The Interaction of Accrual Management and Hedging: Evidence from Oil and Gas Firms

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1 The Interaction of Accrual Management and Hedging: Evidence from Oil and Gas Firms by Morton Pincus Associate Professor of Accounting Tippie College of Business The University of Iowa Iowa City IA and Shivaram Rajgopal Assistant Professor of Accounting School of Business Administration University of Washington Seattle, WA Current draft: December 7, 2000 We appreciate the comments and suggestions we received from the anonymous referees and Mary Barth (the associate editor), from workshop participants at the joint Oregon-Washington-UBC workshop, the University of Pittsburgh, the University of Wisconsin, and the 1999 American Accounting Association annual meetings, and from Lisa Bryant, Dave Burgstahler, Neil Fargher, Gerry Feltham, Steve Fortin, Jim Jiambalvo, Mark Kohlbeck, Eric Noreen, Joe Paperman, Terry Shevlin, and

2 D. Shores. Pincus gratefully acknowledges the financial support of the Tippie College of Business at The University of Iowa. 1

3 The Interaction of Accrual Management and Hedging: Evidence from Oil and Gas Firms ABSTRACT: This research investigates whether oil and gas producing firms use discretionary accruals and hedging with derivatives as substitutes to manage earnings volatility. We examine firms primarily engaged in oil exploration and drilling since we can identify two kinds of risks to which these firms are exposed that can cause earnings volatility. These are oil price risk and exploration risk. While firms can hedge oil price risk with derivative instruments, markets do not exist in which they can hedge the operational risk of unsuccessful drilling. Discretionary accrual choices and hedging with derivatives can both be used to reduce volatility caused by oil price and exploration risks, while only hedging can reduce cash flow volatility induced by oil price fluctuations. Empirically, we consider the decision of whether or not to hedge oil price risk, and then, given that hedging occurs, we allow for simultaneous decisions regarding the extent of hedging and the extent of smoothing with discretionary accruals. The results indicate that, after controlling for hypothesized determinants of hedging and smoothing with discretionary accruals, managers make decisions about the extent of hedging oil price risk independent of decisions about smoothing with discretionary accruals, but they then make decisions about the extent of smoothing with discretionary accruals based on the extent of their hedging and they do so in a manner that treats the extent of hedging and the extent of smoothing with discretionary accruals as substitute mechanisms for smoothing income. Key words: Hedging; Derivatives; Income smoothing; Discretionary accruals; Oil and gas firms. Data Availability: All data used in this research are from publicly available sources.

4 The Interaction of Accrual Management and Hedging: Evidence from Oil and Gas Firms I. INTRODUCTION In this paper we study the relation between two mechanisms that managers of oil and gas producing firms can use to manage earnings volatility. Specifically, we investigate whether discretionary accrual choices and hedging with derivatives are used as income smoothing substitutes. Earnings variability is a function of both cash flows and accounting accruals. Hedging dampens cash flow and thus earnings volatility, while smoothing with discretionary accruals directly affects only the latter. The question of whether managers smooth income, i.e., take actions to reduce the time-series variability in reported earnings, has interested researchers and financial analysts for a long time (e.g., Ronen and Sadan 1981; Schipper 1989; Hunt et al. 1996). DeMarzo and Duffie (1995) have demonstrated that managing earnings volatility can be an optimal strategy from the shareholders' perspective, and Schrand and Elliott (1998, 276) note that controlling accounting risk, i.e., "the risk associated with variability in accounting amounts," is a frequently cited objective of managers. 1 We focus on oil and gas producing firms. These firms primarily are engaged in exploration and drilling, and we can identify two types of industry-specific risks that affect the volatility of their earnings and, thus, their accounting risk. The first risk is due to market factors, which are beyond management's control (i.e., fluctuations in oil prices), and the second risk is due to operational circumstances -- specifically, the firm's drilling success (also see Malmquist 1990; Fargher et al. 1997). 2 Oil and gas producers can use a variety of techniques to manage exposure to earnings volatility stemming from these risks. Oil price risk can readily be hedged with derivatives through transactions in capital markets. However, the same is probably not true of the risk of unsuccessful exploration for oil and gas. There 1

