FAQs

1. What is asset rationalization?

Asset rationalization is the strategic assessment of oil and gas portfolios to identify core assets, divest non‑core properties, reduce operational complexity, and align long‑term capital deployment with business objectives.

2. Why is asset rationalization important in Western Canada?

With rising regulatory expectations, capital discipline, and evolving market conditions, companies are prioritizing assets with stronger economics while reducing exposure to liabilities, high‑decline assets, and fragmented positions.

3. How do A&D transactions support asset rationalization?

A&D transactions enable companies to reshape their portfolios by acquiring assets that strengthen strategic positions or divesting properties that no longer fit. They provide a disciplined mechanism to optimize value while managing risk.

4. Why are A&D timelines often tight and complex?

Competitive sales processes, regulatory approval windows, financing constraints, and deal milestones require rapid, accurate decision‑making across multiple technical, commercial, and operational disciplines.

5. What role does the Land department play in A&D?

The Land team verifies mineral and surface title, reviews contracts, identifies obligations, prepares conveyance documentation, manages regulatory submissions, and supports post‑closing integration, making them essential to smooth execution.

6. What risks arise from incomplete Land due diligence?

Delays or gaps can lead to missed obligations, incorrect valuation assumptions, regulatory issues during transfers, unexpected liabilities, and post‑closing disputes, all of which can jeopardize the transaction.

7. How does Sproule ERCE support A&D transactions?

Sproule ERCE provides full‑cycle Land expertise, including due diligence, risk identification, conveyance preparation, closing coordination, and post‑closing data integration, helping companies close with confidence and maintain momentum throughout the transaction lifecycle.

Explore our full article “Asset Rationalization: Why Timely Land Support Matters in A&D Transactions” for detailed insights into the A&D lifecycle and best practices for effective asset management:

🔗 Asset Rationalization: Timely Land Support in A&D Transactions – Sproule ERCE

1. What is a Competent Person’s Report (CPR)?

A Competent Person’s Report (CPR) is an independent reserves and resources report for a company’s oil, gas, or mining assets. It is used on the London Stock Exchange (LSE) and other European Exchanges governed by the European Securities and Markets Authority (ESMA) regulations.

2. What are the regulatory requirements for a CPR?

The content of a CPR is governed by specific regulatory bodies, with the most commonly referenced being the European Union agency responsible for overseeing financial market regulations across EU member states, and the domestic regulator in the United Kingdom.

3. What standards must a CPR adhere to?

A CPR must be prepared in accordance with an appropriate reserves and resources standard as specified by the particular exchange. Examples include SPE-PRMS and COGEH. The Competent Person (CP) preparing the CPR must be professionally qualified, have at least five years of relevant experience, be independent of the company, and not be remunerated based on the findings of the CPR.

4. What data is required for a CPR?

The CP and team require multi-disciplinary geological, engineering, and financial data to conduct evaluations of reserves and resources. This data may include geological maps, seismic surveys, production and pressure data, petrophysical information, development plans, cost estimates, and details of marketing arrangements. An effective date is assigned to the CPR to ensure all data and assumptions are current and valid up to that point.

5. What should a CPR include?

Typically, a CPR should cover the following:

• Executive summary
• Table of contents
• Introduction
• Overview of the region, location, and assets
• Reserves & resources (separately disclosed)
• Other assets
• Conclusions
• Qualifications and basis of opinion
• Appendices – Glossary and definitions of any terms used

6. Which stock exchanges does Sproule ERCE prepare CPRs for?

Sproule ERCE has experience in preparing CPRs for the following European stock exchanges:

• UK – LSE & AIM
• Norway – Oslo
• Sweden – Nasdaq Stockholm

Sproule ERCE also prepares reserves and resources reports for other exchanges worldwide, but these are not strictly CPRs as other report naming conventions are used.

7. Why choose Sproule ERCE for CPRs?

Sproule ERCE has built a reputation for preparing reliable and compliant asset evaluations, valued by the investment community. Our CPRs are unbiased, transparent, and detailed, ensuring investor protection and regulatory compliance.

