ConocoPhillips

ConocoPhillips reported EBITDA of $9.32 billion, 8% above S&P's $8.63 billion consensus. During the quarter, it bought into several Middle East projects in Iraq and Syria. CEO Ryan Lance announced his retirement, with CFO Andy O'Brien stepping into the role.

Why it matters: Boosting exposure to Iraq and Syria in the middle of the ongoing regional war is certainly a countercyclical bet, but in the long arc of history, Conoco is likely buying low. It seems unlikely that new capital will be allocated to Iraq, with management expecting the joint venture to generate its own needs. Syria is presented as a smaller opportunity, with no near-term impact. Most importantly, neither project is expected to derail the long-term free cash flow target. They could present further production growth in the 2030s through additional development.

The bottom line: We are lowering our fair value estimate to $126 from $129 after incorporating the results and refreshing our model. Pushing back our expected full resumption of Middle Eastern liquids production into 2028 drove the decrease. Shares trade in 3-star territory, but trade below our revised fair value estimate. Our narrow moat rating, Exemplary Morningstar Capital Allocation Rating, and High Morningstar Uncertainty Rating remain unchanged.

Coming up: Regarding the leadership transition, management stressed that there has been no fundamental shift in strategy. O'Brien has been with Conoco for nearly 30 years and touched most parts of the business, including strategy and as CFO. It's hard to see why management would shift strategy; it has so far been effective, and there is a clear glide path with the existing plan through 2029. There is no pressing need to make acquisitions, with consultancy Rystad Energy estimating the firm's Permian Basin runway exceeds 40 years at the current drilling pace. That extends well beyond all peers in the basin. Similarly, development in Alaska, Libya, and elsewhere remains an option.

We lower our fair value estimate to $126 per share from $129 after refreshing our model with the most recent results. The primary driver was pushing back our assumed resumption of liquids production to 2028.

We assume oil (West Texas Intermediate) prices in 2026 and 2027 will average $81 and $72 per barrel, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $3.10 and $3.49 per thousand cubic feet. Terminal prices are defined by our long-term midcycle price estimates (currently $65/bbl Brent, $60/bbl West Texas Intermediate, and $3.70/mcf natural gas).

Our fair value estimate corresponds to enterprise value/EBITDA multiples of 5.5 times and 6.0 times for 2026 and 2027, respectively. Our production forecast for 2026 is 2,321 thousand barrels of oil equivalent per day, in line with guidance from management. That drives 2026 EBITDA to $33.7 billion, and we expect free cash flow to reach $13.5 billion in the same period. Our 2027 estimates for production, EBITDA, and free cash flow are approximately 2,426 mboe/d, $31.1 billion, and $12.6 billion, respectively.

ConocoPhillips is a global upstream producer of oil, natural gas liquids, natural gas, liquefied natural gas, and bitumen. Given its low costs and global asset base, we see the firm as having a narrow Morningstar Economic Moat Rating, driven by a general cost advantage and efficient scale in some activities. Oil and gas producers can gain a moat only through cost advantage, as they must deliver excess returns over the commodity cycle.

In 2025, Rystad Energy estimated that the breakeven cost for ConocoPhillips’ current and future production is around $34/bbl (barrel of oil), rising to $38/bbl-$44/bbl when considering only undrilled and proven inventory. Both are well below our midcycle expectations of $60 and $65 for West Texas Intermediate and Brent, respectively.

Alaska earns a narrow moat:

Alaskan production had been declining year over year as new development stalled. ConocoPhillips has begun more aggressively investing in the asset to maintain and grow production since it received the necessary go-ahead to develop the Willow project. This is the firm's largest remaining capital project, and we expect it to achieve first oil in 2029.

Production is expected to be flat to low-single-digit growth outside of the Willow project. Conoco intends to bring wells online as old wells decline to continue filling the existing infrastructure. In addition to field-level infrastructure, Conoco also holds a minority interest in the crucial Trans Alaska Pipeline, which connects the northern fields to Valdez on the southern coast of Alaska. This pipeline has operated at about one-quarter of its design capacity of 2 million barrels per day in recent years, highlighting the scalability of Alaskan production.

