EGY

Portfolio Restructuring and Strategy

• Over the past two years, management has streamlined and diversified the company's portfolio, completing the divestment of all Canadian assets in early 2026 and expanding the company's position in West Africa.
• The core strategic priority is to grow production, reserves, and shareholder value, while maintaining a top-quartile dividend and consistent capital discipline.

Côte d'Ivoire Operational Updates

• The Baobab FPSO completed its 12-month refurbishment on schedule, returned to the field in April 2026, and all producing wells were brought online in June. A 10-year license extension for Baobab runs through 2038.
• A major 8-well development drilling program (4 producers, 2-3 injectors, 2 workovers) will begin in Q3 2026. The first production from the program is expected by end-2026, with material production uplift coming in 2027.
• Valco was confirmed as operator with a 60% working interest in the Kisapo field, located 8km from Baobab. Kisapo holds estimated 2C gross resources of ~102 million barrels of oil equivalent, with 293 million boe in place. A field development plan is being prepared using new ocean bottom node seismic data, and Valco secured a 6-month extension for the FDP submission deadline to H1 2027.
• For the CI705 exploration block, Valco secured a 6-month extension to the first exploration phase, which now runs through Q4 2026. A final investment decision on proceeding to the well commitment phase will be made by end-2026.

Gabon Operational Updates

• The Phase 3 drilling program is largely complete: two successful new development wells were brought online in Q2 2026, with Itami 14-8 currently producing ~3,000 gross bbl/d. The Iburi 5H well came online at 8,000 gross bbl/d, but water cut has risen faster than modeled, requiring reservoir model re-evaluation.
• The new ETBNM3 gas supply well was completed on schedule, with gas volumes matching pre-drill estimates. It will replace expensive diesel fuel for field operations, improve gas lift reliability, and reduce operating costs.
• Exploration blocks Nyosi Marine and Gaduma Marine completed their 3D seismic survey in Q1 2026; processing is underway with initial results expected in late August 2026.
• Management reduced planned 2026 workover spending to zero from an original guidance of up to $10 million, as existing wells have performed better than expected, and future workovers will be done with the company's in-country workover unit to cut costs.

Egypt Operational Updates

• After a successful multi-year drilling campaign that delivered year-over-year production growth, the drilling program resumed in May 2026. Management expanded the program scope to 10-15 wells in 2026, with no increase to full-year CAPEX guidance, funded by under-budget drilling in Gabon and deferred non-essential projects.
• Trade receivables fell from ~$24 million at end-Q1 to ~$13 million at end-Q2, marking continued progress in keeping receivables current with EGPC.

Equatorial Guinea Operational Updates

• The front-end engineering design (FEED) study for the Venus Block P development is complete, which confirmed technical viability. Management is now evaluating a subsea development design (replacing the original shelf-based design) to reduce complexity and cut costs, targeting a final investment decision (FID) in Q4 2026.

Financial Highlights

• Q2 2026 net capital expenditures were $98.9 million on an accrual basis, below the low end of the prior guidance range, with drilling in Gabon coming in consistently under budget.
• At end-Q2, unrestricted cash was $30.4 million, net debt was $147 million, and the borrowing base under the company's reserve-based lending facility was increased to $300 million in April 2026.
• The company maintained its quarterly dividend program, paying a $6.7 million dividend in Q2 and declaring a Q3 dividend for September 2026.

• Q3 2026 Production Guidance: 24,400 to 26,900 working interest BOPD, and 19,600 to 21,600 NRI BOPD, representing a ~23% production increase from Q2 2026.
• Q3 2026 Sales Guidance: 17,200 to 18,900 NRI BOPD, slightly above Q2 actual sales volumes. The first Baobab lifting (950,000 gross barrels, 27.4% Valco working interest) is expected in August 2026. Smaller cargo sizes are expected for Gabon liftings due to spot market uncertainty.
• Q3 2026 Cost Guidance: Production costs of $25 to $29 per NRI barrel, slightly lower than Q2; exploration expense of $3 to $4 million (mostly for seismic processing); cash G&A of $7 million to $9 million.
• Q3 2026 CAPEX Guidance: $75 million to $115 million, covering ongoing drilling in Gabon, Baobab development preparation, and additional drilling in Egypt.
• Full Year 2026 Guidance: Management reaffirms the prior full-year production and sales growth guidance. The full-year CAPEX midpoint is maintained, even after expanding the Egypt drilling program, due to under-spend in other segments. Workover CAPEX guidance for 2026 is revised to zero from the prior up to $10 million range. Production increases in Egypt and Côte d'Ivoire offset minor downward adjustments to Gabon production, leaving full-year guidance unchanged.
• Management expects growing production, sales volumes, and margins through the second half of 2026 and into early 2027, with material uplift from the Baobab drilling program coming in 2027.

