Rigs are the primary assets of drilling contractors and fleet inventories are tracked by a number of commercial organizations. Private and state-owned firms usually report their fleet size on company Web pages. The scale and quality of a contractor’s fleet is correlated with its revenue base. A large asset base implies a platform for sustainable earnings and cash flows and is related to a company’s market position, cost structure, and ability to obtain financing for capital projects.
The net asset value (NAV) of a rig is an estimate of the rig’s discounted expected future net earnings evaluated using cash flow models and rig-specific parameters. Fleet value is the sum of the NAV of all the rigs in a firm’s fleet. Jefferies, Standard and Poors, ODS-Petrodata, and other investment and market intelligence firms develop NAV estimates based on proprietary cash flow models and their data is widely referenced in the industry (Slorer et al. 2011; Glickman 2006), but because economic evaluation is universal, NAVs are easy to compute (See Appendix A). Fleet value is correlated with fleet size because of the commodity-like nature of the rigs and the algorithmic manner in which fleet values are assessed (Fig. 7). Fleet value is expected to be a better predictor of firm value than fleet size because it incorporates variation associated with rig class, specifications, dayrates and contract status, while fleet size only measures the number of rigs.
Firm revenue is a function of fleet size, dayrates and utilization rates. Firms with greater revenues will have greater earnings and value, and for all else equal, firms with more valuable fleets are expected to generate greater revenue. Revenue may vary considerably from year to year depending on market conditions and fleet portfolio, and as a result, revenue tends to be a less stable measure than fleet value.
Old fleets are less valuable than new fleets because older rigs receive lower dayrates and utilization, and have fewer remaining years to generate earnings. To illustrate the relation, rigs in the 2010 world fleet were grouped into old (pre-1986 construction) and new (post-1986)Footnote 2 classes and the average dayrates each rig received during the year were computed by region (Table 3). Older rigs received lower average dayrates than newer rigs in every regional market with a premium of 88 % in the jackup market, 71 % in the drillship market, and 25 % in the semi market. Newer rigs were also more heavily utilized than older rigs, and companies with older fleets stacked their rigs a greater percentage of time (Fig. 8). Hercules and Diamond have particularly old fleets, whereas Seadrill has a younger fleet than the other large-cap firms, and these differences are likely to contribute to differences in market valuation vis a vis revenue generation potential.
Floaters generate larger net revenue than jackups in most regional markets and time periods, and drillers specialized in the floater market may have higher valuations than jackup contractors. Performance data for Diamond and Transocean are summarized by market segment in 2011 (Table 4). For Transocean, ultra-deepwater and harsh-environment floaters were highly profitable due to high utilization and market conditions that commanded premium dayrates. High-specification shallow water jackups were the only market segment with negative net revenue. Diamond’s deepwater fleet experienced higher dayrates than its ultra-deepwater fleet and was Diamond’s most lucrative business segment. Floaters were more profitable than jackups in every segment, although the net earnings in Transocean’s deepwater segment were relatively low due to low utilization and high-maintenance costs. Rigs in the midwater market generated approximately $40 million per rig for both firms, whereas the jackup segment was only marginally profitable. Deepwater expected net revenue varied widely, from $7 to 90 million (Transocean) to $40 to 100 million per rig (Diamond).
Contractors diversify within a rig class by operating both high- and low-specification units (Fig. 9). In 2011, Transocean, Noble, Ensco, and Diamond were the only contractors to own units in every rig class. By contrast, all of Seadrill’s units are high specification, and nearly all of Hercules’ units are standard jackups. In most market conditions, high-specification rigs receive a dayrate premium, but high-specification rigs are also more expensive to operate, and may or may not be associated with higher net earnings. For example, for Transocean, high-specification jackups were not associated with a net earnings premium relative to standard jackups in 2011, while high-specification floaters had greater earnings than standard floaters.
Contractors position assets to capitalize on imbalances in supply and demand and achieve administrative cost reductions through economies of scale while building customer and governmental relationships (Corts 2008; Lee and Jablonowski 2010; Mascarenhas 1989). High concentration of rigs in a few countries also subjects firms to increased political, regulatory and financial risk. Following the Macondo blowout in the Gulf of Mexico, for example, the US government imposed a deepwater drilling moratorium which negatively impacted firms operating in the region. Firms with a high degree of concentration in the US GOM in 2010–2011 were disproportionately impacted by the moratorium.
Drilling contractors involved in international operations are subject to additional risks not generally associated with domestic operations, such as terrorist acts; war and civil disturbance; expropriation or nationalization of assets; renegotiation or nullification of contracts; changes in law or interpretation of existing law; assaults on property or personnel; foreign and domestic monetary policies; and travel limitations or operational problems caused by public health threats. There is a tradeoff between fleet diversity and market position, and firms balance the desire for a strong market position in some regions and markets against geographic and market diversity (Speer et al. 2009). Firms with larger fleets are more geographically diverse than firms with smaller fleets (Fig. 10), and as the number of countries in which a company operates increases, the proportion of total revenue from the four largest regions generally declines (Fig. 11).
Large firms are capable of balancing market position and diversity, while smaller firms are limited in the number of regions in which they can successfully compete (Table 5). Diamond Offshore was particularly dependent on the Brazilian market in 2011, and more than half of Hercules revenue were generated in the US GOM. Hercules and Rowan had the most concentrated geographic base while Noble and Transocean had the most geographically diverse revenue base. Firms that consistently rely on competitive or declining regions may be undervalued relative to their peers. Hercules, for example, has historically been concentrated in the US GOM shallow water region, a declining market with low dayrates and utilization, whereas Seadrill has established itself as a significant presence in Brazil’s deepwater region, a growing market with high utilization and limited competition.
Contract backlog is the value of a firm’s existing contract commitments at the time of evaluation. Backlog includes the contracts rigs are currently working under as well as any future contracts and is calculated as the contract dayrate multiplied by the remaining contract duration for all rigs in a company’s fleet. High backlogs are associated with stable revenues in the near to midterm which reduces risk for investors and may increase firm value.
Contractors that derive the majority of their revenue from a small number of E&P firms can create risk because the loss of a single client may eliminate a major source of revenue. Transocean is particularly diverse and its largest customer in 2011 only accounted for 10 % of revenue. Atwood, Diamond, Hercules, Noble, and Rowan’s major customer contributed between 25 and 35 % of 2011 revenue and two customers comprised over half of total revenues for Atwood, Diamond, and Rowan. All else equal, firms with a diverse customer base are expected to be more valuable than firms with a limited customer base, but it is unlikely the market differentiates valuations according to customer concentration levels.
Net revenue associated with operating a rig is determined from the contract dayrate less the daily operating costs. Generally speaking, deepwater, high-specification, international rigs cost more to operate than shallow water, low-specification, domestic rigs (Table 6). Rig size and age, port infrastructure, scale economies related to a contractor’s regional presence, market competition, and the availability of goods and services also impact operating cost. Firms with newer fleets, efficient logistic networks, and good management control tend to have lower operating cost than their competitors, which translates into higher net revenue and stronger valuations.
Operating margin is the ratio of operating income to revenue and is an aggregate measure of the cost structure of the firm. Firms with higher operating margins have larger net earnings per dollar of revenue than firms with lower margins. Firms with older fleets or a large number of stacked rigs are expected to have lower operating margins than firms with younger or more active rigs.
Rig construction is capital intensive and fleet additions are financed through a combination of debt and equity. The use of debt to finance growth increases the risk of default and may lead to variation in earnings as firms service debt. However, the use of debt also allows a firm to leverage its equity, potentially increasing the yield to investors.