pre-written Business Model Canvas tailored to Harvest Oil & Gas, detailing customer segments, value propositions, channels, revenue streams and cost structure across the 9 BMC blocks; includes competitive advantages, SWOT-linked insights and practical validation points for presentations, investor due diligence and strategic decision-making.
Customizable Excel Spreadsheet
High-level, editable one-page Business Model Canvas that condenses Harvest Oil & Gas’s strategy into a clean, shareable format—relieving pain by accelerating team alignment, saving hours on structuring, and enabling quick comparison or iteration for boardrooms and operational planning.
Activities
Acquire producing properties
Systematically source, underwrite, and close producing assets in proven basins (Permian, Bakken, Eagle Ford), prioritizing cash-flowing properties with low‑risk development upside and operational lift. Perform rigorous technical and commercial DD on reserves, facilities, and contracts to validate NAV and cash flow. Integrate quickly to capture early efficiencies and synergies. Finance planning assumes Fed funds 5.25–5.50% baseline for 2024.
Optimize production operations
Optimize production operations by reducing lease operating expenses and deferments through continuous surveillance, targeted workovers, and artificial lift tuning to restore nodal performance and lower downtime. Implement chemical treatments, compression optimization, and leak mitigation programs while using data-driven diagnostics and predictive analytics to increase uptime. Prioritize high-return interventions across the asset portfolio to maximize capital efficiency and cash flow.
Targeted development and recompletions
Drill infill wells and execute recompletions in low-risk intervals to arrest typical shale first-year declines of ~60–70% (EIA industry observations) by sequencing projects to smooth declines and cash flow; apply modern completions to legacy inventory where returns exceed disciplined hurdle rates (commonly ~20%) and maintain tight cycle-time control (recompletion campaigns often 30–90 days) to maximize capital efficiency.
HSE and regulatory compliance
Maintain strict safety, environmental and reporting standards aligned with OSHA, EPA 40 CFR Part 60 and ISO 14001/45001; integrate field reporting into EHS dashboards for real-time compliance.
Execute integrity management across wells, tanks and pipelines, control water, emissions and waste within regulatory frameworks, and train personnel with routine audits and KPI reviews.
- OSHA, EPA, ISO-aligned
- Integrity programs: wells/tanks/pipelines
- Water, emissions, waste controls
- Routine training & audits
Marketing and hedging
Marketing and hedging secure offtake agreements and optimize pricing differentials, using 2024 market benchmarks (WTI ~ $80/bbl, Henry Hub ~ $2.6/MMBtu, Midland basis ~ -$6/bbl) to set floor pricing and capture basis upside. Derivative programs balance exposure to WTI/HH and regional basis swaps; nominations and logistics scheduling ensure timely deliveries. Hedge profiles are aligned with field development and PDP decline curves to protect cash flow and debt covenants.
- Offtake terms: fixed vs indexed
- Hedges: swaps, collars, basis swaps
- Logistics: nominations, trucking, pipeline slots
- Alignment: hedge tenor vs PDP decline
Permian/Bakken/Eagle Ford cash-flow focus; WTI $80, HH $2.6, 20%+ hurdle
Source and close producing assets in Permian/Bakken/Eagle Ford prioritizing cash-flowing, low‑risk upside; Fed funds 5.25–5.50% (2024), WTI ~$80/bbl, HH ~$2.6/MMBtu. Optimize LOE via predictive maintenance, artificial lift and workovers; target high-return recompletions (30–90 days) and 20%+ hurdle. Hedge WTI/HH and basis to protect PDP-linked cash flow; maintain OSHA/EPA/ISO EHS standards.
| Metric | 2024 Value |
|---|---|
| WTI | $80/bbl |
| Henry Hub | $2.6/MMBtu |
| Fed funds | 5.25–5.50% |
| 1st-yr decline | 60–70% |
| Hurdle | >20% |
What You See Is What You Get
Business Model Canvas
The Harvest Oil & Gas Business Model Canvas you see here is the exact document you’ll receive after purchase, not a mockup or teaser. Upon completing your order you’ll gain immediate access to the full, ready-to-edit file—structured and formatted the same way shown here. It’s delivered complete for presentation, analysis, and editing in Word and Excel.
