Talos Energy Inc. — Form 10-Q Summary
Business Context and Reporting Period
Talos Energy is an independent offshore oil and gas exploration and production company operating primarily in the U.S. Gulf of Mexico and offshore Mexico. It also develops carbon capture and sequestration projects. This unaudited Form 10-Q covers the three and six months ended June 30, 2022, compared with the corresponding 2021 periods.
Key Financial Metrics
| Metric | Q2 2022 | Q2 2021 | Six Months 2022 | Six Months 2021 |
|---|---|---|---|---|
| Revenue | $519.1 million | $303.8 million | $932.7 million | $570.7 million |
| Operating income | $276.0 million | $93.3 million | $493.5 million | $158.0 million |
| Net income (loss) | $195.1 million | $(125.8) million | $128.7 million | $(247.3) million |
| Diluted EPS | $2.33 | $(1.54) | $1.55 | $(3.03) |
| Net cash from operating activities | Not separately disclosed | Not separately disclosed | $354.4 million | $199.1 million |
| Adjusted EBITDA | $250.8 million | $148.1 million | $459.0 million | $284.7 million |
Q2 operating margin was approximately 53.2% and net margin was approximately 37.6%; six-month operating margin was approximately 52.9% and net margin was approximately 13.8%. These margins are affected by derivative results and unusual gains and expenses.
- Production declined to 65.4 MBoepd in Q2 from 66.3 MBoepd, and to 64.3 MBoepd for the six months from 66.2 MBoepd.
- Q2 realized prices increased to $108.03 per oil barrel, $8.00 per Mcf of natural gas and $37.79 per NGL barrel. Price per Boe, including realized commodity derivatives, was $60.28 versus $38.89 in the prior-year quarter.
- Six-month capital expenditures were $130.9 million, including $70.5 million for U.S. drilling and completions and $2.6 million for CCS. Including plugging and abandonment, total expenditures were $170.6 million.
- Cash and cash equivalents were $108.5 million at June 30, 2022, versus $69.9 million at December 31, 2021.
- Available liquidity, defined as cash plus available Bank Credit Facility capacity, was $702.1 million.
- Debt before discounts and deferred financing costs was $850.0 million, consisting primarily of $650.0 million of 12.00% second-priority senior secured notes due 2026 and $200.0 million drawn under the Bank Credit Facility.
- The Bank Credit Facility borrowing base increased from $950.0 million to $1.1 billion, and commitments increased from $791.3 million to $806.3 million. The Company was in compliance with its debt covenants.
Material Changes Versus the Prior Comparable Period
- Revenue increased 71% in Q2 and 63% for the six-month period, primarily because of higher oil, natural gas and NGL prices. Production volumes were modestly lower.
- Net income improved from a $125.8 million loss to $195.1 million of income in Q2 and from a $247.3 million loss to $128.7 million of income for the six months.
- Operating cash flow increased $155.3 million for the six months, despite $169.7 million of additional cash payments on settled derivatives.
- Lease operating expense increased 22% in Q2, primarily due to facility and workover costs at the Phoenix and Gunflint fields. Six-month lease operating expense increased 6%.
- Price risk management expense was $64.1 million in Q2 and $345.3 million for the six months. Six-month expense included $287.3 million of cash settlement losses and $58.0 million of unrealized losses.
- The Company redeemed its $6.1 million of 7.50% senior notes at maturity on May 31, 2022 and reduced Bank Credit Facility borrowings by $175.0 million during the first six months.
- Production was affected by approximately 40 days of Eugene Island Pipeline System downtime in the first quarter, resulting in estimated deferred production of approximately 2.3 MBoepd for the six-month period.
Guidance, Outlook, Commentary, Risks and Unusual Items
- Management expects cash flows from operations, cash on hand and Bank Credit Facility availability to fund the remainder of the board-approved 2022 capital program of $450 million to $480 million, including approximately $30 million for CCS. This is liquidity commentary rather than a revenue or earnings forecast.
- The HP-I floating production facility began a planned dry-dock on August 3, 2022, with expected Phoenix Field production shut-in of approximately 45 to 60 days.
- Talos recorded a $27.5 million litigation settlement gain in the six-month period and a $13.9 million gain on the partial sale of its Bayou Bend CCS investment. These items benefited reported earnings.
- Estimated decommissioning obligations of $10.5 million were recorded for the six months, primarily because certain counterparties or former working-interest partners may be unable to perform abandonment obligations. Total asset retirement obligations were $452.4 million at June 30, 2022.
- Commodity derivatives created a net liability of $254.7 million at June 30, 2022, compared with $196.7 million at year-end 2021. Hedging contracts extend through June 2024 and may materially affect future earnings and cash flows.
- Key risks include oil and gas price volatility, inflation and higher interest rates, offshore operational and weather risks, third-party infrastructure outages, cybersecurity, environmental liabilities, decommissioning and BOEM bonding requirements, regulatory changes, uncertainty regarding the Zama development plan, and risks associated with CCS projects.
- At June 30, 2022, the Company had $689.0 million of performance bonds and $12.6 million of letters of credit related primarily to abandonment, facility-removal and Mexico production-sharing obligations.
- Bayou Bend generated no revenue and incurred $7.8 million of operating expenses in the first six months. Talos owned a 25% interest at quarter-end and remained project operator.
Important Facts for Investors to Verify
- Verify the sustainability of earnings and cash flow after excluding the litigation settlement, Bayou Bend sale gain and derivative mark-to-market effects.
- Assess the impact of the HP-I dry-dock and other third-party downtime on production and 2022 guidance.
- Review hedge volumes, fixed prices, collateral terms and the $254.7 million net derivative liability.
- Evaluate liquidity after planned capital spending, debt service, derivative settlements and potential decommissioning payments.
- Monitor the fourth-quarter 2022 borrowing-base redetermination and compliance with Bank Credit Facility covenants.
- Assess potential increases in BOEM supplemental bonding requirements and the Company’s exposure to third-party abandonment failures.
- Review progress, funding requirements and permitting for Bayou Bend and other CCS initiatives, as well as development uncertainty surrounding the Zama asset.