Callon Petroleum Company

Stand by, we're about to begin. Ladies and gentlemen, thank you for standing by and welcome to the Cal and Petroleum second quarter 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question at that time, simply press star 1 on your telephone keypad. And please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Mr. Kevin Smith, Director of Investor Relations. Please go ahead, sir.

Thank you, Bo. Good morning. Thank you for taking the time to join our conference call. With me on today's call are Joe Gatto, President and Chief Executive Officer, Dr. Jeff Palmer, SVP and Chief Operating Officer, and Kevin Haggard, SVP and Chief Financial Officer. During our prepared remarks, we may reference the earnings results presentation and our second quarter earnings press release. both of which are available on our website. So I encourage everyone to download both documents if you have not done so already. You can find the slides on our events and presentations page and the press list under the news heading, both of which are located within the investor section of our website at www.calend.com. Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers, and important disclosures included on slide two of the presentation. We will make some forward-looking statements today during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on that slide and in our periodic SEC bonds. We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the earnings presentation slide, and in our earnings press release, both of which are available on our website. Following our prepared remarks, we'll open the call for Q&A. And with that, I'd like to turn the call over to Joe Gatto. Joe?

Thanks, Kevin, and good morning to everyone on the call. As Kevin mentioned, please refer to the earnings presentation on our website as background for our commentary. I'll be highlighting a few pages in particular as a walkthrough introductory remarks. I'll start off by discussing our accomplishments for the first half of the year. As we enter 2022, we outline several goals, including maintaining momentum on strengthening our financial position, increasing capital efficiencies, and solidifying the foundation for sustainable free cash flow generation. Moreover, we emphasize progressing these goals while committing further reductions in our carbon footprint. Over the first six months of the year, we've paid down debt to $2.5 billion and reduced the company's leverage ratio to 1.67 times at quarter end. In addition, We took advantage of a window in the capital markets and refinanced senior notes with a 2024 maturity and removed the second lien notes from the company's capital structure. The end result of this timely transaction was an extension of our maturity profile and a reduction in our term debt balances. In parallel, our focus on the use of free cash flow for debt pay down this year has put us that much closer to achieving our near-term absolute debt target of $2 billion and a leverage ratio of one times which are key milestones in our return of capital strategy. Switching to operations, we've been focused on improving capital efficiencies, both from DNC activities and well productivity. In terms of the former, our average feet drilled per day has increased almost 50% since 2018 in the Delaware Basin, and profit tons pumped per day in completions have increased by approximately 160% on average across all basins. I also want to highlight substantial well productivity improvements being delivered with our Delaware Basin Development Program. Since initiating larger scale program development over the last couple years, we've acquired a significant amount of empirical production data from co-development to corroborate our subsurface modeling work. Based on this integrated data set, we've employed wider well spacing and begun to incorporate larger completion designs. These efforts have led to average wealth performance in 2022 that is almost 20% better than 2021 production, as you can see on page 10 of the earnings presentation materials. This is a critical catalyst for improving our capital efficiency and reducing our reinvestment rates in 2022 and beyond. I'll have one last operational item on the marketing front, where we continue to be proactive in our approach to moving hydrocarbons and capturing incremental economics. We announced in June the calendar had entered into multiple natural gas transportation agreements for firm transportation to the Gulf Coast for approximately 75,000 mm BTU per day, beginning in mid 2023. These transactions will increase our pricing exposure to Gulf Coast gas pricing and provide additional flow assurance benefits. Turning to EESG, we are steadily executing on our accelerated emissions reduction goals. We are well on our way to achieving our two-year plan to replace all of our pneumatic devices with zero-emission or no bleed devices, which will significantly reduce our overall emissions, particularly methane. Consistent with our track record of acquiring and proving assets, we've been investing this year in facility upgrades in our Delaware South operations to bring them in line with calendar standards and reduce flaring and other emissions. With these and other activities, we remain committed to our goal of reaching a 50% reduction in emissions intensity by 2024. You can read more about our progress and initiatives in our forthcoming sustainability report, which will be released in the coming weeks, so please be on the lookout for that. Now turning to our second quarter results. Operationally, this was a transitional quarter for us as we ramped up our completion activity and placed 33 gross wells on production, almost double the first quarter as we started developing our duck backlog that had increased pace early in the quarter. Headline production came in at the midpoint of our guidance at 101,000 barrels of oil equivalent per day, carrying an oil cut of 61% and total liquids content of 81%. Volumes for the quarter were relatively flat compared to the first quarter and were impacted by a couple of one-time items. We stepped up our workover activity as we accelerated the implementation of Calum's artificial lift program in the Delaware Basin, particularly in the Delaware South area, as we experienced higher levels of well downtime from power disruptions and typical equipment failures that occur after useful life is