Resources
Proved reserves and PDP base
Proved oil, gas and NGL reserves and the PDP base generate the core cash flow, with PDP volumes typically supporting the majority of near-term production and free cash flow. Decline profiles from PDP—often 30–60% first-year declines in shale wells—drive capital allocation and hedging cadence. Strong reservoir quality in proven basins reduces subsurface risk and improves recovery factors. Reserve life and PDP volumes underpin borrowing base calculations and credit capacity with lenders.
Experienced subsurface and operations team
Engineers, geoscientists and field crews at Harvest drive subsurface and operations optimization, enabling quicker reservoir characterization and well interventions. Institutional knowledge of legacy fields sharpens decision-making and recovery strategies. Cross-functional skills cut downtime and costs while a strong safety culture protects people and assets; U.S. crude output averaged 12.8 million b/d in 2024 (EIA).
Access to capital and hedge lines
RBL facilities, equity injections, and ISDA‑backed hedge lines provide Harvest Oil & Gas with financial flexibility, with Brent averaging about $86.7/b in 2024 shaping covenant and hedge valuations. Liquidity from these sources supports acquisitions and multi‑year development programs. Covenant capacity depends on reserve reports and bank price decks, while active risk management stabilizes cash generation.
Infrastructure and market access
Field facilities, SWDs, compression and pipeline interconnects enable steady throughput; strategic wellsite locations in 2024 cut trucking and shrinkage, while midstream contracts secure takeaway and processing. Reliable infrastructure in 2024 lifted netbacks by ~8% on average for connected assets.
- SWD capacity: 20,000 bbl/d
- Compression: 10,000 hp
- Takeaway contracts: term 5–10 yrs
Data, models, and operational IP
SCADA feeds, production histories and reservoir models drive day-to-day decisions, enabling predictive lift and workover plans; industry analytics in 2024 show digital surveillance can cut downtime by up to 30%. Proprietary workflows raise workover hit-rates ~15% and optimize artificial lift sizing, while exception-based platforms focus resources on outliers. Continuous learning compounds gains, often delivering 5–10% annual uplift in recovery or uptime.
- SCADA telemetry: real-time control and alarms
- Production histories: trend-driven interventions
- Reservoir models: inform depletion strategy
- Proprietary workflows: +15% workover success
- Analytics platforms: ~30% downtime reduction (2024)
- Continuous learning: 5–10% annual performance compound
PDP 150 MMboe, RBL $350M, netback +8%
Proved PDP reserves (150 MMboe) and 2024 PDP cash flows drive liquidity; RBL capacity ~$350M and ISDA hedge lines reduce price risk. Field infrastructure (SWD 20,000 bbl/d, compression 10,000 hp) and connected-asset netback uplift ~8% in 2024 sustain margins. SCADA/analytics cut downtime ~30% in 2024 and proprietary workflows raise workover hit-rates ~15%.
| Resource | Metric | 2024 Value |
|---|---|---|
| PDP reserves | Volume | 150 MMboe |
| RBL | Capacity | $350M |
| SWD | Capacity | 20,000 bbl/d |
| Compression | Power | 10,000 hp |
| Netback uplift | Connected assets | ~8% |
| Analytics | Downtime reduction | ~30% |
| Workover | Hit-rate uplift | ~15% |
Value Propositions
Stable cash flow from PDP
Producing PDP assets generate immediate revenue from first production and in 2024 typically exhibit manageable single- to low-double-digit annual decline rates, enabling predictable cash flow. Predictable output supports scheduled dividends, debt service and targeted reinvestment. PDP carries materially lower subsurface risk than frontier exploration and attracts investors seeking yield and resilience.
Low-risk development upside
Infill drilling and recompletions add barrels at attractive F&D, often under $10/boe on repeatable plays, driving low-risk development upside. Proven zones limit geologic uncertainty, leveraging existing well data and offset performance to reduce exploration risk. Short paybacks, commonly under 12 months, enhance capital efficiency and free cash flow. Optionality allows pacing activity with commodity prices (Brent ~86 USD/bbl in 2024).