For a deeper understanding of “Competent Person’s Reports (CPRs)” and their significance in the energy sector, read the full article:

🔗 Competent Person’s Report (CPR)

1. Why can’t North American shale success be replicated globally?

North American shale success depends on a unique combination of geology, infrastructure, operational scale, and fiscal conditions. While technologies such as horizontal drilling and hydraulic fracturing are transferable, differences in subsurface properties, service costs, regulations, and market conditions mean that development strategies must be adapted to each basin.

2. What geological factors determine shale development success?

Shale performance is primarily controlled by Organic Quality, Rock Quality, and Mechanical Quality. These variables define hydrocarbon generation, storage capacity, and fracture behavior, all of which vary significantly across basins and directly impact development outcomes.

3. What lessons from North American shale development can be applied globally?

Transferable lessons include integrated subsurface analysis, the use of diagnostics to understand stimulation behavior, pressure interference modeling, and data‑driven decision‑making. These approaches improve understanding and reduce uncertainty, even in data‑limited environments.

4. What shale development practices do not translate well internationally?

Practices such as standardized completion designs, assumptions about low service costs, rapid large‑scale development, and uniform fiscal frameworks often fail outside North America. Local geological, operational, and regulatory conditions require tailored approaches.

5. How do operational and economic conditions impact shale development?

Beyond geology, factors such as infrastructure availability, service costs, water management, logistics, and workforce capability influence project viability. Economic modeling must also reflect local market conditions, fiscal regimes, and development timelines.

6. Why is an integrated approach important in global shale projects?

Successful shale development requires coordination between subsurface, engineering, economic, and regulatory considerations. An integrated approach helps operators understand interdependencies, reduce uncertainty, and design development strategies suited to local conditions.

7. How can operators reduce risk in global shale development?

Operators can reduce risk by prioritizing subsurface understanding, designing pilot programs to resolve key uncertainties, adapting operational strategies to local conditions, and addressing regulatory and economic constraints early in the development process.

Explore our full article “Global Shales, Local Rules: Why North America’s Shale Revolution Can’t Simply Be Copied” to understand how geology, operations, and policy shape shale development outcomes worldwide.

🔗 https://sproule-erce.com/blog/global-shale-development

1. Why is Libya’s oil and gas sector attracting renewed attention?

Libya holds some of the largest oil resources in Africa and ranks among the top oil resource holders globally. After years of limited activity due to political instability and underinvestment, recent licensing rounds and renewed international interest have brought Libya back into global energy discussions.

2. How large are Libya’s oil and gas resources?

Libya is estimated to hold approximately 48 billion barrels of oil, representing around 40% of Africa’s total oil resources and about 3% of global totals. The country also has a substantial natural gas base, which has historically been underdeveloped compared to oil.

3. Why have Libya’s oil and gas assets remained underdeveloped?

Much of Libya’s development gap has been driven by non‑geological factors, including prolonged political instability, production shutdowns around 2015, deferred investment, and limited application of modern technologies. Importantly, these factors affected development levels, not the underlying quality of the reservoirs.

4. What challenges do underdeveloped oil and gas assets in Libya present?

Key challenges include aging infrastructure, assets affected by prolonged shut‑ins or intermittent production, outdated development plans, and the need for updated subsurface evaluation. Addressing these challenges typically requires staged redevelopment supported by independent technical analysis.

5. Why is independent reserves evaluation important for Libya?

Independent reserves and resources evaluation helps stakeholders understand what has already been developed, what remains economically recoverable, and what work is required to move assets forward. In Libya, where historical production has been interrupted, independent assessment is critical for supporting investment, financing, and re‑entry decisions.

6. How does Libya fit into global supply diversification?

Libya’s geographic position allows oil and gas exports without reliance on highly congested or geopolitically sensitive transit routes such as the Strait of Hormuz. As energy security and diversification become more important globally, Libya’s role as a potential stabilizing contributor is gaining relevance.

7. How can experience support investment decisions in Libya?

Libya’s operating environment requires deep historical context, technical rigor, and an understanding of legacy assets. Experience gained through reserves evaluation, field development planning, and advisory work allows decision‑makers to navigate complexity, reduce uncertainty, and take a disciplined approach to redevelopment.

