On the Coterra Energy Second Quarter 2023 Earnings Call, Dan Guffey welcomed everyone and gave an overview of the call. Tom Jorden and Shane Young gave prepared remarks and then took questions. The company had an excellent quarter due to production beats on oil, natural gas, and natural gas liquids, which was driven by well productivity that exceeded expectations in the Marcellus, Anadarko, and Permian regions.

Coterra is dedicated to achieving excellent results and sustainable asset performance, which is made possible by the hard work and passion of their field staff. They plan to maintain consistent profitable growth through 2024, with a 10-15% reduction in some big ticket items and a net 5% reduction in total well costs. They have top-tier assets, a pristine balance sheet, and few contractual service commitments, allowing them to generate consistent profitable growth with discipline and courage.

Coterra has adopted an "as-steady-as-she-goes" approach to program design and execution, which includes stress testing opportunities at draconian low commodity prices in order to ensure reasonable returns. The company's 2024 plans will be based on range-bound assumptions of future commodity pricing, and they will focus on selecting the best returns and ensuring flexibility to pivot if conditions change. Coterra's goal is to achieve consistent annual progress, and they are committed to investing for results that can withstand commodity swings.

Tom welcomes Shane to the Coterra team, and bids farewell to Scott Schroeder who is retiring after a successful career with Cabot and Coterra. He expresses his gratitude for Scott's work and emphasizes that Shane will be a key player in the team for many years to come. Tom also mentions that the company has options and flexibility when it comes to capital allocation and activity outlook. He then passes the call to Shane who will discuss the second quarter 2023 results, shareholder return program, activity outlook, and guidance for the third quarter and full year.

Coterra experienced a strong quarter of production, with all 3 streams exceeding expectations. Despite a 30% quarter-over-quarter decline in commodity prices, Coterra reported net income of $209 million and discretionary cash flow of $705 million. Capital expenditures totaled $537 million and free cash flow was $113 million. Coterra also announced a $0.20 per share base dividend and repurchased 2.4 million shares for $57 million.

Coterra has returned $628 million to shareholders so far this year, and is committing to returning at least 50% of their free cash flow for the year. They are estimating their 2023 accrued capital to be between $2 billion and $2.2 billion, and are expecting a 5% decrease in 2024 dollar per foot costs compared to 2023. Additionally, they are increasing their oil, natural gas, and BOE guidance by 3%, 2%, and 2% respectively.

This paragraph discusses the company's estimated production for the third quarter, its 3-year outlook, and its business unit updates. Specifically, it states that production is estimated to average 640 MBoe per day, natural gas to average 2.8 Bcf per day and oil to average 89.5 Mbo per day. The 3-year outlook expects the company's oil CAGR to be greater than 5%, and the 2023 discretionary and free cash flow guidance is lower than previously forecasted. Lastly, the Marcellus well performance increased 9% sequentially, and activity has been dropped to 2 rigs and 1 crew, which could lead to a decrease in Marcellus capital by at least $200 million per year.

Coterra is performing well, despite commodity headwinds in the second quarter, due to strong operational execution leading to production beats and the need to raise their annual production guidance range. They are running 6 rigs and 3 frac crews in the Permian and 1 rig in the Anadarko, and cash costs have gone down from $8.90 to $8.27 per BOE. Deferred taxes are expected to range between 10% and 20% of income tax expense in 2023. The company is well-positioned to meet or exceed their 2023 and 2025 targets, and Scott Schroeder was congratulated for his 28-year career at Cabot and Coterra.

Nitin Kumar asked Thomas Jorden and Shannon Young to explain the guide for the third quarter, which was driven by project timing and improved productivity. They discussed the mid-[indiscernible] wells, the Red Hills asset in New Mexico, and the 3-mile project in Reeves County. Nitin then asked about how they will balance maintaining cash and countercyclical buybacks. Shannon Young answered that they will take into account the $840 million in cash they had at the end of the quarter.

Thomas Jorden and Arun Jayaram discussed the potential to drive annual oil growth above 5%, which was 5% below before that. The change is being driven by well productivity, and there is no assumption of reallocation in the 3-year plan. Thomas Jorden stated that he would not say there is a better than 50% chance that they will decide to reallocate the $200 million from the Marcellus to their other oil plays. Scott is also retiring, and congratulations were given to him.

Blake Sirgo and Thomas Jorden discussed the cost deflation point and how their cost structure is and is not moving throughout '23. They have seen some deflation in rigs, OCTG, frac sand, but not in labor and fuel, which is a smaller part of their cost structure. They are assuming that the leading-edge indicators on those services maintain for a full year in order to realize the 5% cost savings. Thomas Jorden also discussed how they plan to drill more productive wells and achieve increasing operational efficiencies in order to maintain a consistent operational program.

