Merger and acquisition history contains too many examples of mergers that failed to produce shareholder value, with research suggesting that more than half of all mergers do not prove to increase shareholder value after 12 months. Failures result, perhaps, from elusive synergies, indecisive transition plans, integration confusion or accounting surprises. This article highlights some of the key accounting and tax issues to consider when carrying out due diligence for energy acquisitions. While the discussion is largely focused on US concepts, the global implications - such as the impact of international accounting standards and local country tax laws - must be considered where relevant.
Several themes dominate corporate financial reporting in the energy sector, with three areas in particular requiring investigation during an acquisition: derivatives, energy trading and special purpose entities.
Derivatives
In 2001, the US Statement of Financial Accounting Standards No 133 (SFAS 133), Accounting for Derivatives and Hedging Activities, as amended, became effective. This is easily the most complex standard within the current US generally accepted accounting principles (GAAP) framework. The statement has been amended and interpreted more than 150 times. In the energy industry, oil, natural gas and electricity are considered derivatives because active markets exist to trade these commodities. Consequently, any freestanding contract to purchase or sell these commodities is considered a derivative unless the contract qualifies for a scope exception (that is, as a normal purchase and sale). Derivatives are recorded at fair value, but changes in fair value may be deferred for income statement purposes if the derivative is documented as a cash-flow hedge. The income statement impact of properly documented (designated) cash-flow hedges is deferred in an equity account - other comprehensive income (OCI).
When the hedged transaction settles, the OCI is transferred to the income statement. For example, if a natural gas consumer wished to fix the price of fuel the following year, the company could purchase a natural gas forward contract for $3/Mcf. The contract would be documented as a cash-flow hedge against the variability of the following year's price of natural gas. If the market price of natural gas fell to $2.50/Mcf at the intervening year-end, the contract would be recorded as $2.50 and a $0.50 charge would be recorded in OCI. If the subsequent year's price, at settlement, were $2.75, then the company would mark the derivative to $2.75 and record a $0.25 gain in OCI. At settlement, the company would pay the contract price ($3), remove the derivative asset ($2.75), and transfer the cumulative comprehensive income amount ($0.25) to the income statement. The cost of the fuel is the contract price, not the market price at settlement. Hedge accounting locks in the contracted price, removing uncertainty, but the economic loss is deferred until settlement.
Understanding the complexity of the target's hedge accounting is critical to performing due diligence. Contract lengths, volumes hedged compared to total purchases or sales of the commodity, and the depth of understanding of the accounting requirements of SFAS 133 and its interpretations, are essential data points. Contract length is critical because the requirement for fair value derivative contracts forces market participants to estimate prices beyond the ready liquid market. For instance, a 20-year electricity contract must be recorded at fair value, but a liquid price point in that market may only exist for 36 months. Thereafter, the price will be an estimate based on broker quotes, demand forecasts, supply forecasts and other variables. Some companies do not project price increases beyond five years. Others assume growth of 1%-3%. The results of these assumptions on contract value are dramatic. To provide some transparency to these estimates, the Securities and Exchange Commission (SEC) published regulations requiring registrants to identify the source of estimated value in three categories: active market, broker quotes and modelling. This information should be obtained during due diligence, and significant value in the model category should be appropriately discounted after determining underlying assumptions.
The complexity of SFAS 133 raises the spectre of incorrect accounting. The Financial Accounting Standards Board (FASB) created a Derivative Implementation Group to produce interpretations (now numbering over 150) of SFAS 133. At the very least, there is the possibility of needing to conform accounting policies in the merger pro forma and, at worst, the possibility that an interpretation has been omitted or incorrectly applied. The due diligence team should interview the accounting officer responsible for derivatives to determine the depth of knowledge and the critical interpretations applied.