We expect additional projects to materialize, but we’ve not included them in our forecast.

Lower 48 earns a narrow moat:

Conoco’s Lower 48 operations are dominated by shale drilling. We see the segment as marginally meriting a narrow moat. The segment’s ability to earn excess returns outside the most extreme downcycles, like the 2020 slump, is reassuring. The firm’s strategy for the Lower 48 is to constrain activity at a maintenance level and realize incremental drilling efficiencies. Shale assets are short-cycle, generating most of their volumes in the first 12-18 months, and decline quickly. So, while this segment will demand the most capital, it is only the amount needed to keep production flat.

Conoco is looking to longer-cycle projects with lower breakevens to fuel future growth, such as the Port Arthur LNG facility on the Gulf Coast. Conoco is both an equity partner and purchaser of 5 million tons per year of LNG in the first phase, which is expected to achieve first gas in 2027. In 2025, it expanded its involvement by agreeing to purchase another 4 Mtpa from Phase 2 of the project, which we expect in 2030 and 2031. Further purchases from US LNG facilities without equity commitments look likely, as the intense competition between facilities for long-term buyers has driven down fixed fee prices for the industry.

Canada earns no moat:

Canadian operations do not justify a moat today, but the operating environment is becoming increasingly favorable and could have a narrow moat in the future. We’ve not observed a consistent history of excess returns and only forecast marginally excess returns at midcycle.

Producers in Canada have difficulty generating returns above their cost of capital, despite decades of Tier 1 acreage. Fundamental issues include additional processing costs for heavy Canadian crude, causing a persistent discount to West Texas Intermediate that their American counterparts, who mainly produce light crude, don’t face. Tight midstream capacity can worsen the discount as crude will have to be shipped by rail or stored until conditions improve. Additionally, bitumen, the segment's primary commodity, sells at an even deeper discount to West Texas Intermediate. We expect segment volumes to grow as drilling in the Montney continues but still expect this to be a minor contributor by the end of the decade due to its small size.

Europe, the Middle East, and North Africa earn a narrow moat:

Thanks to the segment’s heavy exposure to Brent pricing and modest capital required to maintain production, we expect the segment to produce strong excess returns. Furthermore, current and developing projects with Qatar will provide the lowest-cost source of LNG.

Operated assets are in Norway and Equatorial Guinea, with non-operated stakes in Norway, Qatar, Libya, Iraq, and Syria. Production in Norway and Equatorial Guinea is expected to decline over time as the fields are mature. Operations in Equatorial Guinea may experience a longer life beyond produced gas; however, the stakes include downstream gas processing and LNG and liquefied petroleum gas export facilities. As production declines, those assets may instead serve other producers.

Asia-Pacific earns a narrow moat:

Even during 2020, returns for the segment did not dip below the cost of capital. The only operated asset within the segment is an LNG production facility and natural gas production that feeds the facility and local demand. Almost all production is secured by 20-year purchase agreements, which amounted to 68% of the segment’s 2024 volumes. The asset would generally earn a wide moat if assessed alone.

The remaining assets are nonoperated stakes in CNOOC’s Penglai field in mainland China and multiple minority stakes in Malaysia. These volumes receive Brent pricing, with Malaysian volumes getting a substantial premium. Both continue to be developed, with multiple exploration activities in process in Malaysia and Australia.

As other US E&Ps begin to branch out into international markets, Conoco has been there for decades with experience across asset types.

With US shale peaking, exposure to global assets gives substantial flexibility in investment decisions.

LNG expertise is unmatched among independents, with an industry-standard train design and years of operational experience.

Shale is a high-cost source of supply that may be displaced as new oil development focuses on low-cost offshore opportunities.

Extending US shale reserves will require purchasing operations and leases, which will be at an increasing premium for quality acreage.

Conoco operates in multiple regulatory jurisdictions that, while friendly today, may quickly turn against it.