Q3 2024 Earnings Summary
| Metric | YoY Change | Reason |
|---|---|---|
Total Revenue | +0.2% | Stronger oil and NGL sales slightly outweighed the drop in natural gas revenue, leading to nearly flat overall revenue growth. |
Natural Gas Revenue | –33% | Lower realized natural gas prices drove the decline, as commodity market softness reduced revenue despite relatively stable production. |
Oil Revenue | +12% | Higher realized oil prices and increased production volumes (supported by improved drilling efficiency) boosted oil revenue. |
NGL Revenue | +9% | Improved NGL pricing and moderately higher volumes helped lift NGL revenue despite broader market volatility. |
Operating Income | –23% | Rising costs (including production and G&A) and weaker natural gas revenue pressure offset gains in oil and NGL, lowering operating income. |
Net Income | –22% | Reduced operating margins and the ongoing weakness in natural gas markets outweighed the uplift from oil and NGL, curbing net income growth. |
EPS | –21% | The decline in net income directly curtailed EPS; share repurchases provided a modest offset, but overall lower profitability led to reduced EPS. |
| Metric | Period | Previous Guidance | Current Guidance | Change |
|---|---|---|---|---|
Total production | Q4 2024 | no prior guidance | 630 to 660 MBoe per day | no prior guidance |
Oil production | Q4 2024 | no prior guidance | 106 to 110 MBO per day | no prior guidance |
Natural gas production | Q4 2024 | no prior guidance | 2.53 to 2.66 Bcf per day | no prior guidance |
Capital expenditures | Q4 2024 | no prior guidance | $410 million to $500 million | no prior guidance |
Oil production | FY 2024 | 105.5 to 108.5 MBO per day | 107 to 108 MBO per day | raised |
Capital expenditures | FY 2024 | $1.75B to $1.95B | $1.75B to $1.85B | lowered |
| Metric | Period | Guidance | Actual | Performance |
|---|---|---|---|---|
Capital Expenditure | Q3 2024 | $450 million - $530 million | $393 million | Missed |
| Topic | Previous Mentions | Current Period | Trend |
|---|---|---|---|
Operational efficiency gains (including simul-frac) | Q2 2024: Highlighted simul-frac at Windham Row, achieving 10%-15% cost reductions. Q1 2024: Electric simul-frac saved ~$75/foot compared to diesel. Q4 2023: Large-scale simul-frac projects, 5%-15% lower costs. | Continuing simul-frac in Culberson County, resulting in significant cost savings (~$25/foot). About two-thirds of outperformance tied to timing and one-third to productivity. | Consistently mentioned. Sentiment remains positive as simul-frac continues to drive cost savings. |
Capital efficiency and commodity price sensitivity | Q2 2024: 11% reduction in cost/foot, pivoting capital based on macro conditions. Q1 2024: ~$10.75/foot in Permian, deferring Marcellus due to low gas prices. Q4 2023: Plan to invest $1.75-$1.95B with 5% oil growth. | Achieved 12% higher oil with ~14% less CapEx; lowered 2024 capital guidance by $50-$100MM. Stressed flexibility if oil or gas prices change. Strong returns even at ~$50/bbl. | Recurring topic. Sentiment remains positive as efficiency improves and portfolio flexes with price swings. |
Marcellus activity and curtailments | Q2 2024: Curtailed 325 MMcf/d due to low in-basin pricing. Q1 2024: Deferred TIL of 12 wells, pushing turn-in-lines. Q4 2023: Cut capital >50%, ~6% decline in 2024 Marcellus volumes but contingency plan to resume if prices recover. | No drilling or completion, continuing strategic curtailments. Waiting for Northeast spot prices to improve. | Consistently mentioned. Bearish near term due to low gas prices, but flexible to ramp up when prices improve. |
Drilling inventory and basin-specific productivity | Q2 2024: No “ample acreage,” open to acquisitions. Windham Row in Culberson highlighted. Q1 2024: Strong Lower Marcellus, transitioning to Upper Marcellus. Q4 2023: 3-6 years in Lower Marcellus, ability to pivot. | Emphasized “deep and long inventory” in Anadarko; Wolfcamp (Upper) and Bone Spring strong. Lower vs. Upper Marcellus discussion, though no new Marcellus drilling now. | Recurring topic. Sentiment steady on resource depth, positive on multiple basins. |
Future natural gas demand drivers (AI, LNG, power) | Q2 2024: Focus on LNG exports and power generation, no explicit AI mention. Q1 2024: Discussed AI-driven data center demand potentially 3-30 Bcf/d by 2030, plus LNG growth. Q4 2023: Mainly new LNG capacity as a demand driver. | Highlighted power generation (30%-40% of incremental demand) and LNG export deals. Did not specifically discuss AI demand in detail. | Recurring topic. Remains bullish on LNG and power generation. AI mentioned strongly in Q1 but less so recently. |
Flexibility in capital reallocation and investment | Q2 2024: Not tied to short-term price swings, can pivot among Marcellus, Anadarko, Permian. Q1 2024: Shifting capital out of Marcellus if gas prices stay weak, can accelerate if conditions improve. Q4 2023: Light long-term commitments, can reallocate on market shifts. | Maintaining multi-basin approach and monitoring markets to shift investment as needed. Prepared to respond if gas prices recover. | Consistently mentioned. Sentiment remains highly positive on ability to adapt capital plans quickly. |
Shareholder returns (dividends & buybacks) | Q2 2024: $0.21/share base dividend, 5MM shares repurchased ($295MM), 120% of FCF. Q1 2024: $0.21/share, 5.6MM shares repurchased ($308MM), ~90% of FCF. Q4 2023: $0.21/share, 17MM shares total in 2023, 77% of FCF. | Declared $0.21/share base dividend, repurchased 4.3MM shares ($111MM), returned $265MM total (96% of FCF). | Recurring topic. Sentiment consistently bullish on high return of capital. |
