California Resources: where should the next dollar go?
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Strategy case for MBA students and working professionals
Information cutoff: September 24, 2026, close of business Pacific Time
Your assignment
You are advising a hypothetical CRC capital-allocation team after Carbon TerraVault I (CTV I) began injecting carbon dioxide in May 2026. Recommend a conditional rule for the next discretionary dollar: stage additional CTV storage and customer development; prioritize California production, power and related infrastructure; or preserve more capital for shareholder returns, debt reduction or liquidity. You may propose a combination, but specify the conditions that would shift funding among uses.
This is a classroom decision, not a disclosed board vote, approved next tranche, or known internal debate. Work only with information available by the cutoff. Distinguish reported facts from management claims and unresolved estimates. What evidence should CRC require before releasing additional capital?
A California energy company at a transition point
California Resources Corporation (CRC) produces oil and natural gas, operates related facilities and is developing carbon-management projects through CTV. Its strategy presents these activities as connected: existing subsurface, land, operating and infrastructure assets may support both conventional energy operations and carbon storage. Whether those assets create a durable economic advantage for CTV remains to be demonstrated in project-level results. CRC 2025 Form 10-K, pp. 32–33, 42–43, 69–70
The company had recently expanded and reshaped its portfolio. In May, CTV I reported its first CO₂ injection at the 26R reservoir at Elk Hills. On September 1, CRC completed its approximately $63 million all-cash acquisition of Crimson California Resources, a midstream pipeline business. CRC cited market access and operating flexibility and described potential future CO₂ transport as an opportunity; it did not disclose a quantified synergy or a committed CO₂-conversion plan. First injection release, May 26; Crimson closing release, September 1
On September 17, CRC announced an agreement to sell its Uinta Basin assets for approximately $90 million cash, subject to customary adjustments, consents and conditions. The sale had not closed by the case cutoff; CRC expected it to close by year-end. Management said proceeds would support shareholder returns and other corporate purposes and described the sale as helping offset the Crimson purchase and sharpening CRC’s California focus. The announced gross price was not cash on hand and was not specifically earmarked for CTV. Uinta announcement, September 17
These moves make the next-dollar question timely. They do not establish that the company has chosen which activity to fund next.
What has CTV demonstrated?
CTV I’s first injection is an operating milestone. EPA’s Class VI permit record covers four injection wells for the specified 26R facility. A permit authorizes wells; it does not establish steady-state throughput, contracted third-party demand, realized economics or permission for every other CTV reservoir. CRC’s May announcement reports the initial injection; it is not evidence of a full operating year. EPA permit record; CRC first-injection release
CRC said CTV began accruing revenue related to Section 45Q tax credits as CO₂ was captured beginning in May. Accrued credit revenue is not evidence of cash received. Separately, the CTV joint venture (JV) reported about $1 million of sequestration-service revenue for the second quarter and first half of 2026; the filing does not identify this as all 45Q revenue. CTV’s second-quarter update also reported initial revenue and said it was discussing opportunities with power customers; discussions are not signed offtake agreements. Q2 Form 10-Q, Note 12, “Supplemental Account Balances,” Revenues subsection (p. 29; SEC lines 1635–36); Q2 Form 10-Q, Note 3 (pp. 13–14; SEC lines 756–58); Q2 Form 10-Q, MD&A p. 50 (segment table; SEC lines 2380–94); CTV Q2 update, August 10
CTV is not solely CRC-funded or controlled. CRC owns 51% of the CTV JV and Brookfield owns 49%; the companies share decision-making on matters that most affect the venture’s economics. Brookfield had contributed $92 million through June 30. Remaining initial contributions depend in part on permitted storage capacity and contracted injection volumes. CRC’s annual filing describes an initial Brookfield commitment for jointly approved projects, subject to milestones. This is conditional partner funding, not an unrestricted CRC cash balance or a guaranteed project budget. Q2 Form 10-Q, Note 3; 2025 Form 10-K, CTV JV discussion
Capital alternatives
CRC’s Q2 filing estimated a 2026 capital program of $520–560 million: $500–525 million for oil and gas, $12–20 million for carbon management and $8–15 million for corporate and other items. The filing states that the carbon-management capital line excludes amounts funded by Brookfield through the JV. CTV’s separate August 10 update gave a 2026 CTV capital-investment range of $10–18 million. CRC has not reconciled the different $12–20 million and $10–18 million ranges in the materials reviewed. They may reflect different scopes; keep them separate and do not treat either as full CTV project cost or as a return measure. Q2 Form 10-Q, MD&A, pp. 50–51; CTV Q2 update
