Phillips Johnston

Phillips Johnston asked about the average EUR per thousand foot assumed by Netherland, Sewell (after a correction from Lee Keeling) in the Western Haynesville and how it compares to the Legacy Haynesville. Phillips Johnston then followed up, asking about the implied next 12-month PDP decline rate in the year-end reserve report and how it compares to the decline rate in the year-end 2024 report.

Answer

Jay Allison, Chairman and CEO, clarified that Netherland, Sewell audits their reserves. He stated that Western Haynesville EURs generally range from 3-4 Bcf per 1,000 feet of lateral, with 3.5 Bcf being a good average. Ron Mills, VP of Finance and Investor Relations, stated that the next 12-month PDP decline rate has decreased slightly (1-2% from 40%), which is expected as the Western Haynesville contributes a greater percentage of production, and this decline rate will continue to improve over time.

Phillips Johnston asked about the average Estimated Ultimate Recovery (EUR) per thousand feet assumed by Netherland, Sewell for the Western Haynesville in the year-end reserve report, and how this compares to the legacy Haynesville. He also inquired about the implied next 12-month PDP decline rate in the report and its comparison to the year-end 2024 report.

Answer

Chairman and CEO Jay Allison (correcting the auditor reference) and President and CFO Roland Burns stated that Western Haynesville EURs generally range from 3-4 Bcf per 1,000 feet of lateral, with 3.5 Bcf being a good average. VP of Finance and Investor Relations Ron Mills noted that the implied next 12-month PDP decline rate has slightly decreased by 1-2% from 40%, attributing this to a growing percentage of Western Haynesville production, which will improve the first-year PDP decline over time.

Phillips Johnston from Capital One Securities, Inc. followed up on the non-core asset sale, asking about the potential proceeds and tax implications. He also questioned how CapEx could remain flat in the second half of the year despite an increased rig count and well plan.

Answer

President & CFO Roland Burns declined to specify proceeds but stated they hope to provide an update next quarter and do not expect significant tax leakage. Regarding CapEx, COO Daniel Harrison explained that D&C costs are down approximately 10% due to lower pipe and vendor pricing. Roland Burns added that the cadence of completion activity, a major cost driver, is expected to be slightly lower in the second half of the year, offsetting the higher drilling activity.

Phillips Johnston from Capital One Securities, Inc. asked for the potential magnitude of proceeds from the non-core asset sale and any associated tax leakage. He also questioned why CapEx guidance for the second half of the year is relatively flat despite an increased rig count and well plan.

Answer

President & CFO Roland Burns and CEO M. Jay Allison declined to provide a figure for potential proceeds, indicating more information would be available next quarter, but stated they do not expect significant tax leakage. Regarding the flat CapEx, COO Daniel Harrison attributed it to D&C costs being down approximately 10% due to lower pipe and vendor prices. Roland Burns added that the cadence of completion activity, a major cost driver, is expected to be slightly lower in the second half of the year.

Phillips Johnston from Capital One Securities, Inc. followed up on the non-core asset sale, asking about potential proceeds and tax implications. He also questioned why CapEx guidance remains flat for the second half of the year despite an increased rig count and well drilling plan.

Answer

President/CFO Roland Burns declined to specify proceeds but stated they expect no significant tax leakage. Regarding CapEx, COO Daniel Harrison explained that D&C costs are down approximately 10% due to lower pipe and vendor costs. Roland Burns added that the cadence of completions, a major cost driver, is expected to be slightly lower in the second half of the year, helping to keep spending flat.

Phillips Johnston from Capital One Securities, Inc. followed up on the non-core asset sale, asking about the potential proceeds and tax implications. He also questioned why CapEx guidance is flat for the second half of the year despite a higher rig count.

Answer

President and CFO Roland Burns declined to specify the potential proceeds but stated they hope to provide an update next quarter and do not anticipate significant tax leakage. Regarding capital spending, COO Daniel Harrison explained that D&C costs are down approximately 10% due to lower pipe and vendor costs, which offsets the higher activity. President and CFO Roland Burns added that the cadence of completions, a major cost driver, is expected to be slightly lower in the second half of the year.

Phillips Johnston from Capital One Securities, Inc. followed up on the non-core asset sale, asking about the potential magnitude of proceeds and any expected tax leakage. He also questioned how the CapEx guidance for the second half of the year remains flat despite an increased rig count and well drilling plan.