5 are, for instance, no markets comparable to oil futures markets in which a firm can hedge the risks it bears for oil exploration. We find that exploration and oil price risks are positively related and thus tend to impact earnings volatility similarly, rather than in an offsetting manner. This suggests that both hedging and smoothing with discretionary accruals can be used to reduce earnings volatility induced by these risks. If we assume that less volatility is always preferred, we would expect managers to use all available techniques to reduce earnings volatility. However, Haushalter (2000) documents that oil and gas producers do not hedge all of their exposure to oil price risk, and we find this is also the case in our sample. One possible explanation for this is that managers may have incentives not to hedge. This could occur, for example, if they hold stock options in their firms' shares and want to maximize volatility in their firms' stock price (Tufano 1996). Alternatively, managers may seek to coordinate their risk management strategies, as Schrand and Unal (1998) find is done in the thrift industry. In our setting, oil and gas firms might hedge oil price less extensively the lower their level of exploration risk, or possibly hedge oil price more extensively to take on additional exploration risk if they expect higher returns from exploration activities per unit of risk taken. Furthermore, hedging can be a costly and imperfect tool for eliminating volatility. Efficient hedging requires a certain level of expertise (e.g., hiring personnel with the experience and knowledge to manage a derivatives program, and economies of scale in transaction costs associated with hedging). If firms must bear costs of a certain threshold to obtain hedging expertise, larger firms will find it relatively less costly to hedge than will smaller firms. In addition, oil and gas producers may face basis risk, which is the risk that changes in the value of derivatives that are available for hedging purposes and changes in the value of oil and gas being hedged are not highly correlated. Moreover, hedging typically requires a 2

6 period of time to have an impact. On the other hand, it is probably less costly to obtain expertise to smooth income using DACs than expertise in hedging, and DAC entries have an immediate effect and can be made after the end of the fiscal year. Thus, there may be situations where it is more costly or less effective to hedge with derivatives than to use DACs to manage earnings volatility. Of course, smoothing with DACs also can be costly and ineffective. Greater scrutiny of accounting choices of firms listed on major stock exchanges may make smoothing with DACs difficult to implement, as might constraints on DAC choices under generally accepted accounting principles. Because both hedging and smoothing with DACs are costly and imperfect mechanisms for managing earnings volatility, managers may find it optimal to trade off one for the other. 3 To investigate the relation between hedging and smoothing with DACs with regard to managing earnings volatility derived from both market and operational risks, we address several key empirical design issues. First, there are substantive differences between firms that hedge and those that do not (Geczy et al. 1997; Haushalter 2000). Therefore, we analyze separately the decision of whether or not to hedge and the decision of the extent of hedging (Cragg 1971; Schrand 1994; Haushalter 2000; Barton 2001). Second, decisions about the extent of both hedging and smoothing with DACs likely are endogenous components of a firm's risk management strategy. To allow for this we use a simultaneous equations system in which the extent of hedging regression includes the extent of smoothing with DACs variable and the extent of smoothing with DACs regression includes the extent of hedging variable. 4 Third, it is the discretionary component of accruals that is relevant to our investigation. Accordingly, we disaggregate total accruals and estimate the discretionary and non-discretionary components (e.g., Dechow et al. 1995). 5 Fourth, oil and gas producers also decide whether to use the full cost or successful efforts method to account for exploration costs. Over our sample period fewer than three 3

