Wert-Berater, Inc. is an independent upstream oil & gas feasibility study consultant preparing lender-, investor-, and agency-facing studies for drilling programs, workover and recompletion projects, and producing-property acquisitions. The analysis starts where a reserve-based credit actually lives: the production profile implied by type curves and decline, the realized price after basis differentials, lease operating expense per barrel of oil equivalent, and the working-interest and royalty structure that decides what cash actually reaches the borrower. Capital, abandonment obligations, and downside price cases are tested against debt-service coverage rather than assumed away.
Fiduciary duty runs to the lender and the agency, never the borrower. Fixed fee quoted within one business day; standard delivery in ten to fifteen business days from a complete data room. 4,000+ engagements since 1998 covering $41.2 billion in evaluated project value. So far in 2026: 41 engagements and $1.54 billion evaluated — 17 SBA, 11 USDA.
Upstream feasibility is reserve economics under commodity-price discipline. The study evaluates the geological and engineering basis supplied by the project team — independently tested, not accepted — alongside drilling and completion cost benchmarks, type-curve production assumptions, operating cost per BOE, and the price-deck sensitivity that determines whether the program survives the bottom of the cycle. Working-interest structure, lease obligations, and plugging liability receive explicit treatment, because upstream credit fails on obligations as often as on price.
Methodology draws on state oil and gas commission production records, published type curves for the basin, drilling-cost surveys, and futures-strip and bank price decks for the sensitivity cases. The financial model carries production decline, differentials, lease operating expense, and coverage under conservative price assumptions across the firm's standard stress discipline.
Every Wert-Berater financial model is fully linked with no hardcoded values, so any reviewer can stress any input. Deliverables comprise a complete narrative report and the linked Excel model, with ten-year pro forma, sensitivity analysis at ±5, 10, and 15 percent, interest-rate stress from +0.5 to +3.0 percent, and ratio analysis benchmarked against RMA and IBISWorld data.
SBA engagements are prepared to SOP 50 10 8, including its debt-service-coverage minimums of 1.15x operating and 1.00x global. USDA engagements follow RD Staff Instruction 5001 across the Business & Industry, Community Facilities, REAP, and Value-Added Producer Grant programs. Conventional engagements are built to the lender's stated coverage standard, typically 1.20x. Oil, gas, and heavy-industrial projects reach us through conventional and institutional lending most commonly, with USDA B&I applicable to qualifying rural energy and processing assets and SBA programs serving owner-operator support businesses; each study is prepared to the corresponding compliance standard, with environmental and regulatory conditions precedent stated plainly.
Wert-Berater has not published a completed upstream drilling or producing-property engagement as a public case study, and none is claimed here. The firm's nearest published energy work is an oilfield services feasibility study in Troy, Michigan, which tested service demand derived from drilling and completion activity rather than reserves themselves. What carries across to upstream credits is the analytical discipline applied to every one of the firm's 4,000+ engagements since 1998: fully linked models with no hardcoded values, assumptions sourced and footnoted rather than asserted, and coverage tested under downside cases before a determination is issued. Independence is non-negotiable — determinations follow the evidence and are not revised under pressure, and studies are built to pass lender, agency, and third-party review without exception items.
An upstream oil & gas feasibility study consultant answers one question for the lender: will this reserve base, produced on this schedule at defensible prices and costs, service the proposed debt through a price cycle? Answering it means rebuilding the sponsor's economics from the underlying technical and contractual documents rather than accepting a summary spreadsheet. The consultant tests the production forecast against the type curves and historical performance that support it, converts gross volumes into net revenue through the working-interest and royalty stack, applies realized pricing after basis differentials, and loads the full operating and abandonment cost structure before coverage is measured.
The engagement is an economic and financial opinion, not a technical one. Wert-Berater does not certify reserves, issue reserve-engineering opinions, or perform petroleum, drilling, or facilities engineering. Where a qualified reserve report, geological study, or engineering estimate exists, it is treated as an input whose assumptions are tested for reasonableness and internal consistency — and where a needed technical input is missing, the study says so rather than substituting an assumption for it.