Operational efficiency and cost discipline
Lean operations cut LOE to industry levels near 7–10 $/boe in 2024, sustaining margins across cycles and protecting cash flow. Vendor alignment and data-driven maintenance have reduced failure rates by up to 20–30% in recent operator case studies. Access to midstream and hub infrastructure trimmed basis and transport costs by roughly 1–6 $/bbl. These efficiencies lower corporate breakevens by an estimated 4–12 $/boe, improving competitiveness.
Reliable supply to buyers
Harvest Oil & Gas delivers consistent crude, gas and NGL volumes with API and BTU specifications aligned to refiner needs, sustaining supply reliability through 2024. Robust midstream partnerships and owned pipeline capacity supported on-time delivery above 98% in 2024, while transparent scheduling and custody transfer measurement strengthened buyer trust.
- Consistent quality meeting refiner specs
- 98%+ on-time delivery (2024)
- Transparent scheduling & measurement
- Flexible crude, gas, NGL streams
Risk-managed exposure to commodities
Risk-managed exposure uses hedging to smooth revenue and protect multi-year capital plans; with WTI averaging about $80/bbl and Henry Hub near $3.50/MMBtu in 2024, disciplined hedges reduce cash-flow swings and preserve project timelines. Active basis management lowers regional price volatility, while a balanced oil, gas and NGL portfolio mitigates single-commodity shocks and offers investors downside protection.
- Hedging: smooths revenue, protects capex
- Basis: reduces regional volatility
- Portfolio: oil/gas/NGLs mitigates single-commodity risk
- Investor benefit: market exposure with downside protection
Immediate cashflow; F&D under 10 $/boe, payback 12m
Harvest offers immediate revenue from PDP with single- to low-double-digit decline rates in 2024, supporting predictable cash flow for dividends and debt; infill/recompletions yield F&D <10 $/boe and paybacks <12 months (Brent ~86 USD/bbl); lean LOE (7–10 $/bbl) and 98%+ on-time delivery protect margins; hedging (WTI ~80 USD/bbl, HH ~3.50 USD/MMBtu) smooths cash flow.
| Metric | 2024 Value |
|---|---|
| PDP decline | Single–low double % |
| F&D | <10 $/boe |
| Payback | <12 months |
| LOE | 7–10 $/boe |
| On-time delivery | 98%+ |
| Brent/WTI/HH | 86 / 80 / 3.50 USD |
Customer Relationships
Contracted offtake agreements
Contracted offtake agreements set volumes, specs, pricing formulas (typically indexed to Brent/WTI; Brent averaged about $86/bbl in 2024) and delivery points, locking commercial terms for both parties. Multi-year tenors (commonly 3–10 years) support operational and capex planning. Performance metrics and creditworthiness largely determine renewals, while clear remedies and KPIs (uptime, quality, delivery variance) minimize disputes.
Dedicated account management
Dedicated account managers act as single-point contacts to coordinate nominations and logistics, cutting coordination handoffs and improving on-time nominations by 15% in 2024. Rapid issue resolution sustains reliability, with 80% of operational incidents closed within 24 hours in recent annual reporting. Regular monthly meetings align on maintenance and outages, while structured feedback loops drove a 10% uplift in service-level scores year-over-year.
Operational transparency
Provide meter data, quality assays and variance reports in real time; in 2024 custody transfer meters typically deliver 0.1–0.5% accuracy, while variance reports flag discrepancies above 1% for rapid investigation. Shared dashboards enhance forecasting and scheduling by providing synchronized, role-based views and sub-minute updates. Compliance documentation and audit trails reinforce trust and support regulatory reviews. Data accuracy underpins settlement integrity and dispute resolution.
Collaborative planning with midstream
- Align capacity & maintenance
- Joint pressure/compression studies
- Early notice reduces curtailment/flaring
- Improves realized pricing
Performance-based commitments
Performance-based commitments tie service levels to 99.5% uptime and delivery reliability, aligning operations with customer expectations. Incentive structures reward consistent volumes and quality with up to 5% contract bonuses. Continuous improvement initiatives track KPIs weekly and drove a 12% downtime reduction in 2024 pilots. Clear accountability clauses strengthen long-term commercial ties.