7 percent of firms qualifying for inclusion in our sample changed their accounting for exploration costs. We concentrate on firms that did not change methods, and treat the full cost or successful efforts choice as a control variable for firm type and also incorporate it into our estimation of discretionary accruals. Fifth, we include controls for other determinants of hedging and smoothing with DACs. While some factors affect both hedging and smoothing with DACs, others are identified as determinants of only one or the other. We are aware of two papers that previously have examined the relation between accounting choice and hedging. Petersen and Thiagarajan (1997) report case study evidence of two gold mining firms; one managed risk with derivatives while the other used accounting estimates to smooth earnings. Barton (2001) documents a simultaneous and negative relation between foreign exchange and interest rate derivative holdings and discretionary accrual management in a subset of Fortune 500 firms, which is consistent with the substitution hypothesis we examine. Our study differs from Barton's (2001) in several ways. First, by focusing on a single industry we identify and measure the inherent market and operational risks faced by our sample firms. Thus, we can compute a hedging ratio that reflects the proportion of risk exposure hedged and we can estimate an important operational risk (exploration risk) and examine its interaction with hedging and smoothing with DACs. Barton (2001) can do neither of these things. 6 Second, we compute a smoothing ratio that relates the variance of non-discretionary earnings to the variance of earnings; it thus directly captures the effect on earnings of smoothing with DACs. Barton (2001) uses an indirect measure, the absolute value of discretionary accruals, and one can identify cases where, for example, larger absolute values of discretionary accruals do not result in smoother earnings. Third, we are able to identify and account for an important accounting choice (full cost or successful efforts) on discretionary accruals. Barton does not do this since important accounting 4

8 choices are too numerous across a set of industries to allow satisfactory identification and control. Barton acknowledges the weaknesses in his hedging and DAC variables and notes that measurement error in his hedging variable potentially is an alternative explanation for his results supporting simultaneity. It thus is reasonable to believe our setting is a more powerful one to examine the substitution hypothesis and our endogenous variables are less subject to measurement error enabling us to more reliably gauge the presence of simultaneity in the extent of hedging and smoothing with DAC decisions. Our results indicate that in the extent of hedging regression, the extent of smoothing with DACs is not significant. However, the extent of hedging is negatively related to the extent of smoothing with DACs in the extent of smoothing with DACs regression. The results are consistent with firms not attempting to eliminate earnings volatility and suggest that managers implement oil price hedges independent of smoothing with DACs, and then make DACs decisions near or even after the end of the fiscal year in light of the extent of hedging they have engaged in. That is, there is a sequential process in choosing between two smoothing tools; managers put into action their hedging decisions and then use DACs to smooth earnings more (less) the less (more) extensively they have hedged oil price risk. We organize the remainder of the paper as follows. First, we develop the motivation for expecting managers of oil and gas producers to view hedging oil price risk and smoothing with discretionary accruals as substitute devices for managing earnings volatility. We then specify the empirical models in section III and identify the explanatory variables for the hedging and the smoothing with DACs regressions. Section IV describes the sample and presents the results, and the final section includes a summary, conclusions, and a suggestion for future research. 5

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10 END NOTES 1 DeFond and Park (1997) provide evidence that managers smooth income because of concerns about job security. Barth et al. (1999) document higher price-earnings multiples for firms exhibiting patterns of steadily increasing earnings and a decline in price-earnings multiples when earnings fall after a prior pattern of increasing earnings. 2 Equity Research, Oil & Gas Production (Bear Stearns, August 21, 1996, 21) states the "two major risks in the E&P [exploration and production] business are dry holes and commodity price swings." Because we can identify their inherent risks, we focus on exploration and producing firms (SIC code 1311, Crude petroleum and natural gas) and exclude large, vertically integrated firms that explore, extract, transport, refine, and distribute oil and gas products (i.e., SIC code 2911, Petroleum refining). 3 Hedging affects earnings volatility by directly impacting the distribution of underlying cash flows, unlike discretionary accrual choices (although DACs may provide signals about future cash flows). We are interested in the interaction of hedging and DAC choices in managing earnings volatility irrespective of the smoothing mechanism's impact on cash flows. 4 Beatty et al. (1995) and Hunt et al. (1996) discuss the simultaneous assessment of the substitution or complementary effects that accounting and financing decisions can have. 5 Discretionary accruals reflect measurement error using existing estimation approaches (e.g., Bernard and Skinner 1996; Dechow et al. 1995) and probably should be referred to as unanticipated or unexpected accruals. We use the term discretionary accruals since it is the term used in a long line of research in earnings management and perform several sensitivity checks of our DAC smoothing variable. 6 The denominator in Barton's (2001) hedging variable is lagged total assets, whereas the denominator of our hedging ratio is the amount of underlying risk a firm is exposed to. Also, the numerator in our hedging ratio is the firm's hedging position for which we can sign long and short derivative positions. 7 Holthausen (1990) suggests that concerns about reputation can serve to make credible a manager's attempt to communicate private information about his/her firm via accounting choices. Also see Subramanyam (1996). 8 If oil price and exploration risks were negatively related, hedging oil price risk would create additional earnings volatility since earnings shocks from oil price fluctuations and exploration activities no longer