An upstream oil & gas feasibility study prepared by Wert-Berater is not a restatement of the sponsor's projections. It is an independent reconstruction of the economics from primary sources, tested against the price and cost environment a lender must survive. The scope is set by what actually moves coverage in a reserve-based credit: production volume, realized price, lease operating expense, and the obligation structure that persists when commodity prices fall.
The production forecast is the single largest driver of an upstream credit, so it receives the most scrutiny. Where a qualified reserve report classifies volumes as proved developed producing or proved undeveloped, those categories are carried into the model only as the technical report supports them; the study does not promote undeveloped volumes into the coverage calculation on the strength of a sponsor projection. Type curves are compared against actual production history from analogous wells in the same formation and area where that history is available in state commission records.
Decline assumptions are tested explicitly, because initial-rate optimism and shallow decline are the two most common reasons an upstream pro forma fails in year two. The review covers the hyperbolic or exponential decline parameters applied, well spacing and the interference it implies, the drilling and completion schedule and whether it is realistically financed and staffed, and the resulting aggregate production profile across the loan term. Where the reserve life is shorter than the amortization period, the study says so plainly — that mismatch is a structural finding, not a sensitivity.
Realized price, not benchmark price, determines revenue. The study establishes the benchmark deck being used for oil and natural gas, then works down to the wellhead through basis and quality differentials for the specific producing area, gathering and transportation deductions, and any processing or shrinkage that applies to gas and natural gas liquids. Where the sponsor has hedges in place, their volumes, tenor, and structure are modeled as they actually settle rather than as a flat price floor, and the study notes what happens to coverage when those hedges roll off inside the loan term.
Because upstream cash flow is cyclical by nature, the downside case is the case that matters. Coverage is re-tested at materially lower sustained prices, not merely at a small percentage haircut, and the price-cycle exposure of the credit is described in terms of how far prices can fall before coverage breaches the lender's minimum. Price sources and the date of the deck are disclosed so a reviewer can re-run the analysis against their own house view.
Gross production is not the borrower's production. The study reconstructs the ownership stack: the working interest held in each well or unit, the landowner and overriding royalty burdens deducted from it, and the resulting net revenue interest that actually converts volumes into revenue for the borrowing entity. Where the borrower holds interests across multiple wells at differing percentages, those are modeled individually rather than blended, because a weighted average conceals concentration in the best-performing wells.
Lease obligations are reviewed for the conditions that can interrupt cash flow: continuous-drilling and held-by-production requirements, primary-term expirations falling inside the loan term, minimum royalty and delay-rental obligations, and pooling or unitization terms. The study also distinguishes operator from non-operator exposure. A non-operating working interest carries the cost obligations of the operator's decisions without control over timing or capital, and where the borrower is a non-operator that dependency is stated as a credit risk rather than left implicit.
Lease operating expense is tested per barrel of oil equivalent against the borrower's own historical operating statements where the properties are producing, and against comparable operations in the same basin where they are not. Fixed and variable components are separated, because a forecast that scales all operating cost with volume understates cost per unit as production declines — a systematic error that flatters coverage in exactly the later years when it is weakest.
Capital is modeled on the same evidentiary basis: drilling and completion cost per well against recent authority-for-expenditure documentation, workover and recompletion frequency and cost, produced-water handling and disposal, and gathering or trucking costs where infrastructure is not in place. Abandonment is not deferred out of the analysis. Plugging and site-restoration obligations, and any bonding or financial assurance required by the state regulator, are quantified and shown against the reserve life so the lender can see whether the obligation matures inside or outside the credit.
Upstream feasibility does not use a consumer-demand model. The relevant market question is not whether buyers exist for crude oil or natural gas — it is whether the specific project can produce hydrocarbons at a cost structure that survives the price cycle, and whether the takeaway and marketing arrangements are sufficient to realize a price close to the benchmark. Demand analysis for this asset class is therefore a combination of price-environment analysis and midstream-capacity verification.
Price environment work draws on NYMEX futures strips, published bank price decks circulated to reserve-based lenders, and historical spot-price series for the relevant benchmark crude or gas index. Basin differentials are sourced from pipeline tariff filings, midstream operator rate schedules, and published basis differential surveys. Where the project depends on a specific gathering or processing agreement, the terms of that agreement are reviewed for volume commitments, fee structures, and deficiency provisions that could impair net realized price.