Coterra is undertaking a 51-well project in the Permian which is expected to be highly productive. The company is disciplined in their approach to commodity prices and do not chase the strip, but instead focus on consistency. Doug Leggate of Bank of America asked if there was something going on with the Permian production mix, which has decreased from 35-36% natural gas yield to 31% in the first quarter. Thomas Jorden responded that they were not aware of any overprinting.

Investors have congratulated Scott and Shane on their performance. Michael Scala asked if any investors were telling them not to grow oil more than 5% in the next few years. Shannon Young answered that they currently have two rigs and one crew running in the Marcellus and if they keep that level of activity, their annual capital will be $200 million lower in the Marcellus area, which would keep production flat.

Thomas Jorden and Blake Sirgo discuss the potential savings that the Culberson row 51-well project will bring, such as taking advantage of infrastructure, operational efficiencies, electrification, and minimizing parent-child interference. They also explain that the project consists of 6 distinct drill spacing units that will be prosecuted in one consistent row without changes to the well per section or completion design.

Thomas Jorden explains that when it comes to OFS costs, it is important to consider spot versus long-term contracts. He states that it depends on the particular item and what is meant by long-term contract. He also explains that they typically avoid long-term commitments as it limits their flexibility. However, they may look at a downside commodity case and lock in a portion of it if they know for sure that they will have a certain amount of rigs running.

Thomas Jorden discusses the Wolfcamp in Culberson County in South Central Texas, which has a mixture of sand and shale landing zones. He explains that they have changed their thinking on how to best exploit these different landing zones, which has contributed to better-than-expected well productivity in the second quarter.

Coterra is continuously innovating in its drilling and completion techniques, using machine learning to help optimize their projects. They are constantly debating well spacing and frac design, and this year they are testing in the Bone Spring to help optimize their projects over the next 3 years. However, this testing will not change their capital allocation.

Thomas Jorden and Blake Sirgo discussed the opportunities for increasing productivity across their various assets. They are pleased with their Anadarko Basin flowback, and their Marcellus team has done a good job optimizing their delineation and slide deck updates. In the Permian, they are focusing on larger developments that take advantage of project size, and they have seen an increase in the average wells per project over the last two years. They are also seeing an increase in their drilling and completion fees per day.

Blake Sirgo and Roger Read are discussing the CapEx for '23 and '24, and how the deflation of certain services has not materialized as expected. Blake Sirgo states that if the deflation had gone through the entire cost structure, they would be at the low end of the range. Kevin MacCurdy then inquires about the trajectory of OpEx for the year, noting that the first two quarters were at the higher end of guidance, and that the second half of the year would need to be at the lower end of the range.

Blake Sirgo and Shannon Young discussed how their LOE is down quarter-over-quarter and their cash costs are down from $8.90 a BOE last quarter to $8.27 BOE this quarter, respectively. Thomas Jorden then discussed their experience with 3-mile laterals, noting that they don't have broad experience in any one area, but that the well in Reeves County surprised them with an upside.

Thomas Jorden praised the operational team for their work in the Marcellus region, citing their management of parent-child effects, well spacing, and completion design as contributing to the 9% production growth in the second quarter. He also mentioned their success in revising their forecasting methodology and their projects in the lower and upper Marcellus. Leo Mariani then asked about their CapEx, with Thomas Jorden replying that they will likely be a couple of percent over the midpoint in '23.

Shannon Young answered Paul Cheng's question about 3-mile wells and larger pad development in the Permian Basin. Young stated that the guidance range for accrued CapEx in 2023 is $2 billion to $2.2 billion, with a trend of 1-2% above the midpoint. They are letting go of spot crews in the Permian and Anadarko, leading to lower accrued CapEx in the fourth quarter. Young also mentioned that they will benefit from 3-mile wells in the second quarter and that their Permian portfolio has the opportunity to have 3-mile wells, with an increase in larger pad development.

Thomas Jorden discussed the risk-reward of infrastructure investment, noting that the 3-mile wells will be a small part of the program, but that the 51-well project will give them the opportunity to test a lot of things and have good offset control. He believes they are ready for a project of this size and hope to deliver outstanding results.

Blake Sirgo discussed the impact of LNG on gas prices in the Permian and Marcellus basins. He noted that Waha has opened up this year due to expansions and forecast revisions, and there are options for getting Permian gas to LNG, though none have been found to work yet. Regarding vendor behavior, he noted that it is fairly uniform, with rigs and crews moving to other basins if the arbitrage is big enough.

Scott Schroeder thanked everyone for their support and trust in Coterra over the past two years. He expressed his pride in the company and his confidence that it is in great hands with Shane and the team. He concluded the conference call by thanking everyone for their participation and wishing them well.

This summary was generated with AI and may contain some inaccuracies.