11 would be offsetting. Managers seeking to smooth earnings then would have to use DACs to a greater extent, the greater their use of oil price hedging (if higher magnitudes of DACs translate into greater levels of smoothing, as Barton (2001) implicitly assumes), making hedging and smoothing with DACs complements almost by necessity. But cases then could arise where managers would need to smooth with DACs to a nearly unlimited extent. However, in our sample oil price and exploration risks are positively related (Pearson correlation = 0.16, p-value =.07, two-tailed test). (We estimate an oil price beta for each firm/year as our measure of oil price risk by regressing firm-specific daily stock returns on market returns and percentage changes in oil prices. The mean oil price beta is reliably positive, which is consistent with firms not being fully hedged. Below we discuss our exploration risk variable.) 9 Hedgers equals 1 for a firm having a non-zero derivative position at year-end, and 0 otherwise. We consider a firm's net derivative position, which could reflect derivatives held for trading purposes. However, as noted below (Panel A of Table 2), trading securities are present in only seven percent of firm/years, so including them does not induce a serious measurement problem. 10 We rely on commodity derivative data firms voluntarily disclosed, and cannot rule out the possibility firms might have disclosed different or more complete information had SFAS No. 119 (FASB 1994) required them to do so. Lack of availability of quarterly data on derivatives precludes analysis on a quarterly basis. 11 The numerator is the total notional quantity of oil and gas hedged, which we determine by aggregating across various derivative types. This introduces measurement error since not all derivatives of the same notional quantity have the same risk-reduction properties. A swap (or a forward or futures) contract with a notional quantity of one million barrels may not change a firm's cash flow volatility to the same degree as an option contract with the same notional quantity. This is because options are one-sided contracts whereas swaps, forwards, and futures are two-sided contracts (there are receivable/payable implications whether the oil price rises above or falls below the strike price of the derivative). To shed further light on this limitation, we compiled a frequency count of instruments used for hedging by our sample firms. Standardized by derivative/years, we find forwards are used in approximately 44 percent of firm/years with hedging, swaps are used 33 percent of the time, futures 13 percent, and options 10 percent. Since options use is limited in our sample, aggregating across instrument types is not likely to introduce significant measurement error in our hedge ratio variable. 49