The filing also lists drilling adjustments, dividends and share repurchases, debt reduction, carbon management and retaining cash as uses CRC considers. At June 30, CRC reported $43 million cash and $1.279 billion of revolver availability; revolver availability is borrowing capacity, not cash. It had $750 million of 2034 notes with a 7.0% coupon and $550 million of 2035 notes with a 7.25% coupon. Up to $600 million remained under its nonbinding repurchase authorization, and CRC declared a $0.405-per-share dividend in August. These are alternatives and constraints, not instructions to spend. Q2 Form 10-Q, MD&A pp. 50–51, Note 4 and Item 2
Exhibit 1. Reported capital and liquidity at the cutoff
| Disclosure | Reported amount / status | Boundary |
|---|---|---|
| 2026 total capital program | $520–560m | Company estimate; includes the segments below |
| Oil and gas capital | $500–525m | Company estimate; not a project return forecast |
| Carbon-management capital | $12–20m | Q2 10-Q segment range; excludes Brookfield-funded JV amounts |
| CTV 2026 capital investment | $10–18m | Separate CTV update range; scope difference unresolved |
| Corporate and other capital | $8–15m | Company estimate |
| Cash, June 30 | $43m | Balance-sheet cash |
| Revolver availability, June 30 | $1.279bn | Borrowing capacity, not cash |
| Remaining repurchase authorization | $600m | Nonbinding authorization; not a planned spend |
| 2034 / 2035 notes | $750m at 7.0% / $550m at 7.25% | Principal and coupons disclosed in filing |
Source: CRC Form 10-Q, MD&A pp. 50–51, Note 4 and Item 2. The CTV range is from its separate Q2 update. Do not merge or select a range without resolving scope.
A competitive and regulatory landscape
California’s CCS pipeline includes another power-linked project. EPA Region 9 lists Calpine’s Sutter Decarbonization application as administratively complete on March 13, 2024, with three proposed injection wells and about 22 million tonnes over approximately 12 years. Administrative completeness is not an issued permit, final investment decision, construction or operation. Calpine’s August 2024 announcement describes a capture design targeting 95% and a DOE Phase 1 cost-share for engineering, design, community engagement and planning. The 95% is a design target, not an achieved rate; later phases are contingent. These sources disclose no project economics or contracted storage cash flow. Sutter is a California development-stage comparison, not a return benchmark. EPA Region 9 application tracker, Sutter row last updated July 24, 2026; Calpine announcement, August 7, 2024
ExxonMobil’s May 2026 climate report describes several named industrial CCS customer agreements and approximately 9 million tonnes per year under contract across its projects. This offers a commercialization contrast—disclosed customer commitments—rather than a California cost or return comparison. ExxonMobil’s report is company-reported, and some planned volumes remain contingent on additional investment and government permits. The scale, geography, infrastructure and project stages differ from CTV. ExxonMobil, Advancing Climate Solutions 2026, p. 17
CRC has also announced a proposed Golden Valley Technology Hub data-center development at Elk Hills with Beacon Data Centers. CRC’s CEO cited reliable-power demand as a strategic opportunity. The company has not disclosed a signed power offtake, CRC capital requirement, final investment decision or project return. It is another option to investigate, not a fully specified investment proposal. Q2 earnings release, August 10, 2026
Exhibit 2. What the project comparisons establish
| Project | Disclosed evidence | What remains unknown |
|---|---|---|
| CTV I / 26R | First injection in May; four EPA Class VI well permits for the specified facility; Brookfield JV | Contracted external volume, realized utilization, project-level returns and next-reservoir economics |
| Calpine Sutter | Application administratively complete; three proposed wells; design target of 95% capture; DOE Phase 1 engineering/design support | Permit, FID, achieved capture, project economics and contracted storage cash flow |
| ExxonMobil projects | Named customer agreements; company report describes ~9 Mt/year under contract | CRC-comparable California project cost or return; some volumes contingent on investment and permits |
The decision
CRC’s first injection, issued 26R permits, JV structure and evolving California portfolio make additional CTV investment a credible subject for review. Yet the public record does not establish contracted customer demand, the economics or capital requirements of another storage tranche, cash received from 45Q, or the realized value of Crimson’s possible CO₂-transport role. Core oil and gas remains the largest stated capital category; returns for the marginal production dollar are also not disclosed in the case materials. The company’s next-dollar rule must therefore confront competing uses without pretending the public numbers resolve project-level returns.
What conditional portfolio-allocation rule should CRC use after CTV I’s first injection? What evidence should release the next CTV tranche, shift capital toward production/power or preserve funds for debt reduction, shareholder returns and liquidity? Explain which uncertainties matter most, what could change your recommendation and how CRC should treat its partners’ funding and decision rights.
Information boundary: This case uses accessible information published on or before September 24, 2026, close of business Pacific Time. CRC’s September 2026 investor presentation was listed but could not be read; no case claim relies on unseen slides. The classroom role and next-dollar choice are hypothetical, not a claim about CRC management’s or its board’s actual deliberations. The case contains no post-cutoff outcome.