Reduced liquidity due to accelerated buybacks | Q2 2024: No direct mentions of liquidity strain; ended with ~$1.32B in cash. Q1 2024: Strong liquidity cited as rationale for heavier buybacks, still above target. Q4 2023: Did not reference reduced liquidity; ended 2023 with ~$2.5B liquidity. | Noted cash drawdown from ~$1B to ~$840MM; can drop to ~$500MM while maintaining flexibility. | Newer explicit mention in Q3 about willingness to reduce cash further. Not previously flagged as a concern. |
Macroeconomic and political risk factors | Q2 2024: Low natural gas prices, oversupply, potential 2024 election outcomes. Company remains flexible. Q1 2024 & Q4 2023: No specific mentions [—]. | Potential New Mexico setbacks viewed as minimal risk given the state’s revenue reliance on oil & gas. Acknowledged permian gas growth pressuring Waha pricing. | Mentioned more robustly in Q3 and Q2. Sentiment largely neutral, mitigating potential regulatory threats. |
Potential for future growth vs. inventory depletion | Q2 2024: Acknowledged no “ample acreage,” watch for high asset valuations. Q1 2024: Tracking Lower Marcellus depletion, shifting to Upper. Q4 2023: ~3-6 year Lower Marcellus inventory, flexible to accelerate if gas recovers. | Confident in robust portfolio, open to Anadarko acquisitions if accretive. Marcellus tapered but can ramp on price recovery. | Recurring topic. Sentiment remains balanced: confident in multi-basin growth while managing eventual Lower Marcellus depletion. |
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Capital Allocation and Production Growth
Q: How will you allocate capital across assets given your production growth?
A: We're estimating our cash flow based on commodity prices and decide our investment accordingly, maintaining a return of capital in the 40% to 70% range. We ensure our projects are profitable even at oil prices down to sub-$50 per barrel. Growth is an output of disciplined capital allocation, and we remain flexible to adjust investment based on market conditions. -
Simul-Frac and Capital Efficiency
Q: Will you continue using simul-frac in 2025 to improve capital efficiency?
A: We haven't made a firm decision yet but recognize that continuing simul-frac could save about $30 million annually and reduce costs by at least $25 per foot. We're evaluating market conditions and will release detailed plans next quarter, aiming to maintain operational flexibility. -
M&A Strategy and Potential Acquisitions
Q: Are you considering acquisitions to expand your asset base?
A: We're open to smart bolt-on acquisitions, especially in the Anadarko Basin , if they compete with our existing assets. We'd stretch for opportunities to build a new focus area with high-quality resources, but we're cautious not to overpay in the current market. -
Regulatory Risks in New Mexico
Q: How do potential New Mexico setback rules affect you?
A: We believe the setback concerns are overblown and unlikely to be implemented materially. Such rules would harm New Mexico's revenue, which relies 50% on oil and gas. We operate in a responsible regulatory environment with tough standards but don't see serious risk from these proposals at this time. -
Capital Efficiency Improvements
Q: What drives your capital efficiency gains, and are they sustainable?
A: Approximately two-thirds of our efficiency gains come from faster operations, and one-third from improved productivity. Our teams continually push for operational excellence, and we believe these efficiencies are repeatable into 2025 and beyond. -
LNG Contracts and Netback Sales
Q: How will your new LNG contracts impact gas realizations?
A: Our LNG deals are physical gas sales tied directly to foreign indexes like JKM and TTF. While we can't disclose specific improvement figures, these netback sales minimize variability and align our gas prices with global markets. We wish these contracts were in force today. -
Marcellus Activity and Gas Prices
Q: How are you managing Marcellus operations amid low gas prices?
A: We have paused drilling and completion activity, managing curtailments month-to-month. We dewater new wells but treat all molecules equally after capital is spent. We're ready to ramp up quickly with on-ramps in our capital program when gas prices improve. -
Permian Gas Production and Matterhorn Pipeline
Q: What drives your Permian gas growth, and will Matterhorn help?
A: Unexpected higher gas-to-oil ratios contributed to strong gas production. While we've had flow assurance, Matterhorn's startup should improve pricing, especially for Waha-settled volumes, although it's not a complete solution for Waha pricing challenges. -
Anadarko Basin Expansion
Q: Will you acquire more acreage in the Anadarko Basin?
A: With a deep inventory at current investment levels, we would consider additional assets in the Anadarko Basin if they compete for capital and enhance our program , allowing us to run a steadier operation. -
Shareholder Returns and Buybacks
Q: Will shareholder returns remain higher than average?
A: We are committed to returning 50%+ of free cash flow to shareholders. We assess buybacks based on intrinsic value, free cash flow outlook, and liquidity. With about $840 million in cash , we have the ability to continue buybacks while evaluating other opportunities. -
Natural Gas Demand from Power Generation
Q: What's your view on gas demand growth from power generation?
A: We see natural gas as a major driver for power demand this decade, potentially supplying over 40% of incremental power needs. Given reliability requirements, there's no other solution in the required timeframe, which should be very constructive for gas demand and prices.