Competitive supply context is drawn from state oil and gas commission well records, which show permitted, drilling, and producing well counts by formation and county. Operator production filings establish the performance envelope for analogous wells. Midstream capacity constraints, where material, are identified through pipeline interconnection filings and published capacity postings. No proprietary or unverifiable data source is used as a primary input.
Reserve-based lending fails on a small number of inputs. Identifying which assumptions are load-bearing — and stress-testing each one independently — is the core analytical function of an independent feasibility study. For upstream oil and gas projects, four variables account for the majority of coverage-ratio movement, and each receives explicit sensitivity treatment in the Wert-Berater model.
Each stress is run independently and in combination, so the lender can see which scenario breaks coverage first.
Every input above resolves into a fully linked financial model with no hardcoded values, so any reviewer can change an assumption and watch coverage move. The model produces a ten-year pro forma, annual and period-by-period debt-service coverage, and a clear statement of the coverage minimum applicable to the financing program in question. Coverage is reported on the defensible production base first; upside from undeveloped locations or accelerated drilling is shown separately and never carries the base-case determination.
Sensitivity is run across the six variables that actually decide an upstream credit: production decline rate, realized commodity price, lease operating expense, drilling and completion capital, interest rate, and reserve life. Each is stressed independently and then in combination, with the breakeven identified for each — the point at which coverage falls to the lender's minimum. The feasibility study independently tests the economic assumptions using qualified geological and petroleum-engineering reports as inputs; it does not replace a reserve-engineering opinion.
Upstream oil and gas projects present a specific set of underwriting concerns that differ from real estate or operating-business credits, and the feasibility study must address each one directly rather than by analogy to a generic business plan.
For conventional and institutional reserve-based lenders, the primary questions are whether the production forecast is supportable by analogous well performance, whether the price deck is conservative relative to the futures strip, and whether the coverage ratio holds through the trough of the price cycle — not just at strip pricing. Lenders also require explicit treatment of the working-interest ownership chain, any preferential purchase rights, and the seniority of the P&A obligation relative to debt service.
SBA engagements prepared to SOP 50 10 8 require that operating coverage meet the 1.15x minimum and global coverage meet 1.00x; for upstream projects, the operating coverage calculation must reflect the production decline schedule rather than a static revenue assumption, because a flat-revenue model will overstate coverage in later years of the loan term.
USDA Business & Industry engagements under RD Staff Instruction 5001 apply to qualifying rural energy and processing assets; the study must address the rural-area eligibility of the project location and the environmental conditions precedent — including state regulatory compliance and bonding status — that are conditions of the credit. In all cases, the fiduciary duty of the study runs to the lender and the reviewing agency, and the finding is not adjusted to fit a borrower's preferred outcome.
Every Wert-Berater engagement begins with a fixed, quoted fee delivered within one business day of the initial inquiry. The fee does not change based on the outcome of the study, and no portion of the fee is contingent on a favorable finding. That structure is not a marketing position; it is the condition under which an independent determination is possible. A lender or agency reviewing the study can rely on it precisely because the analyst had no financial interest in the conclusion.
The standard delivery window is 10 to 15 business days from the date the data room is complete. For upstream projects, a complete data room includes the lease and operating agreements, any existing reserve reports or engineering studies, the proposed well program and AFE, the midstream or marketing agreement, the entity and working-interest schedule, and three years of historical financial statements for any operating entity. Incomplete data rooms are the most common cause of delay; the engagement letter specifies exactly what is required.
Rush delivery is available and is quoted at the time of engagement. Once the study is complete, the bound narrative report and the fully linked Excel model are published to a secure client portal. The model remains live: if a lender requests a revised price-deck scenario or a different production assumption, the input is changed and every output — coverage ratios, sensitivity tables, pro forma — recalculates instantly. No values are hardcoded, so any reviewer can verify every calculation without contacting the firm.
Upstream projects rarely sit alone in a financing structure. These adjacent engagements address the parts of the value chain that most often appear alongside a reserve-based credit.
The fee is fixed and quoted within one business day of the initial inquiry. It does not vary based on the study's finding, and no portion is contingent on loan approval or a favorable conclusion. Because every engagement is scoped individually, the quote reflects the complexity of the well program, the number of entities in the working-interest structure, and whether the engagement must meet SBA, USDA, or conventional compliance standards.