The prospective acquirer must understand that all amounts in the target's OCI will not continue as equity in the opening balance sheet. The target's equity will disappear and will not affect future earnings. For instance, in the example above, if a purchase were completed at the end of the year when the market price of natural gas was $2.50/Mcf, the opening balance sheet would reflect the following:
Derivative asset |
$2.50 (fair value) |
Goodwill |
$0.50 (previously OCI) |
Liability to counterparty |
$3.00 (contract price) |
The prospective acquirer also must understand that exceptions exist to the SFAS 133 fair value requirements. Contracts subject to those exceptions (previously unrecorded until settlement) will be recorded in the opening balance sheet at fair value - resetting all pricing to market at the date the business combination is closed. For instance, assume an electricity generator contracted to sell electricity for $80/Mwh. This contract met the requirements of SFAS 133 to be classified as a normal sale and, therefore, was not recorded at fair value until settlement. If the generator is purchased when the market price for electricity is $50/Mwh, the amounts that will be reflected on the opening balance sheet are the gain or loss in the contract, an intangible asset, at closing. The opening balance sheet will reflect the following:
Contract receivable* |
$30 (amount over the market price) |
Goodwill |
$30 (offset) |
* sometimes known as a favourable contract
As electricity is delivered, the cash received will be the contract rate of $80/Mwh, but the collection of the contract receivable reduces the future revenue stream to the market price at closing, or $50/Mwh. The positive or negative experience of the target in managing price risk through contracts existing at the acquisition date will be experienced in cash flows, but not in post-acquisition earnings.
Energy trading
Most energy companies developed energy trading desks to manage price risk and to take advantage of volatility in deregulated markets. The challenge to the prospective acquirer is to evaluate the quality of the risk metrics used to monitor the positions they are taking. Trading operations generate income from three sources: commissions, volatility and taking positions (betting on a price view). All energy trading contracts must be marked to market unless designated as a hedge for the non-trading affiliate in consolidation. Historical results are meaningless unless put in the context of underlying market volatility and the degree to which the forward trading book was balanced. As more entrants enter this market, margins grow thinner.
In energy trading, the media has recently focused its attention on wash trading or round-trip transactions. The Federal Energy Regulatory Commission defines such activities as the simultaneous purchase and sale of electricity or gas with the same counterparty. While some allege these transactions are entered into for valid businesses reasons, widespread skepticism exists because such transactions artificially increase reported revenues (for those energy trading companies that report revenues on a gross basis), can manipulate forward pricing markets and can create the appearance of an active market. Consequently, due diligence procedures should focus on identifying the target's energy trading revenue recognition method, reviewing a listing of the target's largest counterparties and performing a file interrogation of the target's energy trading records.
Special purpose entities
The energy industry commonly financed hard assets (for example, power stations, pipelines and storage facilities) through off-balance sheet financing vehicles. These structured finance transactions met the literal requirements of US GAAP, but have received scrutiny following Enron's December 2001 bankruptcy. Accounting rules for these entities are changing and due diligence should focus on whether the existing structures would meet the requirements of the new rules - specifically, whether related party special purpose transactions resulted in recognized gains for the target. In general, transactions with related parties should not result in gains. Financial guarantees of the debt or equity of special purpose entities also should be explored.
A particular special purpose transaction is a synthetic lease, involving a special purpose entity that builds an asset (for example, a power plant) and then leases the asset to a generator or other party. The generator provides a residual value guarantee (usually 89.9% of the asset value) to the special purpose entity at the end of the lease term. For tax purposes, these transactions are capital leases so that the generator records and depreciates the plant against taxable income. For financial accounting purposes, these transactions are operating leases and the lease payment is recorded as an expense. The lease payment in a synthetic lease generally represents only the financing cost of the underlying asset with no principal payment. Therefore, if the special purpose entity ever fails to meet the appropriate GAAP test or if the rules change, the effect on future income is greater than the financing cost. An additional depreciation expense also must be calculated. In due diligence, the pro forma effect of special purpose entities must be modelled with care because of the potential combination of interest expense and depreciation expense.
Other accounting due diligence concerns
Accounts receivable valuation
Counterparty creditworthiness is an increased risk because of concerns over liquidity in a weakening economy and in the energy industry in general. Due diligence teams should evaluate trade receivables by major product line, division and customer type, as well as review the target's recent bad debt history, disputed balances and current credit concentrations. For extreme credit concentration situations, the acquirer also should evaluate the potential for right of offset in the event of counterparty non-performance through master-netting arrangements or industry-standard contracts.