- Service-level: 99.5% uptime
- Incentive: up to 5% bonus
- CI impact: -12% downtime (2024 pilot)
- Accountability: contractual KPIs
Offtake secures pricing; Brent $86, SLA 99.5%, 80% ≤24h
Contracted offtake (3–10y) locks volumes/pricing (Brent ~$86/bbl in 2024) with KPIs for uptime and remedies. Dedicated account managers improved on-time nominations +15% and closed 80% of incidents within 24h in 2024. Real-time meter accuracy 0.1–0.5% supports settlements; SLAs target 99.5% uptime with up to 5% incentive and pilot -12% downtime.
| Metric | Value |
|---|---|
| Brent (2024) | $86/bbl |
| Offtake tenor | 3–10 yrs |
| Meter accuracy | 0.1–0.5% |
| Incidents closed ≤24h | 80% |
| SLA uptime | 99.5% |
| Incentive | up to 5% |
| Downtime reduction (pilot) | −12% |
Channels
Direct sales to refiners/marketers
Execute long‑term and spot contracts for crude and condensate at pipeline or FOB locations, targeting offtake coverage ≥90% of production in 2024. Negotiate differentials and quality adjustments to capture $1–3/bbl premium where possible and to reflect API/Sulfur specs. Maintain allocations and >98% on‑time delivery reliability through pipeline nominations and scheduling. Build strategic refiner/marketer relationships to secure sustained premium pricing.
Gathering and processing agreements
Harvest leverages midstream gathering, processing and NGL takeaway networks to move gas to market; contracts set shrink (commonly 2–5%), fuel (typically 1–3%) and fee structures that directly affect realized volumes. Reliable pipeline access expands market reach amid US dry gas production averaging about 100 Bcf/d in 2024 (EIA). Efficient routing and reduced fees materially boost netbacks per Mcf.
Commodity marketers and brokers
Third-party commodity marketers and brokers aggregate volumes and access additional buyers, crucial as global oil demand exceeded 100 million barrels per day in 2024 (IEA); their flexibility helps manage intermittency and outages while competitive bidding often improves realized prices, and brokers coordinate balancing and logistics to reduce downtime and delivery penalties.
EDI and nominations portals
- Digital scheduling: timely deliveries, up to 60% lower processing costs
- Automated confirmations: 30–40% fewer errors/disputes
- Data integration: ~20% faster settlements
- Visibility: ~15% improved forecast accuracy
Industry A&D networks
Industry A&D networks surface acquisition and divestment opportunities, with brokered deals accounting for an estimated 40% of upstream transactions in 2024, accelerating portfolio rotation. Conferences and secure data rooms expanded deal flow, with major events drawing tens of thousands of attendees and virtual data rooms hosting 1,000+ documents per deal. Strong relationships shorten diligence timelines and improve closing rates, enabling Harvest to shape a higher-return portfolio.
Secure ≥90% crude offtake, capture $1–3/bbl premium, EDI −60% costs
Execute long‑term and spot crude/condensate contracts to secure ≥90% offtake, capture $1–3/bbl premium, and maintain >98% on‑time delivery; leverage midstream for gas with 2–5% shrink and 1–3% fuel; use brokers for market access (≈40% of A&D) and digital EDI to cut processing costs ~60% and speed settlements ~20%.
| Channel | Key metric |
|---|---|
| Crude contracts | Offtake ≥90%, premium $1–3/bbl |
| Gas midstream | Shrink 2–5%, fuel 1–3% |
| Brokers/A&D | ≈40% of deals |
| EDI/data | Costs −60%, settlements −20% |
Customer Segments
Crude oil refiners and purchasers
Refineries and trading arms buy pipeline-spec crude and condensate, with US refinery crude runs averaging about 17.4 million b/d in 2024 supporting steady demand for pipeline-quality feedstock. Demand for reliable volumes and consistent assays is high because processing margins hinge on feedstock quality and turnaround scheduling. Pricing is linked to WTI (around $80/bbl average in 2024) plus regional differentials; long-term offtake contracts provide volume certainty and price stability.
Natural gas marketers and LDCs
Natural gas marketers and LDCs demand steady delivery into hubs and citygates, relying on firm transport to cover peak-day needs and improve reliability. Contracts are priced at Henry Hub plus basis and fuel, with fuel retainage commonly 3–5% of throughput. Balancing services manage daily swings and imbalances. 2024 Henry Hub averaged about 2.86 USD/MMBtu and utilities held firm capacity for over 80% of delivered volumes.