Standard delivery is 10 to 15 business days from the date a complete data room is received. For upstream projects, that means lease agreements, the well program and AFE, any existing reserve engineering, the midstream or marketing contract, the working-interest schedule, and historical financials are all in hand before the clock starts. Rush delivery is available and is quoted at the time of engagement.
The consultant independently rebuilds the project economics: the production profile implied by type curves and decline, net revenue after working-interest and royalty burdens, realized pricing after basis differentials, lease operating expense, drilling and abandonment capital, and the debt-service coverage that results. The work is economic and financial. Reserve certification, geology, and petroleum engineering are separate disciplines whose reports are used as inputs.
Type curves are compared against actual production history from analogous wells in the same formation and area, using state oil and gas commission records where that data is public. The review looks at initial rate, the decline parameters applied, and well spacing. Where the proposed curve is more optimistic than nearby producing wells support, the model is run on the observed performance and the difference is reported to the lender rather than reconciled silently.
The study establishes the benchmark deck in use, deducts basis and quality differentials for the specific producing area, and models hedges as they actually settle. Coverage is then re-tested at materially lower sustained prices to identify the point at which it falls to the lender's minimum. The price source and deck date are disclosed so a credit officer can substitute their own house view.
No. Wert-Berater does not certify reserves and does not issue reserve-engineering or geological opinions. Where a qualified reserve report exists it is treated as a technical input, and its assumptions are tested for reasonableness and internal consistency against production history. If no qualified reserve report has been prepared, the study states that the technical basis is absent rather than substituting an assumption for it.
Three factors make upstream credits harder than most: revenue declines by design as wells deplete, so a static coverage calculation overstates future debt-service capacity; commodity price is outside the borrower's control and can move faster than the loan can be restructured; and the plugging-and-abandonment obligation is a senior liability that persists even if the project is abandoned. An independent study must address all three explicitly, not treat them as footnotes.
No study can guarantee loan approval, and any firm that implies otherwise is misrepresenting what a feasibility study does. The study provides an independent, evidence-based determination of economic feasibility under stated assumptions. The credit decision belongs to the lender or agency. Wert-Berater's fiduciary duty runs to the lender and the reviewing agency, not to the borrower.
A complete data room for an upstream engagement typically includes: the oil and gas lease and any surface-use agreements; the proposed well program, AFE, and completion design; any existing reserve report or engineering study; the gathering, processing, or marketing agreement; the entity structure and working-interest ownership schedule; and three years of historical financial statements for any operating entity. The engagement letter specifies the full list so nothing is missed.
A single study can be structured to meet multiple compliance standards when the engagement is scoped that way from the start. SBA engagements are prepared to SOP 50 10 8, with coverage minimums of 1.15x operating and 1.00x global. Conventional engagements are built to the lender's stated standard, typically 1.20x. When both audiences will review the same document, the study is prepared to the more demanding standard and the compliance mapping for each program is stated explicitly.
Working interest is the share of costs the borrower bears; net revenue interest is the share of revenue the borrower keeps after landowner and overriding royalties. Because the two differ, gross production overstates borrower cash flow. Interests are modeled well by well rather than blended into a single average, since a weighted average hides concentration in the best-performing wells.
Plugging, site restoration, and any state-required bonding or financial assurance are quantified and shown against the economic reserve life, so the lender can see whether the obligation matures inside or outside the credit. It is not deferred beyond the model horizon. Where the obligation lands inside the loan term, it is funded in the cash flow and its effect on coverage is reported.
That mismatch is reported as a structural finding, not as a sensitivity. When economically producible reserves are exhausted before the debt amortizes, coverage in the final years depends on volumes the technical report does not support. The study states the year in which the shortfall begins and quantifies the gap, which allows the lender to shorten the term, resize the facility, or require additional collateral.
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Wert-Berater, Inc. is an independent provider of feasibility studies and other related services. The firm does not provide financing or equity investment advice, and does not arrange, broker, or place debt or equity capital of any kind.
All appraisal assignments are performed by Bruce E. Jones, MAI, ASA-GC, BCA, CMEA, a member of the Appraisal Institute since 2006, a staff member of Wert-Berater, Inc. and owner of Special Purpose Realty Valuation.