Due Diligence and Modeling Oil and Gas Acquisitions
The foundation for all financing is being able to provide answers to three questions: (1) how much is needed; (2) what is the collateral; and (3) when is the debt repaid or investor exit.
Preamble: When considering various oil and gas assets or Leases for possible acquisition, gathering due diligence documents and data, and then being able to quickly organize and objectively evaluate that information is critical to decision-making. Compounding this is that unlike in most transactions where deals are qualified and one-off financing structures are created, planned, adopted, and then pursued, oil and gas deals are cash-only transactions. Acquired assets can be leveraged afterwards. Even if a transaction is a negotiated direct sale, from the time an MOU or LOI is signed between the buyer and seller, deals rarely have more than 45 days to close, and that is usually not enough time for identified investors and lenders to complete their diligence and paperwork for one-off funding structures and finish. Further, the foundation for all financing is being able to provide answers to three questions: (1) how much is needed; (2) what is the collateral; and (3) when is the debt repaid or investor exit. Therefore, developing a method or model that can quickly organize and objectively present answers to those questions is paramount and must include: all investment capital needed to close the transaction AND show needed capital throughout a proffered period of time to achieve the target ROI; how the capital investment is secured and leveraged; and finally, a clear and detailed repayment and exit schedule for lenders and investors. Moreover, these answers must be presented in a standard and acceptable format with the ability to objectively conduct what-if analysis to help identify and consider any near-term funding problems and options to remedy, the myriads of operating risks and market changes and how they can be overcome, and the ability to quickly and thoroughly organize and satisfy all frontend diligence mandates. No small task.
Over many years and having been party to dozens of oil and gas transactions, we have developed a Cash Flow Model (CFM) that achieves the aforementioned objectives. At a high level, oil and gas transactions are mostly the same allowing for the CFM to have been refined and perfected over time. Output presentations include the Assumptions Page (link) wherein all data input is centralized and easy to manipulate for what-if analysis; the Balance Sheet and Statement of Cash Flows (link) which many deem the Bible of information for investment consideration as it’s really about following the Ending Bank Balance for each period; the Income Statement (link) which includes per period EBITDA, and quick reference to per period lifting cost (which is most important to operators), and the Funding Schedule (link) which clearly shows when capital is needed, how capital is secured, and when its either repaid or the investor has realization and exit.
Cash Flow Model Context: Following are CFM explanations and constants to frame the context of the CFM presentation. A benefit is that the CFM is fully dynamic allowing for unlimited manipulation of input data to quickly analyze any change in macroeconomic market conditions, vendor costs, or in the internal corporate cost structure of the buyer, that could affect operating performance. Moreover, the integrity and objectivity of the CFM is maintained regardless of how many “what-if” scenarios are explored enabling the buyer, and any financier and bank, to immediately review and analyze output results with confidence.
All schedules and financial statements are pursuant to GAAP principles and guidelines.
The CFM output schedules are completely objective. The only page where inputs can be manipulated is on the Assumptions Page and then, only the variables in blue type.
All input values are derived from individual well data and information recorded and cataloged under the assigned API number for each well archived within the Energy Information Administration (“EIA”) division of the U.S. Department of Energy; from the relevant State Agency governing and enforcing Lease operations; documents recorded with the County where the subject Mineral Rights exist; from Petroleum Engineering Reports; from documents and information received from the Seller; and from whatever is sourced independently.
The CFM aggregates specific expense totals to each well equally for simplicity. Seldomly do sellers provide accurate well-by-well LOE expense data. The totals are accurate given what is learned from diligence investigations and absent sellers providing audited LOE statements, the delta between the aggregated totals and historical well-by-well operating expenses is minimal and mostly acceptable.
The CFM assumes the Purchase price will be 100% financed, with any need for equity shown last (see funding schedule). That way, the buyer or reader of the CFM can discern real value before pledging equity and assuming that risk, and can then decide if the subject acquisition is worth pursuing.
Oil and Gas Reserve valuation metrics, including decline data, are provided by Petroleum Engineering evaluations and appraisals – usually requested and commissioned by the buyer. The CFM incorporates well decline (rate value as entered into the Assumptions Page), into period-by-period production forecasts.
Production Decline analysis and production forecast estimates for remaining reserve years are based only on historical PDP data from producing zone(s). No production consideration from other known zones are included in the calculous to determine remaining Reserve years and asset value, which could be deemed as untapped additional value.
The Oil price in Period #1 is linked to the current WTI price per barrel produced at the time the CFM was prepared for evaluation. The CFM then adjusts the oil price moving forward, per period, pursuant to the WTI oil price variance input value added on the Assumptions Page.
The CFM assumes the Lease or Asset being evaluated operates “as is” throughout the model with the ability to conduct “what if” analysis. “What if” inputs could include: (1) preventative maintenance schedules beginning and ending in given months or extending throughout the model; (2) augmenting production via infill drilling of new wells and then evaluating any flush period – in terms of time, yield, and cost. Any expected flush production from infill wells drilled and completed, and the associated lifting costs, are aggregated to the performance of nearby wells after the flush period (typically 2-3 months in waning duration) and the costs of adding wells are posted in the period when incurred; and (3) other equipment purchases, add-on asset acquisitions, or unplanned non-operating expenses, etc.
The CFM assumes that future capital costs expenditures, for whatever purpose, are sourced and paid from available cash. Should there be a cash shortfall in any given period, the CFM will first seek to draw from a Revolving Credit Line secured by an allowable percentage of A/R (usually the cheapest form of financing short-term capital needs); then the CFM will look to source the outstanding cash shortfall via Long-Term Debt secured by the allowable limit to borrow against equity in the subject assets; and finally, capital is sourced by incentivizing new investment capital by offering Mezzanine Equity or Preferred Stock.
The CFM shows in which specific month or period capital infusions are needed, received, and then delineates when monthly debt service and principal payments are made until debts are fully repaid. The CFM also shows when dividend payments are made, if applicable, and when any return-of-capital is paid to retire the Preferred Stock or Mezzanine Equity.
Loan or capital values as shown, interest rates, financing fees, and repayment schedules are for information purposes only, and may not reflect actual terms from lenders and financiers. Moreover, the presentation exhibits assume acquisition financing, soft costs, and initial operating capital was closed first and secured via Surety Bond while the funds are in escrow. Transactions are not official until the transaction and Division Orders are prepared, verified, and recorded (usually within 45 to 90 days after the transaction closes), and while ongoing revenue is then immediately owned by the buyer at transaction closing or in month #1, revenue receipts are held in suspense and not released to the new owner until the Division Orders have been recorded.
While the Accounts Receivable (A/R) and Depreciation Schedules are part of the CFM, they are not presented as both are self-explanatory given the line-item information for the same shown on the Balance Sheet and Income Statement.
The links to the various CFM schedules are a snapshot of the first periods. The CFM extends out 120 months or 10 years – plenty of time to ascertain value and how debt or investment capital is repaid or retired.
Furthermore, the CFM becomes the budget and benchmark against where actual performance will be measured. While no model is predictive of everything, it does provide to be an invaluable tool to objectively study all what is known about the purchase, and anticipated near-and-long term cash flow performance, of an oil and gas Lease. Moreover, the CFM can also determine if an asset is self-reliant and can exist and function on its own, and if any redundancy to a Company’s existing G&A or equipment inventory could be employed or shared to enhance overall company profitability.