Intangible assets
SFAS 142, Goodwill and Other Intangible Assets, contains additional operational criteria for recognizing intangible assets in a business combination. Thus, details should be obtained pertaining to such items as patents, trade marks and copyrights, showing all pertinent terms, including age and amount of sales covered. A schedule of recorded intangibles by major categories and related amortization policies also is useful in determining the income statement effect in future years. Under SFAS 142, intangible assets with indefinite useful lives are not amortized. One of the first considerations of an SEC review is determining whether intangibles have been identified, and subsequently correctly valued and classified as amortizable or non-amortizable.
Debt
In purchase accounting, the target's outstanding debt is recorded at fair value if not repaid as part of the merger agreement. Existing public debt usually survives. The practical effect of the accounting rules is to reset the effective interest rate to the market rate at the date of acquisition by recognizing an increment to or decrease in the par value of the debt. Frequently, covenants require repayment of bank debt if a control change occurs. In a stock purchase, existing covenants become applicable to the new corporate parent and, in due diligence, any particularly onerous conditions should be understood.
Contracts
Sales commitments, take-or-pay contracts, leases and other contracts for future exchanges of cash are intangibles for accounting purposes, and are presented at fair value in the opening balance sheet. Any contract pricing, therefore, continues to govern the terms of the cash transactions, but recognition in earnings will reflect market prices in effect at completion. For instance, if a lease for office space signed six years ago with a fixed rental of $35/square foot for 100,000 square feet and a remaining term of four years was present in a business combination consummated when the prevailing rental rate was $50/square foot, an asset would be recorded. This asset, with a value of $6,000,000 (($50 - $35) x 100,000 x 4), would be amortized over the remaining life of a lease to increase rent expense, although the cash paid for rent would continue to be $3,500,000 each year.
Other liabilities
Other liabilities frequently include contingencies that management has estimated. In due diligence, letters of audit inquiry that external counsel sends to the independent auditor are a useful source for identifying contingent liabilities. The company usually will have a copy of each letter; otherwise, the independent auditor's working papers may be reviewed, with appropriate written permission. Valuation of contingent liabilities is ultimately a matter of judgement. In instances where material amounts are claimed, engaging another counsel to evaluate the facts to estimate the outcome is often useful. The SEC has cautioned acquirers not to materially increase liabilities related to contingent liabilities unless facts have changed or the acquirer will settle the liability in a different fashion.
Contingent liabilities also include environmental remediation liabilities that may exist for onsite and offsite contamination. A joint and several damage clause frequently is associated with offsite clean-up, requiring a review of the financial standing of contributors to contamination. Each jurisdiction may have unique requirements. In many cases, permission for facilities for air or water discharges is tied to environmental compliance. In due diligence, the inquiries of environmental compliance officers are critical to identifying risks and liabilities. As a condition for existing permits, future capital commitments for environmental projects, particularly for coal-fired electrical generators, may be required.
Other liabilities include guarantees of indebtedness and outstanding letters of credit. Letters of credit are common to demonstrate financial assurance for environmental remediation or site restoration costs. An examination of underlying plans and the financial condition of entities to whom guarantees were extended should be part of due diligence.
Intercompany/affiliate transactions
The due diligence team should scrutinize any affiliate or other related-party transaction involving non-consolidated affiliates. Procedures should focus on the propriety of transactions and their proper recording/disclosure in financial statements. All gains and losses recognized between affiliated companies should be closely evaluated to assess propriety.
The acquirer should obtain details of the target's accounting for investments, including equity in earnings, investment premiums (goodwill), elimination of intercompany profits, and other financial statement effects not readily apparent from financial statements of investees.