Valco Energy is an upstream oil and gas company operating across four geographic asset segments, with the following Q2 2026 performance:

1. Côte d'Ivoire: Baobab field production restarted in June 2026 following FPSO refurbishment, but no sales liftings occurred in Q2. Production is running slightly above pre-startup forecasts at ~16,400-16,500 gross barrels per day, ~2,000 bbl/d higher than pre-shutdown levels. The company holds a 27.4% non-operating working interest in Baobab, and a 60% operated working interest in the adjacent Kisapo field, plus a 70% operated working interest in the CI705 exploration block.
2. Gabon: Q2 2026 working interest production reached 9,300 barrels of oil equivalent per day, up 23.8% from Q1 2026's 7,516 boepd. Two new development wells (Itami 14-8 and Iburi 5H) came online in Q2, and a new high-GOR gas supply well (ETBNM3) was completed in late Q2. One exploration well (West Etan) was plugged and abandoned as non-commercial.
3. Egypt: First half 2026 sales volumes were 7% higher than the same period in 2025, with production continuing to rise through Q2 following the resumption of the company's drilling campaign in May 2026.
4. Equatorial Guinea: No producing output in Q2 2026, as the Venus Block P development remains in the planning phase.

On a company-wide basis, Q2 2026 production was 16,688 net revenue interest barrels of oil per day (NRI BOPD) and 21,796 working interest BOPD, a 10% increase quarter-over-quarter. Sales hit 17,812 NRI BOPD, 47% higher than Q1. Q2 2026 net income was $42.4 million, adjusted EBITDAX was $54.8 million, and net revenue more than doubled from Q1, reaching $72.6 million above Q1 revenue levels.

• Geologic and reservoir modeling uncertainty: the Iburi 5H well in Gabon saw water cut rise much faster than originally modeled, requiring rework of reservoir models and leading to lower-than-expected near-term production from the well.
• Exploration risk: the West Etan exploration well offshore Gabon encountered good quality sand but was water-bearing and non-commercial. All exploration projects carry inherent risk of dry holes or non-commercial discoveries.
• Macroeconomic and geopolitical risk: ongoing conflict in Iran has driven increases in diesel and freight costs, which may push near-term operating expenses higher. Brent price volatility also impacts cash flow, debt levels, and the timing of cost oil recovery in production sharing contracts.
• Market volatility: geopolitical uncertainty has led to spot market buyers favoring smaller cargoes and delaying purchase agreements, creating near-term timing variability in sales volumes across quarters.
• Development execution risk: the Venus Block P development in Equatorial Guinea required a redesign from the original shelf-based plan, introducing timing uncertainty for the project.
• H2S management risk: while existing H2S control processes have performed better than expected to date, unanticipated H2S levels in new wells could impact production and operating costs.

Q: The newly completed gas supply well in Gabon encountered hydrocarbon shows in shallower intervals; are there any future development opportunities from these zones, and how quickly will switching from diesel to gas reduce operating expenses? / A: While shows were encountered in shallower intervals, the well was not designed to produce from these zones, and they have been tagged for potential future re-completion. The full switch to field gas for the Gabon FSO will cut diesel usage by ~300 to 350 cubic meters per month, for an estimated gross savings of $500,000 to $600,000 per month (Valco's 58% working interest share is ~$290,000 to $350,000 per month). In addition to cost savings, the new gas supply improves gas lift operations and turbine reliability, which is expected to drive additional oil production from existing subsea wells that had underperformed due to insufficient gas pressure.

Q: Why is Gabon's full-year 2026 production at the lower end of expectations, and why was the Kisapo field development plan submission pushed to H1 2027? / A: Gabon's lower guidance is almost entirely due to the Iburi 5H well, which saw a faster-than-expected increase in water cut and faster production decline than the original reservoir model predicted; management has adjusted its forecast to reflect the current plateau rate rather than the original higher decline curve projections. The Kisapo FDP deadline was extended by six months at the request of Valco and its partner, which requested extra time to prepare a higher-quality plan using new seismic data, and the Ivorian regulator approved the extension.

Q: How will the restart and expansion of Baobab production impact Valco's overall cost structure starting in 2027, and what pricing can be expected for Côte d'Ivoire crude? / A: Baobab already has the lowest per-barrel lifting cost in Valco's portfolio. In 2026, transitional costs (including planned ROV inspection work in Q4) will keep unit costs temporarily elevated, but in 2027, fixed costs will be spread over higher production volumes and the operator will complete its planned O&M contract restructuring, leading to a material drop in per-barrel lifting costs. While near-term crude pricing is very volatile due to geopolitical news, Côte d'Ivoire crude has a high-quality assay that is expected to trade at least at parity with Brent over the long term.

Q: When will peak debt be reached under current capital plans, and what is the status of H2S management in Gabon? / A: Peak debt is currently projected for Q1 2027, as capital spending continues for Baobab and Gabon drilling before material production uplift comes online, with the exact level dependent on future Brent prices. Current downhole and topside H2S injection and scavenging processes are performing better than predicted, and the company is able to fully control all H2S output from existing producing wells. Additional production upside from untapped zones will be quantified after the reworking of the reservoir model for the Iburi area is complete in the next 4-5 months.