Explore our full article “Libya’s Second Chance in Global Energy: Restoring Assets, Rebuilding Confidence” to see how restoring assets, rebuilding confidence, and disciplined redevelopment are shaping Libya’s role in global energy:

🔗 Libya’s Second Chance in Global Energy: Restoring Assets, Rebuilding Confidence

1. Why is decarbonization important today?

Decarbonization is critical to meet global climate targets, comply with evolving regulations, and maintain competitiveness in a market increasingly shaped by sustainability. It helps companies reduce risks, optimize costs, and contribute to a low carbon future while supporting long term profitability.

2. What are MAC Curves?

Marginal Abatement Cost (MAC) Curves are analytical tools that rank emissions reduction measures by their cost per tonne of CO₂e avoided and the potential volume of emissions reduced. They provide a visual representation of decarbonization options helping companies understand which actions deliver the most impact for the least expense.

3. What are MAC Curves used for?

MAC Curves are used to identify, quantify, and prioritize decarbonization strategies. They guide decision-makers in selecting cost effective measures, optimizing investments, and planning emissions reduction pathways that align with both environmental and economic goals.

4. How can MAC Curves be used to develop a smarter decarbonization pathway?

MAC Curves enable companies to pursue emissions reductions strategically. By highlighting low cost or even cost saving measures first, they allow businesses to achieve significant reductions without compromising profitability. They also support scenario analysis, helping firms adapt to changing technology costs, carbon pricing, and regulations.

6. How can Sproule ERCE help you by using MAC Curves?

Sproule ERCE combines technical expertise, economic modeling, and regulatory insight to deliver practical MAC Curve analyses. This includes detailed site assessments, emissions verification, and financial modeling to rank abatement options. Their approach ensures clients receive actionable plans tailored to assets and aligned with evolving climate policies.

Read our full article “How Marginal Abatement Cost (MAC) Curves Drive Smarter Decarbonization Pathways” for detailed insights and practical applications:

🔗 How Marginal Abatement Cost (MAC) Curves Drive Smarter Decarbonization Pathways – Sproule ERCE

1. What is joint venture accounting in oil and gas?

Joint venture accounting is the process of managing and allocating shared costs, revenues, and financial responsibilities between partners based on the terms defined in joint operating or partnership agreements.

2. Why do discrepancies occur in joint venture billings?

Discrepancies often arise because agreements can be complex or interpreted differently. Variations in overhead calculations, cost allocation methodologies, or billing practices can result in charges that do not fully align with the agreed terms. Inconsistent application of equalization and adjustment processes can also contribute to these discrepancies.

3. What is the purpose of a joint venture accounting billing review?

A billing review compares actual charges against contractual agreements to identify mismatches, assess their materiality, and determine whether costs have been applied appropriately.

4. What types of costs are commonly misallocated?

Common areas of concern include:

• Overhead charges
• Cost allocation across assets or operations
• Usage versus ownership discrepancies
• Missing or misapplied equalization and adjustment processes

5. How do billing discrepancies impact profitability?

Even small discrepancies, when recurring over time, can accumulate into meaningful financial impacts. This can reduce profitability, distort cost visibility, affect financial reporting, and impact cash flow management.

6. How can companies identify inappropriate charges?

Identifying inappropriate charges requires:

• Reviewing detailed billings
• Comparing them with agreement terms
• Evaluating whether costs are reasonable and correctly applied

A structured review helps validate charges against agreements and prioritize issues based on their material financial impact.

7. How can a joint venture accounting review support cost recovery?

A well-executed review can help companies quantify discrepancies, challenge unsupported charges, and recover costs that were incorrectly billed. It also strengthens financial oversight, supports dispute resolution, and helps protect long-term asset value.

Explore our full article “Oil & Gas Production & Joint Venture Accounting: Why Accuracy Protects Value” to understand how joint venture accounting billing reviews help identify discrepancies, recover costs, and protect profitability across your assets:

🔗 https://sproule-erce.com/blog/joint-venture-accounting/

1. What is NI 51-101 and why does it matter?

NI 51-101 (National Instrument 51-101) is a Canadian securities regulation that governs the disclosure of oil and gas activities for public companies. It ensures that reserves and resources reporting is transparent, consistent, and reliable, which is critical for investor confidence and regulatory compliance.
By standardizing disclosure, NI 51-101 helps stakeholders compare companies on a level playing field and make informed investment decisions.