Regulatory assets and liabilities
In a regulated environment, the acquirer should involve regulatory specialists to identify factors to consider, including existing rate orders versus expected orders - in particular, work should consider the assumptions and amounts deferred, and the timing of expected recovery through rates. As energy markets move towards deregulation, a focus should be placed on identifying potential stranded costs, for example, regulatory assets that may not be recoverable in a competitive environment. Also, specialists should be heavily involved to determine the effect of deregulation in the target's landscape.
The following information would likely be useful in any due diligence of a rate-regulated energy company:
last two years' rate case filings;
pending rate filings;
last three years' FERC Form 1;
deregulation orders and legislation;
refund exposure;
accounting for acquisition premiums (for example, goodwill and basis in assets), and effect on regulatory accounting and rate determinations; and
regulatory evaluations.
Nuclear generation
Pertinent information for nuclear generation facilities includes an identification of specific plant facilities and equipment and their condition, capacities age, technologies and performance, suppliers, fuel, and operations and maintenance expenditures. Of particular importance is the changing of depreciable lives in an environment of regulatory licence extensions. Such extensions, if approved, can dramatically increase depreciable lives and, therefore, a plant's profitability. After 20 years, a nuclear licence (which lasts 40 years) may be renewed for another 20 years. Based on the in-service date of many merchant nuclear plants, such relicensing is a fact to consider when assessing whether there is sufficient basis to extend a plant's useful life. This is as much an engineering determination as a financial decision.
Oil and gas operation
Oil and gas exploration and production operations are high-value, capital-intensive operations subject to many estimates and risk factors. In the opening balance sheet, properties are presented at fair value as of the date of acquisition. Fair value is determined by projecting future production volumes and assuming sales at prices implied by forward price curves as of the date of acquisition. The production volumes assumed are representative of those determined to be economically recoverable based on the assumptions for pricing and cost. Costs incorporated include pure lifting costs, severance and ad valorem taxes, and developmental costs required to develop such properties. The effective income, net of royalties and other costs, is then present valued at a discount rate commensurate with the risks and return on capital required. This methodology is used for proved properties as well as for those properties in the unproved and probable categories for which the target can develop a risk-based reserve additions model. Determination of future reserves in these categories should focus on the specific regions for which the target holds lease acreage, and for which there are future identified prospects to be drilled. For these prospects, a target should determine the potential reserves that would be recovered and then develop a risk model based on historical success rates for similar properties in that productive region. Additionally, a target should look into the various regions for which it holds lease acreage and determine the potential notional wells that will be developed, to try to fully capture the total anticipated future reserves embodied in the acquired assets.
Finally, the target should look at the remaining value that would be assigned to seismic and other related assets, for which no specifically identified or notional wells are included in the reserve valuation. These assets should be individually reviewed to determine what the potential fair market value of such assets would be to the target. Because these assets typically do not have identified wells, the entity either has the ability to sell the asset (with the asset reflecting the potential sales price) or the entity has no use for the asset, which will be valued at a zero basis.
Production volume figures typically are estimated by the target's internal engineers, for which an independent reservoir engineer typically is used to verify such computations. Most significant exploration and production companies retain an engineer because reserve estimates are required in SEC disclosures for oil and gas companies. The estimates are based on numerous scientific structural facts as well as historical facts for the given productive geological formation. Engineering firms, such as professional service firms in other industries, have reputations and bias that are known in the industry.
The selection of a discount rate is a critical estimate. A range between 15%-18% is common, but values outside the range can be justified based on the geographical location of the reserve basins, international economic and political factors, and market rates of return on equity. The SEC ceiling impairment test uses a 10% rate for full cost companies.
It is not unusual for the acquirer and target to use different accounting methods to account for oil and gas operations. The opening balance sheet value is the same in either case, but operations thereafter will differ significantly. The full cost method is regulated by the SEC, and permits capitalization of dry holes for both exploratory and developmental wells subject to an impairment test. The successful efforts method expenses dry holes as discovered for exploratory drilling, but allows for capitalization of developmental dry holes. Additionally, capitalization and amortization of costs is significantly different because all costs incurred from the initial lease cost to the well head control equipment cost are capitalized into one pool under the full cost method, and amortized over the proved reserve quantities. Conversely, under successful efforts, costs for leaseholds are capitalized and amortized over the total proved reserve quantities, and the costs incurred in drilling a well are capitalized and amortized over the proved developed quantities. As noted, the full cost pool is subject to an impairment test that is representative of a point-in-time valuation based on period-ended pricing at a present value of 10%, whereas, under successful efforts, the accumulated costs on a field level basis are analyzed under SFAS 121, which applies the future cash-flow stream against capitalized costs.