12 12 We examined one-third of our sample firms' balance sheets, income statements, and related notes in depth to identify the common types of accounts reflecting accruals. Operating current assets and liabilities included accounts receivables, inventories, prepaid expenses, various payables, and accrued expenses, which are typical of companies in general. Hence, the modified Jones model would seem to be appropriate here given that most of the current assets and liabilities are pretty typical of a manufacturing firm. There were also several line items that reflect oil and gas exploration and production. These included the following: (a) receivables (payables) from deliveries of natural gas due to excess production (underproduction) where revenue is based on a firm's working interest or entitlement in a field's production; (b) deferred oil and gas revenues recognized as revenue upon delivery under prior sales of volumetric production payments (which are a financing tool in which firms receive advance payments for deliveries of future production at a certain price); and (c) reserves for dismantlement, restoration, and reclamation that are provided based on estimates of, for example, environmental clean ups, and reserves for asset impairments, in general, and write-downs of oil and gas properties, in particular. 13 SFAS No. 69 (FASB 1982, 55) suggests oil and gas exploration costs may not necessarily be related to success or failure of exploration activity, similar to research and development costs. 14 The basic difference between full cost and successful efforts concerns the treatment of exploration costs related to unsuccessful wells. A firm using successful efforts expenses the costs of dry wells; thus earnings will be lower for a period when a well is determined to be uneconomic than when a well is proven to be productive. Under full cost, exploration costs related to dry wells are capitalized and amortized into future earnings. Full cost views an entire drilling area as an asset, while only productive wells are assets under successful efforts. Malmquist (1990) and references therein identify determinants of full cost and successful efforts use. 15 Firms may find it less costly to smooth earnings by using DACs or hedging than to change accounting methods for exploration costs even if underlying economic factors change. Also note that full cost can induce greater variability in earnings when there are sharp oil price declines that necessitate write-downs of reserves. On a year-to-year basis, sharp declines in oil prices did not occur during our sample period (see Rajgopal 1999). 16 Book earnings proxy for taxable income and current earnings proxy for future profitability. 50

13 17 Computing incentive effects from stock options (e.g., sensitivity of options to returns or returns volatility) requires extensive information such as time to maturity and exercise price of all options (new and those previously granted to employees). Full disclosure of previously granted options is not available in footnote data and Execucomp includes complete data for only 25 sample firms. 18 The association between earnings volatility and dividend payout ratio is consistent with dividend restrictions in bond covenants frequently being based on accounting earnings realizations (Smith and Warner 1979). 19 The coefficient of variation, CV, equals Standard deviation / Mean. 20 Haushalter (2000) finds an absence of hedging in almost one-half of the firm/years he examines of 100 oil and gas producers, and reports a lower mean hedge ratio than we find in our sample. 21 Prior studies (see Foster 1980) find that large firms typically use successful efforts, but there is no significant correlation between Firm size and Method in our sample (not shown). As noted, our sample includes oil and gas exploration and drilling firms and excludes large, vertically integrated companies. 22 Haushalter's (2000) sample is quite similar with respect to diversification of operations, but reflects a greater degree of basis risk regarding the location of U.S. production. 23 Our inferences are unchanged when we use log of 1 + DivPayout. 24 Reported p-values are one-tailed unless the prediction is non-directional. 25 It is conceivable that Intl production might proxy for more than basis risk exposure due to international production. Firms having oil and gas production overseas may be subject to foreign exchange risk as well as basis risk. While oil price is denominated in U.S. dollars worldwide, thus protecting revenues from foreign exchange risk, the cost side could be exposed. Thus, firms with international production may have an incentive to hedge foreign exchange risk, and our dummy variable could proxy for that. The observed negative coefficient on Intl production in the hedge/no hedge regression would then capture both the impediment to hedging oil price risk due to basis risk and substitution between foreign exchange hedging and oil price hedging. 26 p-values are White (1980) adjusted. 27 We re-estimated the Hedging ratio and DAC smoothing ratio regressions separately using OLS and the results are similar to those reported in Table 3. In addition, we tested for serial correlation in the residuals since observations for some firms are included more than once in our sample. For the 51