2. What is the Canadian Oil and Gas Evaluation Handbook (COGEH)?

COGEH is the technical companion to NI 51-101. It provides methodologies and best practices for evaluating reserves and resources, ensuring that assessments follow sound engineering and geoscience principles.
Together, NI 51-101 and COGEH create a framework that combines regulatory rigor with technical accuracy, making them essential for credible reserves reporting.

3. What recent changes have been introduced under NI 51-101 and COGEH?

The latest updates to COGEH include:

• Carbon Tax Credits: Clear guidance on when and how carbon tax credits should be included in economic evaluations of reserves.
• Evaluator Definitions: Stricter certification and experience requirements for Qualified Reserves Evaluators (QRE) and Qualified Reserves Auditors (QRA), ensuring higher standards of expertise.
• Minor Wording and Reference Updates: Corrections to document references, version dates, and terminology for consistency across disclosures.

4. Why are these changes important for operators?

These updates increase the complexity of compliance. Operators must:

• Verify that evaluators meet new qualification standards.
• Understand how carbon tax credits impact economic evaluations.
• Maintain accurate references and documentation to avoid regulatory discrepancies.
  Failure to comply can lead to regulatory risk, investor distrust, and potential delays in reporting.

5. How do carbon tax credits affect reserves evaluations?

Carbon tax credits can significantly influence the economic viability of reserves projects. Incorporating them correctly in evaluations ensures that reported reserves reflect true project economics. Misinterpretation can lead to inaccurate disclosures and compliance issues.

6. What are the best practices for staying compliant?

• Engage Independent Evaluators Early: Ensure they meet updated NI 51-101 qualifications.
• Standardize Processes: Implement robust documentation and audit trails.
• Integrate Technical Guidance: Combine engineering, geoscience, and economic expertise for comprehensive evaluations.
• Stay Informed: Monitor NI 51-101 and COGEH updates regularly to anticipate compliance implications.

7. How does Sproule ERCE support compliance?

Sproule ERCE stands out as a trusted partner in Canadian reserves certification, combining deep technical expertise with comprehensive regulatory knowledge:

• Independent reserves and resources evaluations aligned with NI 51-101 and COGEH.
• Expert guidance on integrating regulatory changes into workflows.
• Proven methodologies that emphasize transparency, technical rigor, and investor confidence. Our team has successfully delivered evaluations for major Canadian oil and gas assets, ensuring clients meet compliance and reporting standards.

Read our full article “Reserves Evaluations in Canada – What’s Changing Under COGEH” for detailed insights and best practices:

🔗 Reserves Evaluations in Canada – What’s Changing Under COGEH – Sproule ERCE

1. What is a geothermal resource evaluation methodology?

A geothermal resource evaluation methodology is a structured approach to characterize subsurface heat resources and translate geological data into technically and commercially meaningful outcomes. It defines how uncertainty is assessed, how resources are classified, and how project maturity and economic viability are evaluated to support investment and development decisions.

2. Why is standardization important in geothermal resource evaluation?

Standardization ensures that geothermal projects are evaluated using consistent assumptions, terminology, and risk treatment. This allows developers, investors, lenders, and regulators to compare projects on a like‑for‑like basis and reduces ambiguity that can undermine confidence during financing and due diligence.

3. How does a standardized methodology improve project bankability?

A standardized methodology improves bankability by clearly documenting uncertainty, separating technical and commercial risks, and producing evaluations that are transparent and auditable. Lenders and investors are better able to test downside scenarios, assess deliverability, and understand the robustness of cost and performance assumptions.

4. What is the difference between geothermal resources and reserves?

Geothermal resources represent the estimated subsurface heat available, while reserves require demonstrated deliverability, a defined development plan, and clear commercial viability. A project progresses from resources to reserves as geological certainty increases and technical, economic, and regulatory conditions are met.