reached. In total, our level of workover activity was approximately twice the amount in the first quarter and pulled forward workovers for repairs and lift conversions forecasted for later in the year. While the conversion of wells to our artificial lift program does extend downtime relative to normal repairs this initiative has proven to be an important operational synergy that improves production rates and longer term run times as shown on page nine of the materials through the first half of 2022 we've seen an average sustained uplift of over 25 percent through the first 60 days of install which equates to very short payouts after factoring in near-term downtime required to perform the conversion or repair Importantly, it also extends run times and reliability for the longer term. In addition, we restructured one of our primary Midland Basin gathering contracts, changing the contract from a percentage of proceeds structure to a fee-based contract, which increased our natural gas and NGL volumes, resulting in a lower oil cut on a percentage basis. The impact of these items have been factored into our updated guidance for the remainder of the year. Given continued strong oil performance, particularly in the Delaware Basin, We are raising the bottom end of our annual production guidance from 101 to 102,000 BOE per day, with sequential growth expected over the next two quarters. We are also increasing our natural gas mix by 1% on an annual basis to incorporate the additional gas volumes realized from the gathering contract conversion. Our average wellhead pricing increased 15% to approximately $83 per BOE, a level we have not seen since 2014. The top line increase contributed to an eighth consecutive quarterly increase in cash margins, driving quarterly adjusted EBITDA to approximately $420 million on a hedge basis and over $600 million on a non-hedge basis. As our hedge portfolio steps down as percentage of production relative to the first half and associated hedge prices increase, our participation in a strong commodity price environment will improve in the back half of the year. We will also benefit from our ongoing exposure to international and MEH pricing, which represent approximately two-thirds of our oil volumes in 2022 on a combined basis. Beyond strong price realizations, controlling inflationary cost pressures is also critical to preserving our cash margins. While we have seen inflationary pressures from power and fuel on the LOE front and elevated workover costs in the second quarter from the ESP initiatives I discussed, Our guidance range for absolute LOE spent has remained unchanged. GP&T has revised up $5 million, reflective of the Midland Gathering contract conversion, which will increase our exposure to natural gas and NGL volumes, and a new contract that transfers operatorship and maintenance of a compressor station to a third-party operator, which we believe will improve operational efficiency. And finally, G&A expense has been squarely in line with initial expectations. Overall, we have managed our absolute dollar spend well in an inflationary environment, and our per unit metrics will benefit from second half production gains. As we turn to the second half outlook, completion activity will increase over the first half with approximately 40% more wells placed online in the second half. Our second half of 2022 drilling program will remain permanent focused with over 80% of the new wells coming from this area. In terms of mix, the Midland Basin will constitute a larger portion representing approximately 50% of our new wells in the second half of the year. We expect third quarter production volumes to increase to between 102 and 105 MBOE per day, as strong well performance and ongoing contributions from second quarter activity will be bolstered by increased activity in the third quarter with approximately 40 gross wells scheduled to come online. Our operational capital spending is forecasted to be between $245 and $255 million on an accrual basis which is slightly above our second quarter figure. As we've highlighted in the past, we have one of the deepest drilling inventories amongst our peers at over 1,700 locations, equating to roughly 15 years of drilling inventory. What is underappreciated by the market at times, however, are the implications of our life development philosophy, which focus on scale co-development to optimize the value of a large part of the reservoir system. The strategy captures multiple zones that deliver strong economics on both an individual well and project-level basis and minimizes parent-child relationships over time. As a result, we've maintained a more balanced inventory opportunity set for future development. On page 11 of the presentation, we've referenced a third-party independent analysis that illustrates that concept. The analysis created SHAF. or Shapley additive explanation values that are used to explain the relative contributions of a group of factors to the outcome of a predictive model. In this case, Shap values were developed for factors such as geology, well spacing, completion design, and well timing to provide the marginal impact of each on a three-year oil production target outcome. The specific geologic Shap values quantifies the marginal impact of rock quality on well performance. SHAP values were aggregated to create a distribution that characterizes a company's remaining inventory. The median of that distribution is then compared to the median of the SHAP value distribution for wells placed online in 2021 to infer comparability of rock quality for future drilling relative to 2021 rock quality drill. That analysis revealed that out of 16 operators in the Delaware Basin that were included in the study, 12 companies had a negative SHAP value. meaning the company's inventory quality is expected to decline relative to 2021 drilling over the next couple years. On the contrary, Callen had one of the highest positive values, reflecting Callen's inventory opportunity set is expected to improve in quality in the coming years as we execute our life of field development program. We've been consistent in our development approach over time, and we believe this will be an important differentiator in generating free cash flow on a sustained basis with a prospective inventory that has been developed in a more balanced manner. I will now turn the call over to Jeff to cover operations.