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Coterra's Early Shift to Electrified Field Operations Offers Partial Inflation Shield Coterra's Early Shift to Electrified Field Operations Offers Partial Inflation Shield Dave Meats Director Analyst Note | by Dave Meats Updated Aug 03, 2022 Coterra's delivered 632 mboe/d in the second quarter, exceeding guidance. Management attributed the result to several factors, including better-than-expected well performance and accelerated completion activity (which have positive read for future periods) and a surprise uptick in partner production (which is beyond management's control). A very constructive commodity environment also bolstered revenues, and while inflationary pressure nudged up operating costs as well as it has for most E&Ps, the increase was fairly modest. This at least partly reflects the firm's rapid adoption of electrified field operations, especially in the Permian (where two-thirds of the firm's 2022 wells will be drilled by rigs running on grid power). This reduces Coterra's exposure to soaring fuel costs, which are a major input for upstream companies, along with steel and labor. Accordingly, the firm was able to differentiate itself from the group by leaving operating expense guidance intact. However, the firm was unable to avoid lifting the full-year capital budget, although part of the $200 million increase was driven by incremental activity, supporting higher volumes in 2022 and 2023. Volume guidance was increased by about 1% at the midpoint (the high end was unchanged). After incorporating these results, our fair value remains at $32. That's about 10% ahead of the current market price, which is notable because after this year's commodity-driven rally we think the majority of upstream firms are overvalued. The stock trades with an implied midcycle free cash flow yield of 7%-9%, which is at the high end of the range for our upstream coverage. As the firm is committed to returning at least 50% of its free cash to shareholders that suggests a durable yield of about 4% at the midpoint. Nevertheless, our 3-star rating implies the stock is fairly valued on an uncertainty-adjusted basis, which means we'd need to see a higher margin of safety before getting positive on it. Business Strategy and Outlook | by Dave Meats Updated Aug 03, 2022 Coterra Energy was formed after the 2021 merger of equals between Cabot Oil & Gas and Cimarex Energy. The combined business produces oil and natural gas in three U.S. regions. Natural gas is the primary target in the Marcellus Shale (Pennsylvania), where Cabot was focused. But the firm's legacy Cimarex assets, in the Permian Basin (Texas and New Mexico), and Anadarko Basin (Oklahoma) are more oil-weighted. Management believes the combined business will be stronger because of geographic diversificaton and overhead synergies. Coterra's Marcellus assets are ideally located in the northeast portion of the play fairway, which mainly yields dry gas with very little condensate or natural gas liquids content in the production stream (so there's no need to pay for cryogenic processing to separate these products). Wells in this part of the field are typically characterized by very high daily production rates, which also enhances returns. This puts the firm at the low end of the U.S. cost curve for natural gas, but there's a catch: the firm's acreage doesn't have too many lucrative Lower Marcellus drilling opportunities left. So management is starting to layer in wells targeting the overlying Upper Marcellus layer, which are typically up to 30% less productive. But the firm will be able to reuse existing roads and pad sites, and as there are no well configuration constraints in this undeveloped interval, it can enhance returns by drilling longer laterals. As a result, we expect well costs to decrease enough to offset the dip in flow rates, leaving potential returns unchanged. In any case, the firm has abundant inventory in the liquids-rich part of the portfolio. Activity is concentrated in the Delaware Basin, within the Permian. The firm holds over 200,000 net acres, which is prospective for the Wolfcamp, Bone Spring, and Avalon reservoir targets. Management is attempting to maximize capital efficiency with larger pad sizes and longer laterals. This includes a 14-well project with 3-mile horizontal sections, located in Culberson County. The firm will also begin utilizing electric completion spreads in 2022, lowering its own fuel consumption and improving well costs. Economic Moat | by Dave Meats Updated Aug 03, 2022 Coterra is one of the few exploration and production companies to earn a narrow moat rating. The ability to deliver maintainable excess returns on invested capital is a hallmark of moaty companies, and the firm is expected to earn its cost of capital for at least the next 10 years. The recent merger with Cimarex slightly diluted our ROIC projections, but we still expect the firm to earn its cost of capital through our 10-year forecast. Coterra's acreage in the Marcellus Shale is characterized by low operating and development costs, putting it at the lower end of the U.S. natural gas cost curve. The main factor that differentiates the northeast portion of the Marcellus, where Coterra operates, is the lack of oil condensate or natural gas liquids. The production stream consists entirely of dry natural gas, with no liquids content at all. Because natural gas flows more easily out of a reservoir than liquid does, these wells are typically characterized by very high initial production rates and projected recoveries. So Coterra's costs are spread more thinly, pushing up its margins and returns. And because there are no NGLs, the firm doesn't need to pay for cryogenic processing fees (saving it around $0.20/mcf). Playing devil's advocate, we would highlight that the firm's Marcellus acreage only contains a few more years' worth of Lower Marcellus drilling opportunities. As a result, the firm is pivoting to the less productive Upper Marcellus, and those wells do not typically perform at the same stellar level that Lower Marcellus wells do. The good news is that well costs in the Upper Marcellus are expected to be commensurately lower, keeping returns at around the same level. There are two reasons for that: (1) Surface facilities (pad sites, roads, and so on) were already paid for during the Lower Marcellus development and can probably be reused, and (2) there are no constraints on the length of the horizontal portion in the Upper Marcellus, as it is basically "dry powder" with very few pre-existing wells to get in the way, so it can be developed with more profitable longer laterals. So, we would not expect a step-change in profitability when the firm's