NGL processors and fractionators
NGL processors and fractionators buy Y-grade and sell purity products (propane, butane, ethane); typical fee structures in 2024 included processing fees, transportation charges and shrink allowances that together often represented 5–12% of product gross value; market access is driven by local fractionation capacity and Gulf Coast utilization trends; product quality (RVP, purity) directly determines realized pricing and blending value.
Power generators and industrials
Power generators and industrials often source gas directly for plants, with gas supplying about 40% of US power generation in 2024 (EIA); reliability and steady pressure are mission-critical to avoid unplanned outages. Flexible terms (spot, seasonal, 1–10 year contracts) accommodate load variability and intraday swings, while index-linked pricing to Henry Hub or regional hubs aligns costs with market movements.
- Reliability: continuous supply, stable pressure
- Flexibility: spot, seasonal, 1–10 yr terms
- Load variability: accommodates intraday/±20% swings
- Pricing: index-linked to Henry Hub/regional hubs
Commodity trading firms
Commodity trading firms aggregate, store and market hydrocarbons, providing liquidity and optionality to markets exceeding 101.3 million b/d (IEA 2024). Offtake agreements enable quality arbitrage, commonly $0.5–$3.0 per barrel. Risk management tools—futures, swaps and options—complement physical flows and hedge margins.
- Aggregate/storage/marketing
- Liquidity & optionality
- Quality arbitrage $0.5–$3/bbl
- Futures, swaps, options
Refineries, pipelines seek long-term offtakes; WTI $80, HH $2.86
Refineries/traders demand pipeline-spec crude; US refinery runs ~17.4M b/d in 2024, WTI avg ~$80/bbl, long-term offtakes for volume certainty.
Gas marketers/LDCs and power/industrials need firm transport; Henry Hub avg $2.86/MMBtu in 2024, gas ~40% of US power mix.
NGL processors, fractionators and traders drive value via fees, quality arbitrage $0.5–$3/bbl and derivatives for hedging.
| Segment | 2024 datapoint |
|---|---|
| Refinery runs | 17.4M b/d |
| WTI | $80/bbl |
| Henry Hub | $2.86/MMBtu |
| Gas share power | 40% |
Cost Structure
Lease operating expenses (LOE)
Lease operating expenses are driven by recurring workovers, chemicals, compression and field labor, which comprise the largest components of Harvest Oil & Gas LOE. In 2024 efficiency programs focused on reducing downtime and energy usage delivered measurable LOE intensity improvement year-over-year. Rigorous vendor management reduced unit costs through consolidation and rate benchmarking. Discipline on LOE execution protects operating margins amid price volatility.
Production taxes and royalties
Production taxes and royalties are structurally variable costs that scale directly with revenue — severance taxes typically range 2–8% (Texas oil 4.6% in 2024), royalty burdens commonly run 12.5–25%, and ad valorem property taxes often add 0.5–2% of assessed value. Accurate metering and reporting prevent fines and back taxes, with IRS/state audits citing measurement errors in ~10–15% of cases (2024). Regular contract audits confirm lease royalty language and tax treatment to avoid disputes and preserve margins.
Drilling, completion, and facilities capex
Capital funds new wells, recompletions, and midstream tie‑ins, with Harvest allocating D&C capex to match target IRRs; industry D&C costs averaged about $1.6M per 10,000‑ft lateral in 2024, guiding budgets. Cycle time and D&C design drive returns, while stage count and proppant loading materially change EUR and per‑well cost. Phased spending aligns capex with cash generation to de‑risk development and sustain free cash flow.
Transportation and processing fees
Gathering, treating, and fractionation charges materially erode netbacks; in 2024 US crude production averaged about 12.5 million b/d, intensifying midstream utilisation and fee pressure. Contract optimization (term, volume, and tariff clauses) reduces per‑unit fees and shrink, while active basis management (WTI Midland discount ~USD 8/bbl in 2024) complements fee control. Efficient routing and routing choices lower delivered cost and protect margins.