14 DAC smoothing ratio regression, the Durbin-Watson statistic is 2.06, indicating no first-order serial correlation. For the Hedging ratio regression, DW = 1.29, which is significant at the.05 level, but understatement of the standard error from the indicated serial correlation is not a serious concern since the coefficient on DAC smoothing ratio is insignificant. 28 See the text surrounding footnote 2 in Barton (2001) and his footnote 5. Also, see Greene (1993) sections and Barton's (2001) sample is drawn from and the sample firms are large, represent many industries, and 72 percent use derivatives (for foreign exchange and interest rate hedging). 30 It conceivably might also reflect a mechanical relation since full cost smoothes earnings more than successful efforts. But our incorporation of Method in the modified Jones model should mitigate any tendency of full cost mechanically to induce larger DAC smoothing ratio values. 31 We re-ran the regressions after down-weighting influential observations (as recommended by Belsley et al. 1980) using the RWEIGHT function in SAS. The nature of the results is substantially the same as reported. 32 Reserves proxy for all future years' production. Even if the typical firm's hedge ratio scaled by current production is less than 1, we cannot conclude that the duration of the derivative is one year or less. In fact, we found instances where a derivative spanned three and sometimes five years. Hence, scaling by all years of future production is arguably a more defensible design choice and is consistent with the belief that when oil prices change, the market incorporates the change in the present value of future cash flows from all future production, not just the current year's production, into stock price. But also note the cross-sectional correlation between current and subsequent year production is 0.70 (p= 0.00). Thus, production is fairly sticky over time. 33 Lack of data for the lagged DAC variable causes a loss of 15 percent of the observations. 34 Total accruals (TA) are computed as income before extraordinary items (EBEI) minus cash flows from operations (CFO). EBEI includes the earnings effects of any special items. CFO equals working capital from operations (WCO) minus changes in non-cash operating current assets (ÄCA) and plus changes in operating current liabilities (ÄCL). WCO includes the earnings effects of special items since it includes EBEI and is not adjusted for special items (per Han and Wong 1998, ftn. 10 and 11). However, if special items occur and we assume there are no cash flows associated with the special 52

15 items in the quarter, then the -ÄCA and +ÄCL adjustments have the effect of double counting the earnings effects of special items in CFO. To illustrate, consider a restructuring charge that is accrued in a quarter but for which no cash flows are incurred. (SAB 67 (SEC 1986) requires restructurings to be treated as part of income from continuing operations.) ÄCL will include the restructuring reserve that will be added to WCO to determine CFO. Since WCO already includes the restructuring charge, CFO will now reflect a double counting of the restructuring loss. In turn, when total accruals are computed as EBEI - CFO, the result will be too small since double the amount of the restructuring will have been deducted. 35 We also examined firms' 10Ks and annual reports for the specific nonrecurring items reported in income before extraordinary items. There are more frequent and larger magnitude oil and gas reserve write-downs in firm/years with hedging versus those with no hedging. However, the magnitude difference is driven by a few extreme cases. In particular, most of the reserve write-downs occur in October 1995 and are impairments taken under SFAS No. 121 (FASB 1995) by firms that, for the most part, use successful efforts. Falling oil prices characterized the months prior to October 1995, although oil prices rebounded in 1995's fourth quarter (Rajgopal 1999). 36 Sunder's (1976) derivation assumes a constant success rate, θ, implying that θ is independent of N. However, one can argue that θ during a period depends on previous period experience (e.g., learning effects) or that θ is inversely related to N (e.g., firms are likely to exhaust better drilling prospects before moving on to worse prospects). In our empirical measure of Sunder's variance, the components of the variance measure can vary every year. Hence, our measure allows for the possibility that exploration success rates change over time. 37 Sunder's variance is unaffected by the choice of full cost or successful efforts, although it is not unaffected by hedging, which affects cash flows. This likely reflects a potential second order effect of the full cost/successful efforts choice on cash flows and hence on Sunder's variance. Exploration related cash flows likely are measured before the impact of hedging since we have not seen statements by sample firms that they hedge expected production from discoveries or exploration. They are more likely to hedge production coming from the extant stock of reserves. 38 Inferences are unchanged when age is a weighted average of the ages of oil and gas wells. 53

16 39 Firms frequently conduct exploration activities in an area as a part of a consortium. A gross well is a well in which an interest is owned by the firm. A net well represents the fractional interest owned by the firm in the gross well. We use net wells to compute exploration success. 40 If the number of exploratory wells drilled is 0 and or the success rate is 0 or 1, the variance is set equal to 0. 54