Answer

President and CFO Roland Burns declined to specify proceeds for the asset sale but noted an update is expected next quarter and that no significant tax liability is anticipated. Regarding CapEx, COO Daniel Harrison explained that D&C costs are down approximately 10% due to lower service and pipe costs. Roland Burns added that the cadence of completions, with potentially less activity in the second half, also helps maintain a flat budget despite the additional rig.

Phillips Johnston asked for clarification on the quarterly turn-in-line (TIL) cadence and the company's confidence in the significant second-half production ramp-up implied by guidance. He also asked if Comstock expects to fund any capital outlays for the BKV carbon capture agreement.

Answer

President and CFO Roland Burns explained the production ramp is a function of both the number and timing of TILs, noting that Q2 TILs are weighted toward the second half of the quarter, leading to sequential production growth in Q3 and Q4. Regarding the BKV agreement, Burns confirmed Comstock does not expect any significant capital investment; BKV will fund the outlays and get the tax credits, while Comstock will sell its CO2, resulting in a net reduction to operating costs.

Phillips Johnston asked for the assumed average working interest for the 2026 drilling program in Giddings and Karnes, and the company-wide cycle times (gross wells per rig per year). He also sought clarification on the impact of deferred 2025 well completions on the 2026 drill count.

Answer

Brian Corales, Senior Vice President and Chief Financial Officer, stated that Giddings working interest is now in the low 80s, up from the mid-70s, and that 28 gross wells per rig per year is a slightly aggressive but close estimate. Chris Stavros, Chairman, President, and CEO, confirmed that the 2026 drill count would be in the ballpark of the 6 deferred wells from 2025, without necessarily operating with a higher DUC inventory.

Phillips Johnston asked for the assumed average working interest for Magnolia's 2026 drilling program in Giddings and Karnes, and the company-wide cycle times in terms of gross wells per rig per year. He also sought clarification on the impact of six deferred well completions from 2025 on the 2026 drill count.

Answer

Brian Corales, Senior Vice President and Chief Financial Officer, estimated the average working interest in Giddings to be in the low 80s, an increase from the mid-70s. He noted that cycle times around 28 gross wells per rig per year might be slightly aggressive but are not far off. Chris Stavros, Chairman, President, and Chief Executive Officer, confirmed that the six deferred wells from 2025 are in the ballpark for inclusion in the 2026 program.

Phillips Johnston asked for directional guidance on where unit LOE (Lease Operating Expense) and GP&T (Gathering, Processing & Transportation) costs might trend in 2025 relative to the second half of 2024 exit rate. He also questioned if the $15 million in small Q3 deals included any significant production.

Answer

President and CEO Christopher Stavros stated that while they always aim for improvement, maintaining the current reduced LOE levels would be a fair expectation for 2025, with potential for modest gains. He noted this positions the company well against price volatility. Stavros also confirmed that the $15 million in Q3 acquisitions did not include any production of consequence, as they were primarily for incremental working and mineral interests.

Phillips Johnston of Capital One Securities, Inc. inquired about the drivers behind the projected increase in oil mix for the second half of the year. He also asked about the board's comfort level with increasing net debt to fund acquisitions beyond 2025 and sought clarification on the structure of the operator partnerships, specifically regarding earn-outs.

Answer

Tyler Farquharson, President and CEO, clarified that the oil mix is expected to be around 52%, driven by new, oilier production from the Permian Basin. He stated that the company is comfortable with leverage in the 1.0x to 1.25x range and will continue to outspend cash flow to add inventory in the current attractive market. Regarding partnerships, he explained they feature a back-end interest reversion to the operator teams after a return hurdle is met, with no upfront promotes.

Phillips Johnston of Capital One Securities, Inc. inquired about the drivers for the increased oil mix in the second half of the year, the company's appetite for increasing net debt beyond 2025, and the structure of its operator partnerships, specifically regarding earn-outs or working interest reductions.

Answer

President and CEO Tyler Farquharson clarified that the oil mix would be around 52%, driven by new, oilier Permian projects. He affirmed the company's comfort with a leverage ratio of 1.0x to 1.25x and its strategy to outspend cash flow to acquire inventory in the current market. Regarding partnerships, Farquharson explained that there is no upfront promote, but a portion of the interest reverts to the operator partners after a specific return hurdle is achieved.