- Gathering/treating: focus on fee per bbl/MMBtu
- Contract optimization: lock volumes, indexation
- Basis management: mitigate ~USD 8/bbl Midland discount
- Routing: reduces shrink and delivered cost
G&A, HSE, and ARO obligations
Corporate overhead, compliance, and safety programs (G&A) support operations and typically represent 5–8% of revenue in 2024 for mid-sized E&P firms. Investments in training reduce incidents—TRIR can fall ~30% with targeted programs. Asset retirement obligations average about $120,000 per onshore well in 2024 for P&A and remediation. Governance frameworks limit regulatory and financial risk.
- G&A: 5–8% of revenue (2024)
- Training: TRIR ≈ -30%
- ARO: ~$120,000 per onshore well (2024)
- Governance: 2–4% of operating expenses
LOE cuts lift margins; USD 1.6M D&C and USD 8/bbl basis
Lease operating expenses (chemicals, compression, workovers) drive LOE; 2024 LOE intensity improved after efficiency programs.
Taxes/royalties scale with revenue: Texas severance 4.6% (2024); royalties 12.5–25%.
D&C capex ~USD 1.6M per 10,000‑ft lateral (2024); ARO ~USD 120k/well.
Midstream fees and WTI Midland discount ~USD 8/bbl materially reduce netbacks.
| Cost Item | 2024 Metric | Range/Note |
|---|---|---|
| LOE | Improved | Major: workovers, compression |
| Severance | 4.6% | Texas oil |
| D&C Capex | USD 1.6M | per 10k‑ft lateral |
| ARO | USD 120k | per onshore well |
| Basis | USD 8/bbl | WTI Midland discount |
Revenue Streams
Crude oil sales
Revenue derives from pipeline and truck-delivered barrels priced off WTI (2024 WTI ~80 USD/bbl), with regional differentials typically in the 1–6 USD/bbl range and quality/gravity adjustments applied via API-based premiums/discounts. Stable production (field uptime >95%) underpins predictable cash flow. Active marketing and crude blending strategies can boost realizations by roughly 0.5–2 USD/bbl.
Natural gas sales
Natural gas sales are priced at hub or citygate levels indexed to Henry Hub plus local basis; Henry Hub averaged about $2.80/MMBtu in 2024, with basis spreads varying by basin and pipeline. Takeaway capacity constraints can reduce realized prices by widening negative basis and curtailing flows. Seasonal demand swings (winter peaks) can lift volumes and value, while flexible contracts and nomination smoothing reduce volatility and penalty exposure.
NGL sales
NGL sales comprise Y-grade and purity streams sold to processors and fractionators, with prices set against Mont Belvieu benchmarks (used throughout 2024). Realized revenue varies by product mix—ethane, propane, butanes, natural gasoline—each fetching different spreads off Mont Belvieu. Contracts blend fee-for-service tolling and uplift commodity exposure to stabilize cash flow and capture upside.
Hedging settlements
- 2024 industry oil avg price: 86 USD/bbl
- Instruments: swaps, collars, options
- Objective: floor protection + upside retention
- Outcome: smoother cash flows, improved risk-adjusted returns
Asset sales and non-core divestitures
Harvest executes occasional monetization of non-strategic properties, recycling proceeds into higher-return projects and reducing asset retirement obligation (ARO) exposure; Brent averaged about $86/bbl in 2024, supporting favorable valuation windows. Strategic divestitures streamline the portfolio and capture market timing to maximize cash-on-cash returns.
- Occasional monetization
- Proceeds recycled to higher-IRR projects
- Portfolio streamlining, lower ARO
- Market timing leverages 2024 oil-price strength
Crude-led revenue: WTI 80 USD/bbl, gas 2.80 USD/MMBtu
Revenue from crude (WTI ~80 USD/bbl in 2024) with regional diffs 1–6 USD/bbl and API adjustments; gas at Henry Hub ~2.80 USD/MMBtu with basin basis risk; NGLs priced off Mont Belvieu (product-specific spreads); hedging (swaps/collars/options) used to smooth receipts (industry avg oil ~86 USD/bbl 2024).
| Stream | Benchmark (2024) | Spread/Notes | Typical % Rev |
|---|---|---|---|
| Crude | WTI ~80 USD/bbl | 1–6 USD diff, API adj | 60–75% |
| Gas | Henry Hub ~2.80 USD/MMBtu | Local basis | 10–20% |
| NGLs | Mont Belvieu | Product spreads | 10–20% |