5. How are uncertainty and risk addressed in geothermal evaluations?

Uncertainty is addressed through probabilistic analysis, stage‑gate development frameworks, and standardized sensitivities. Rather than bundling risks into a single discount factor, a robust evaluation identifies where uncertainty originates and how it changes as a project advances.

6. How does geothermal resource evaluation impact the levelized cost of energy or heat?

The levelized cost of energy or heat depends heavily on assumptions related to well deliverability, decline rates, availability, and system efficiency. A standardized evaluation ensures that these inputs are defensible, traceable, and aligned with data quality, reducing the risk of overly optimistic cost estimates.

7. How does Sproule ERCE apply standardized geothermal evaluation methodologies?

Sproule ERCE applies standardized geothermal evaluation methodologies by integrating subsurface data, concept‑specific recoverability factors, commercial modeling, and rigorous audit processes. This approach supports credible decision‑making across exploration, appraisal, development, and financing stages, helping projects withstand technical due diligence.

Explore our full article “Standardized Resource Evaluation Methodology for the Geothermal Industry” to understand how standardized, audit‑ready evaluations help developers, investors, and lenders make confident geothermal decisions.

🔗 https://sproule-erce.com/blog/geothermal-resource-evaluation-methodology/

1. What is geothermal technical due diligence?

Geothermal technical due diligence is an independent evaluation of a geothermal project’s technical, operational, and economic foundations. It helps investors, lenders, and project developers assess whether a geothermal resource can be produced reliably, whether the development plan is technically feasible, and whether the project can generate acceptable financial returns.

2. Why is technical due diligence important for geothermal projects?

Technical due diligence reduces uncertainty by validating resource potential, engineering design, and economic assumptions before major investment decisions are made. By identifying technical risks and data gaps early, stakeholders can improve project planning, allocate capital more effectively, and increase confidence in project viability.

3. What is included in a geothermal technical due diligence assessment?

A geothermal technical due diligence assessment typically reviews subsurface characterization, reservoir performance, well design, facilities engineering, system integration, project execution plans, operating costs, capital expenditures, and financial performance forecasts. The goal is to evaluate the project as an integrated system rather than reviewing individual components in isolation.

4. How does technical due diligence help investors evaluate geothermal project risk?

Technical due diligence provides independent validation of key project assumptions and identifies uncertainties related to reservoir productivity, thermal performance, drilling complexity, costs, and long-term operations. This structured approach helps investors understand both the risks and potential returns associated with a geothermal development opportunity.

5. When should geothermal technical due diligence be performed?

Technical due diligence is commonly performed before financing, project acquisition, mergers and acquisitions (M&A), or major development milestones. It is often conducted as part of a lender review process or when investors require an independent assessment of technical and commercial assumptions before committing capital.

6. What is the role of a Lender’s Technical Advisor (LTA) in geothermal developments?

A Lender’s Technical Advisor (LTA) provides an independent review of a geothermal project’s technical assumptions, risks, execution plans, and economic forecasts on behalf of lenders. The LTA helps financial institutions determine whether a project meets financing requirements and whether technical risks are being appropriately managed.

7. How does technical due diligence improve geothermal project bankability?

Technical due diligence improves project bankability by providing transparent, independent validation of resource potential, engineering design, operational performance, and economic forecasts. By quantifying risks and confirming realistic performance expectations, due diligence helps projects satisfy investor and lender requirements, increasing the likelihood of securing financing and advancing through development.

Explore our full article, “Technical Due Diligence: How to Confirm Investor Confidence in Geothermal Projects”, to learn how independent technical evaluations help quantify risk, validate project assumptions, and support informed investment decisions across geothermal developments.

🔗 https://sproule-erce.com/blog/geothermal-technical-due-diligence

1. What is underground gas storage modelling?

Underground gas storage modelling is the integrated evaluation of how gas storage reservoirs, wells, and surface facilities perform under cyclic injection and withdrawal. It is used to assess storage capacity, deliverability, pressure behavior, and long‑term performance under realistic operating conditions.

2. Why is underground gas storage modelling important today?

As gas markets become more exposed to geopolitical risk, LNG dependence, and infrastructure constraints, storage is increasingly relied upon to provide energy security and operational flexibility. Modelling helps decision makers understand whether stored gas can be delivered reliably during peak demand or supply disruptions.