Phillips Johnston of Capital One Securities inquired about the drivers for the projected second-half oil mix increase, the company's tolerance for higher net debt to fund acquisitions, and the structure of its operator partnership agreements regarding earn-outs.

Answer

President and CEO Tyler Farquharson clarified that the oil mix would be around 52%, driven by new, oilier Permian projects. He affirmed the company's comfort with leverage up to 1.25x to capitalize on the current acquisition environment, suggesting outspending cash flow could continue into 2026. He also explained that partnership structures include a back-end interest reversion to partners after a return hurdle is met, with no upfront promote.

Phillips Johnston inquired about the production contribution from Q1 2025 acquisitions, the timing of their closing, and sought confirmation on the full-year guidance for lease operating expenses (LOE).

Answer

Luke Brandenberg, President and CEO, stated that a key Delaware Basin acquisition is expected to contribute about 450 barrels per day for 2025, with minimal impact in Q1 due to its late-quarter closing. Tyler Farquharson, CFO, confirmed that the company expects full-year LOE to be at the low end of its guidance range, driven by increasing scale from its operating partnerships.

Phillips Johnston of Capital One sought clarity on the production trajectory, asking about the magnitude of the expected Q1 2025 production increase and whether the guided mid-teens growth for 2025 applies to total Boe or specifically to oil. He also inquired about the year-end Proved Developed Producing (PDP) decline rate.

Answer

Executive Luke Brandenberg projected a significant Q1 production jump due to 2024 capital spending on wells turning to sales in early 2025. He specified that full-year 2025 growth is expected to be in the mid-teens on a Boe basis, driven primarily by oil. He also stated the current PDP decline rate is around 40%, up slightly from the high-30s a year ago due to higher working interest wells.

Phillips Johnston sought clarification on the production cadence for the remainder of the year, particularly the magnitude of the expected Q3 decline, and asked what a 'maintenance mode' in 2026 would imply for oil volume targets.

Answer

CEO Nicholas O’Grady clarified that Q3 volumes would see a 'modest dip,' likely in the mid-single digits, before rebounding in Q4 to levels similar to Q2. He also stated that a 2026 maintenance scenario would aim to hold production flat against the full-year 2025 average, not the lower second-half levels.

Phillips Johnston questioned what NOG's maintenance capital expenditure would be for 2026 and 2027 if spending falls to the low end of the 2025 range. He also asked if Q1's favorable production taxes and gas price realizations would normalize back toward full-year guidance.

Answer

CTO Jim Evans projected that maintenance CapEx for 2026-2027 would remain around the current level of approximately $850 million, assuming no significant change in drilling costs. CFO Chad Allen confirmed that both production taxes and gas price realizations are expected to trend back into the guided range for the full year, explaining that production taxes will likely rise as the higher-tax Permian basin constitutes a larger portion of the production mix.

Phillips Johnston asked if the delay in six XCL wells would materially impact Q4 production and questioned the company's comfort level with the implied Q4 production ramp.

Answer

An executive, likely President Adam Dirlam or CEO Nicholas O'Grady, confirmed the XCL delay would not have a material impact due to the company's diversified asset base and outperformance elsewhere, such as from the Point acquisition. CEO Nicholas O'Grady stated that achieving the high end of the Q4 production guidance is possible but depends heavily on the timing of well completions, which is out of their control.

Phillips Johnston inquired whether the company would consider M&A in Canada and asked for an update on D&C well costs per foot in its three operating areas, given the new drilling speeds.

Answer

President, Director & CEO Domenic Dell’Osso said that expanding to Canada is not in the company's near-term plans, as it's unclear if it would meet their 'non-negotiable' criteria. Executive VP & COO Josh Viets provided updated costs, noting Haynesville wells are now around $1,200/ft, Bossier wells are under $1,500/ft, and Appalachian wells are within 5% of previous guidance.

Phillips Johnston inquired if the company would consider Canada for M&A and asked for an update on D&C well costs in its operating areas following recent drilling efficiency gains.

Answer

CEO Domenic Dell’Osso said that while they monitor industry trends, Canadian M&A is not in their near-term plans as it is not clear it would meet their strategic criteria. Executive VP & COO Josh Viets provided updated well costs, noting Haynesville costs are now around $1,200-$1,500 per foot, while Appalachian costs are within 5% of previous guidance as improvements there were already anticipated.