Both are widely used, with the largest oil companies favouring the successful efforts method.
New accounting standards
The acquirer's pro formas will need to consider the impact of new or proposed accounting standards on the target, including, but not limited to:
new asset retirement obligation accounting standards;
proposed rules relating to energy trading and marketing activities, such as reporting first-day gains on energy trading transactions; and
proposed rules regarding guarantees and special purpose entities.
SEC investigations
SEC investigations include recent, current, or pending investigations, particularly those involving sensitive issues related to the energy industry, including alleged undisclosed transactions with affiliates, irregularities in the energy trading business, deficiency in reporting and internal controls, and questionable transactions involving special purpose entities. A copy of SEC comment letters covering recently filed Form's 10-K and 10-Q should also be requested.
Other
The following table highlights other focus areas in performing financial due diligence.
Financial – General |
• Monthly management reporting packages, together with commentary review of results against plan |
• Details of any changes in accounting principles, practices and procedures |
• Listing of all significant non-recurring adjustments made during the fourth quarter of the last two years |
• Reports to management issued by independent public accountants and by the internal auditing department |
• Board minutes |
Reconciliations |
• Cash, intercompany, receivable, payables and accrued reconciliations |
Inventories |
• Summary of aged inventory by major category |
• Summary of inventory write-offs as of the most recent two years |
• Listing of purchase and sales commitments |
• Transportation agreements, storage agreements, pipeline, transmission contracts and option/swap contracts, and open position reports |
Property, plant and equipment |
• Summary of all major facilities owned, including location, description of usage, owned v leased, year opened, square footage, capacity and space available for expansion |
• Description of encumbrances |
• Listing of significant construction-in-progress projects |
• Memoranda and analyses in support of recoverability of fixed assets |
Current liabilities |
• Summary of accrued liabilities by major categories |
• Description and amounts of any disputes with vendors |
• Details of general liability and property insurance reserves |
Tax issues
Finding opportunities, as well as identifying risks, is often the result of effective tax due diligence. Given the significant tax implications in even the most basic of business combinations, tax specialists should be included on any due diligence team.
Historically, the nature of the rate-making process dissuaded many regulated energy companies from pursuing aggressive tax-saving strategies, thus reducing the likelihood of significant tax exposure. The trend toward diversification and deregulation has brought with it the incentive for implementing complex tax arrangements. While each of the target's arrangements will be important to understand from a cash flow and effective tax rate standpoint, the US Internal Revenue Service (IRS) and US Treasury's increasing pressure on tax shelters heightens the need for caution and thorough tax due diligence.
In addition to being important for evaluating exposures, due diligence also provides an understanding of the target's tax position that can yield ideas for tax savings. The due diligence team members should possess the skill sets to recognize and implement strategic or structuring opportunities.
Summarized below are a few of the more relevant tax considerations in energy acquisitions.
Derivatives and trading
The advent of SFAS 133, and its associated complexities, should not divert attention from the fact that each type of derivative transaction may have its own set of potential tax consequences and pitfalls. In fact, book and tax characterization of the same transaction may be different. Further complicating matters, in recent years, the IRS amended several of the tax rules that affect the characterization and timing of gains and losses from transactions involving commodities.
Due diligence should include assessing the target's tax policies and procedures in this area. Of primary interest will be risks associated with the company's (i) treatment of gains and losses as capital versus ordinary, (ii) timing of recognition of those gains and losses, including application of the straddle rules, and (iii) income-sourcing practices applied in determining what tax jurisdictions have the right to tax profits. Further, similar to SFAS 133, the tax rules include extensive and strict documentation requirements, which impact the availability of favourable tax treatment of these items.