3. How does gas storage modelling differ from production modelling?

Unlike production modelling, which focuses on steady long‑term depletion, gas storage modelling must account for rapid pressure reversals, high‑frequency cycling, and changing flow regimes. Reservoirs often behave differently during storage operations than they did during primary production, making storage‑specific modelling essential.

4. What types of underground gas storage can be modelled?

Gas storage modelling can be applied to all major storage types, including:

• Depleted oil and gas reservoirs
• Aquifer storage formations
• Salt caverns

Each storage type has distinct geological, operational, and risk characteristics that must be evaluated differently.

5. What risks does underground gas storage modelling help address?

Modelling helps quantify key uncertainties such as:

• Injectivity and productivity degradation over time
• Cushion gas requirements and usable working gas
• Pressure limits and containment risks
• Deliverability constraints during peak demand
• Well and surface facility performance limitations

Addressing these risks early helps avoid underperforming assets and operational failures.

6. Who uses underground gas storage modelling?

Underground gas storage modelling supports a wide range of stakeholders, including:

• Gas storage operators
• Utilities and system planners
• Midstream companies
• Regulators and public‑sector agencies responsible for energy security

7. How does integrated modelling improve storage decision making?

Integrated modelling links subsurface reservoir behavior with wells, compression, and pipeline constraints. This allows storage concepts to be evaluated based on real deliverability and system performance, rather than nominal storage volumes alone.

Explore our article “Underground Gas Storage Modelling: A Strategic Approach to Market Uncertainty” to learn how integrated technical studies support resilient, high‑performing gas systems.

🔗 Underground Gas Storage Modelling: A Strategic Approach to Market Uncertainty

1. What is carbon storage risk assurance?

Carbon storage risk assurance is the process of evaluating and documenting the risks associated with storing CO₂ underground in a CCS project. For insurers, it focuses on identifying, quantifying, and mitigating the risk of CO₂ leakage that could lead to financial exposure, including 45Q tax credit recapture.

2. Why isn’t regulatory approval enough to secure CCS insurance?

Regulatory approvals, such as EPA Class VI permits, establish minimum environmental and safety requirements. Insurers, however, evaluate CCS projects based on financial risk. They require additional analysis to understand leakage likelihood, severity, and duration, factors that directly influence potential tax credit recapture and insurance exposure.

3. Why is 45Q tax credit recapture a major concern for insurers?

Under Section 45Q, tax credits may be recaptured if stored CO₂ leaks to the atmosphere during the monitoring period. This creates direct financial exposure for insurers, making leakage risk assessment a critical input to underwriting decisions and policy limits.

4. Why have legacy wells become a key insurance focus?

Wells that penetrate the injection or confining interval, particularly older legacy wells, are viewed as credible leakage pathways. Many were drilled or abandoned under outdated standards and may lack sufficient documentation. Insurers require detailed evaluation of these wells, including their condition, history, and monitoring plans.

5. Why do insurers require quantitative leakage estimates?

Insurers need to understand not just whether leakage could occur, but how much CO₂ could leak and how quickly. Quantitative estimates, such as potential leakage rates and duration, are essential for pricing risk, defining coverage limits, and evaluating whether financial exposure is bounded.

6. How do mitigation plans and response time affect insurability?

Insurers assess how a project would respond if CO₂ leakage were detected, including available mitigation options and realistic response times. Longer detection or remediation timelines increase financial exposure, making clearly defined intervention plans critical for insurance coverage.

7. Why does early insurance planning improve CCS project outcomes?

Projects that integrate insurance considerations early, during site selection, well evaluation, and MRV design, are better positioned to meet insurer requirements without unexpected delays. Early planning reduces the need for late‑stage technical rework and improves the likelihood of securing 45Q recapture insurance efficiently.

Explore the full article, “Why Insurance Providers Demand Carbon Storage Risk Assurance”, for a deeper look at how insurers evaluate CCS risk and what it means for 45Q recapture insurance and project viability.

🔗 Why Insurance Providers Demand Carbon Storage Risk Assurance