Phillips Johnston from Capital One Securities, Inc. inquired if Expand Energy would consider expanding its footprint into Canada. He also asked for an update on how much D&C well costs have fallen in their three main operating areas.

Answer

President, Director & CEO Domenic Dell’Osso indicated that expanding into Canada is not in their near-term plans. Executive VP & COO Josh Viets provided updated well costs, noting Haynesville costs are now around $1,200/foot, Bossier is just under $1,500/foot, and Appalachian costs are within 5% of the original guide.

Phillips Johnston asked for the rationale behind the implied lower capital spending rate in the fourth quarter guidance and the company's confidence in achieving that reduction.

Answer

President and CEO Brendan McCracken explained that the lower Q4 capital spend is entirely performance-driven. The company has reduced rig counts in the Permian and Montney and has significantly increased drilling and completion speeds, leading to a front-end loaded capital profile for the year.

Phillips Johnston of Capital One asked what specific price or circumstances would trigger a reduction in activity and also inquired about the company's outlook for the AECO gas market as LNG exports ramp up.

Answer

Executive Brendan McCracken stated that a decision to cut capital below maintenance levels would be considered if WTI prices dropped below $50 and were expected to remain there for a sustained period. Regarding AECO, he said the company's strategy is to continue diversifying its market access away from the hub, anticipating that production will likely grow to meet new takeaway capacity.

Phillips Johnston from Capital One sought clarification on whether PPA discussions are now focused only on industrial customers, moving away from other counterparties. He also asked about the company's strategy for the pace of share buybacks following a strong first quarter.

Answer

President and CEO Francisco Leon clarified that while interest has expanded to other industrial players, the primary focus for the Elk Hills PPA remains data centers. CFO Clio Crespy explained the aggressive Q1 buyback was an opportunistic response to a stock value dislocation and that future buybacks will continue to be evaluated against other capital priorities to maximize shareholder value.

Phillips Johnston requested key modeling assumptions for the 3-year outlook, including the expected number of gross wells, lateral feet, and average working interest per year. He also asked how much lower the company's base decline rate could fall from the current 35% by the end of the plan.

Answer

CEO Daniel Brown provided directional guidance, stating that the operated well count is expected to decrease due to longer laterals, while non-operated activity will increase, leveraging recent acquisitions. Regarding the decline rate, Brown did not provide a specific target but confirmed he expects continued downward pressure on it, driven by the higher mix of 3-mile wells and the shift to a maintenance capital program.

Phillips Johnston inquired about the drivers for the expected increase in GP&T costs in the second half of the year and the company's expected year-end PDP decline rate.

Answer

An unnamed executive explained the GP&T variance is due to the mix of wells coming online with different contract rates, with a minor upward pressure from the recently acquired Barilla Draw assets. Co-CEO William Hickey stated he does not expect the corporate decline rate to change significantly, remaining in the mid-to-high 30% range as organic growth offsets the lower decline of acquired assets.

Phillips Johnston requested clarification on the shareholder return framework, asking what would happen in a higher oil price scenario: would the company boost buybacks to maintain its 70% free cash flow payout target, or would it stick to the guided buyback range and use excess cash to accelerate debt reduction?

Answer

Chief Financial Officer Jeff Ritenour explained that the company has the flexibility to do both. The near-term plan is a consistent fixed dividend and a $200-$300 million quarterly buyback, with excess cash potentially going to the balance sheet. However, in a sustained "above mid-cycle" price environment, he said they would reevaluate, potentially increasing buybacks or even reintroducing the variable dividend.

Phillips Johnston followed up on the Alaska transactions, asking for the associated production volume and confirming that its impact is not included in the fourth-quarter guidance.

Answer

Kirk Johnson, SVP of Global Operations, clarified that the production associated with the transactions is marginal, at 'several thousand barrels a day.' He confirmed the deals are expected to close in Q4 but that this production has not yet been formally factored into the company's guidance.

Asked for directional guidance on the production trajectory from Q4 2023 to Q1 2024 and for details on the EG natural decline rate and the potential impact of new infill wells.

Answer

The production profile in 2024 is expected to be similar to 2023, with a first-half weighted capital program resulting in a similar production shape. The EG gas decline rate of ~10% is still a good estimate. The potential two infill wells, coming online in 2025, would only partially mitigate this decline but would add very high-value molecules, extending the asset's financial performance.