Cross-border structures and financing arrangements
With increasing activity in cross-border energy transactions has come a proliferation of creative investment and financing structures. Many countries, including the US, are becoming more focused on minimizing income shifting, double dip and withholding-avoidance structures through legislation, treaty modification and more focused audits. Common issues that surface in the financing context are the deductibility of interest paid to foreign related parties, withholding taxes and reporting, and the use of tax losses. Of particular US interest lately has been companies' aggressiveness in moving profits offshore to tax havens. The impact of these structures may or may not be fully seen in the target's effective tax rate, as some companies choose to reserve for potential losses of the claimed benefits. In any event, however, the cash-flow consequences (including interest and possible penalties) can be significant.
Impact of regulatory changes
Although the pace of change has slowed dramatically in recent months, deregulation - both domestic and foreign - may have a significant impact on a company's tax burden. Tax assets could be included among the stranded costs discussed above. In addition, a target's mix of above-the-line and below-the-line taxes may shift, causing historical results not to be indicative of future expectations. For example, a state that has historically relied on revenue-based or property-based taxes on utilities may move to an income tax system. Typically, this aspect of deregulation is intended to be tax-neutral, but anomalies can arise. Careful analysis of enacted and pending legislation is critical to assessing the target's and combined entities' future tax burden.
Attribute preservation
The target may have substantial tax attributes such as net operating losses (NOLs), foreign tax credits, and other energy-related tax credits worth preserving and maximizing as part of a transaction. In addition to confirming the validity of the attributes as they were generated, a portion of due diligence should focus on whether the attributes have been or will be impaired as a result of debt forgiveness, previous changes of control, restructurings or the contemplated transaction. In the US, for example, a change of ownership of 50% or more over a three-year period can limit a company's ability to use NOLs and other credits.
Property taxes
Since energy companies are often very capital-asset intensive, property taxes can be a significant portion of their overall tax burden. Due diligence should address, among other things, categorization of assets between real and personal property, and any exemptions or abatements claimed by the target. An understanding of both the target's activities and aggressiveness, as well as the legislative environment, are key.
Common tax accounting method issues
Although due diligence on energy targets should include consideration of all varieties of tax accounting method exposures, the following areas are often more significant and relevant, and may require closer scrutiny:
removal and overhaul costs;
repair allowances;
start-up costs and placed-in-service dates;
hedging activities;
R&D;
synthetic leases;
clearing and grading costs;
development costs;
depletion;
contributions in aid of construction;
tax-exempt financing;
investment tax credits;
customer deposits and advance payments;
unbilled revenue;
deferred fuel costs;
political/lobbying expenses;
ERP and CRM systems and implementation costs; and
transaction costs.
Foreign Investment in Real Property Tax Act (FIRPTA)
This law, enacted in 1980, has the potential to trigger unexpected tax liabilities in the context of sales of US operations owned by non-US persons or entities.
Whenever a US subsidiary of a foreign multinational is sold, regardless of whether sold to a related or unrelated buyer, the transaction is likely to be subject to US tax if the taxpayer cannot establish that less than half of the subsidiary's business assets are, or were for a five-year look-back period, US real property interests. This is a negative presumption that must be rebutted to avoid the imposition of US tax on the transfer. If the presumption is not rebutted, the US target is a US real property holding company (USRPHC) and the sale of its stock will be the sale of a US real property interest (USRPI), subject to US tax. Further, the purchaser will be required to withhold 10% of the sales price.
The significant value of an energy company's capital assets relative to its total assets raises the need to be alert to FIRPTA issues, since subtle distinctions between the classification of assets as real versus personal property may exist.
Conclusion
There are many accounting and tax issues to consider. Some acquirers may spend several weeks just focusing on deal breakers. On the other hand, a foreign acquirer may spend six to eight weeks on financial due diligence getting comfortable with local GAAP, tax and business issues. However much time is spent, it may not be enough to guarantee that accounting surprises will not occur. The key is to identify the big issues that make a difference to the success of the transaction.