Lower Marcellus inventory is exhausted. Further, though the firm does have exposure to potential environmental, social, and governance, or ESG, issues that could threaten its moat, we believe there is enough of a spread between projected returns and the firm's cost of capital to provide a comfortable margin of safety. For Coterra, the most significant ESG exposures are greenhouse gas emissions (both from extraction operations and downstream consumption), and other emissions, effluents, and waste (primarily oil spills). Greenhouse gas emissions are unavoidable for oil and natural producers. Firms can clean up their operations in the field as much as possible by avoiding unnecessary flaring and using technologies like electric fracking and carbon capture to reduce CO2 volumes being released into the atmosphere during the extraction process. But because downstream emissions are beyond producers' control, there's really no such thing as a "clean" E&P company. As consumers get more averse to fossil fuels, the reputational risk grows for producers and the probability of widespread substitution away from fossil fuels increases. This also makes value-destructive regulatory intervention more likely (think fracking restrictions or carbon taxes). These threats are not likely enough to be included in our base-case forecasts, but the impact is potentially material. In contrast, spills are not a major concern for firms operating exclusively onshore, as Coterra does. There is no chance of a devastating accident like the BP Macondo disaster in 2010. Nor would the firm be on the hook for adverse events during long-haul transit, like the Kalamazoo River (Michigan) spill, which also occurred in 2010. This activity is typically outsourced to midstream firms that operate regional pipelines. Instead, Coterra is more vulnerable to spills at or around the wellsite. These tend to be frequent but relatively minor. Costly legal challenges are unlikely for this kind of event and we see little chance of significant value destruction. Fair Value and Profit Drivers | by Dave Meats Updated Aug 03, 2022 Our primary valuation tool is our net asset value forecast. This bottom-up model projects cash flows from future drilling on a single-well basis and aggregates across the company's inventory, discounting at the corporate weighted average cost of capital. Cash flows from current (base) production are included with a hyperbolic decline rate assumption. Our valuation also includes the mark-to-market present value of the company’s hedging program. We assume oil (West Texas Intermediate) prices in 2022 and 2023 will average $99 and $85 a barrel, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $7.20 per thousand cubic feet and $5.90/mcf. Terminal prices are defined by our long-term midcycle price estimates (currently $60/bbl Brent, $55/bbl WTI, and $3.30/mcf natural gas). Based on this methodology, our fair value estimate is $32 per share. This corresponds to enterprise value/EBITDA multiples of 4.2 times and 5.0 times for 2022 and 2023, respectively. Our production forecast for 2022 is about 632 mboe/d. That drives 2022 EBITDA to about $7.6 billion, and we expect cash flow per share to reach $7.66 in the same period. Our 2023 estimates for production, EBITDA, and cash flow per share are approximately 691 mboe/d, $7 billion, and $7.35, respectively. Risk and Uncertainty | by Dave Meats Updated Aug 03, 2022 A deteriorating outlook for natural gas prices would pressure the firm’s profitability, reduce cash flows, and drive up financial leverage. An increase to federal taxes, or a revocation of the intangible drilling deduction that U.S. firms enjoy, could also impact profitability and reduce our fair value estimates. Material ESG exposures create additional risk for E&P investors. In this industry, greenhouse gas emissions are the most significant concern (both from extraction operations and downstream consumption), and other emissions, effluents, and waste (primarily oil spills). In additional to the reputational threat, these issues could force climate-conscious consumers away from fossil fuels in greater numbers, resulting in long-term demand erosion. Climate concerns could also trigger regulatory interventions, such as fracking bans, drilling permit suspensions, and perhaps even direct taxes on carbon emissions. The recent merger with Cimarex increased the firm's exposure slightly as the combined firm has a footprint in the New Mexico portion of the Delaware Basin. This is federal, rather than private, land and therefore falls under the direct purview of the executive branch for regulation. President Joe Biden has suggested banning new permits for oil and gas drilling on federal land. Given the volatility of global oil and natural gas markets, we assign a high uncertainty rating for Coterra. Capital Allocation | by Dave Meats Updated May 13, 2022 Coterra's CEO is Tom Jorden, who served in the same capacity at Cimarex. The leadership team comprises executives from both companies, and the board is composed of five directors from each company. Our Standard capital allocation rating reflects Coterra's relatively strong balance sheet, appropriate distributions, and fair investment strategy. The firm prioritizes low-cost drilling opportunities in the dry natural gas window of the Marcellus Shale in northeast Pennsylvania, and has similarly cost-advantaged oil-weighted assets in the Permian Basin. The Cabot-Cimarex merger was sensibly structured as a zero-premium all-stock deal, leaving the balance sheet of the combined firm in relatively good shape. However, by using Cabot's own stock--which we thought was undervalued at the time--as currency, the firm was effectively paying over the odds. Nevertheless, since incorporating the assets had little impact on our DCF-derived fair value estimate, we conclude that Cimarex itself was probably undervalued at the time of the merger as well (consistent with our views on other Permian producers). Coterra was among the first wave of E&P firms to establish a fixed-plus-variable dividend strategy to enable it to rightsize distributions through the commodity cycle, and has committed to paying out 50% of free cash flows. We generally look favorably on such strategies, as they limit the cash that can be ploughed back into new drilling and limit the emphasis on production growth. Coterra is also planning for over $1 billion of buybacks in 2022, which is something to keep an eye on as commodity prices are generally indicative of a top-of-cycle environment. That said, we still consider Coterra's stock to be slightly undervalued, making the buyback program theoretically accretive to net asset value. |
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