Gran Tierra Energy Inc. — Q2 2020 Form 10-Q
Reporting period: Three and six months ended June 30, 2020. Gran Tierra explores and produces oil and natural gas in Colombia and Ecuador. Unless otherwise stated, financial amounts below are in U.S. dollars.
Financial and operating performance
| Metric | Q2 2020 | Q2 2019 | Six months 2020 | Six months 2019 |
|---|---|---|---|---|
| Oil and gas sales | $33.8 million | $158.0 million | $119.9 million | $310.6 million |
| Net income (loss) | ($370.6 million) | $38.5 million | ($622.3 million) | $40.5 million |
| Operating cash flow | Not separately stated | Not separately stated | $6.9 million | $93.0 million |
| Capital expenditures | $4.7 million | $99.6 million | $49.0 million | $194.1 million |
| Adjusted EBITDA (non-GAAP) | $17.9 million | $97.4 million | $52.4 million | $191.3 million |
| Funds flow from operations (non-GAAP) | $6.0 million | $88.3 million | $28.2 million | $163.7 million |
- Q2 NAR production was 18,408 BOEPD, down 37%; sales volumes were 19,266 BOEPD, down 34%. Average realized sales price was $19.29/BOE, down 67%, while Brent averaged $33.39/bbl, down 51%.
- Q2 operating netback, a non-GAAP measure, fell to $10.8 million from $106.6 million; netback per BOE fell to $6.16 from $40.02. Operating expenses fell 45% to $18.4 million, but lower prices, wider differentials and reduced volumes drove the sharp revenue decline.
- Q2 loss included $398.3 million of oil and gas property impairment. First-half impairment charges also included $102.6 million of goodwill and $4.1 million of inventory impairment. These charges were principally tied to lower commodity prices and were largely non-cash.
- At June 30, cash and cash equivalents were $17.2 million; current restricted cash was $0.4 million. Working capital, including cash, was $48.0 million, down from $91.3 million at year-end 2019. Total assets were $1.38 billion, versus $2.04 billion at year-end.
- Long-term debt carrying value was $789.3 million, including $207 million drawn on the revolving facility and $600 million principal amount of senior notes. The notes bear interest at 6.25% and 7.75% and mature in 2025 and 2027. Revolver availability was $18 million against a $225 million borrowing base.
- First-half cash flow from operations of $6.9 million was below $49.0 million of capital expenditures. Cash increased by $8.7 million over the half-year, supported by $90.5 million net proceeds from bank debt.
Material changes and management commentary
- Sales fell 79% in Q2 and 61% in the first half year over year, reflecting weaker Brent prices, higher quality and transportation discounts, and lower sales volumes. Production was curtailed amid low prices, COVID-19 disruptions and a local farmers’ blockade affecting Suroriente and PUT-7.
- Management reduced activity and capital spending to preserve liquidity. Q2 capital expenditures were 95% below Q2 2019; no exploration or development wells were drilled during the quarter. It reported structural cost reductions through vendor renegotiations and personnel and equipment optimization.
- Management said it planned to bring most shut-in fields back online during the second half, restart workovers in Q3, and resume development drilling by year-end, targeting one or two new wells. These plans depend on oil prices, operating conditions and logistics; they are not assured outcomes.
- Management reported $16.7 million of realized oil-hedging gains in the first half and 11,000 BOEPD hedged for the second half. Q2 sales were entirely oil, primarily to two major Colombian customers.
- Tax receivables were $131.8 million current and long-term combined at June 30. Gran Tierra collected $24.9 million in refunds during Q2 and another $21.4 million after quarter-end; management expected total 2020 refunds of approximately $76–$86 million.
Liquidity, risks and contingencies
- The June 1 borrowing-base redetermination reduced the revolver limit from $300 million to $225 million. The company obtained modified financial covenants and was in compliance with applicable covenants at June 30. Management forecast compliance for at least a year, while warning that oil-price volatility and pandemic disruption heightened non-compliance risk. A default could restrict borrowing, accelerate the revolver and trigger defaults under the senior notes.
- The filing contains inconsistent descriptions of the covenant-relief end date: the debt note and MD&A highlight state October 1, 2021, while other MD&A and risk-factor passages state October 1, 2020. Investors should confirm the operative credit-agreement terms and the correct date.
- The credit amendment increased borrowing spreads by 125 basis points during the relief period and imposed a $15 million cash-balance condition, mandatory prepayments in certain circumstances and additional restrictions on debt, liens, investments and distributions.
- Key uncertainties include oil prices and differentials, COVID-19 restrictions, production restart timing, access to financing, future borrowing-base reductions and covenant compliance. Management identified liquidity, asset carrying values and deferred tax asset valuation as particularly judgment-sensitive.
- Letters of credit and other credit support totaled $107.7 million for work commitments and other requirements. The company disclosed ongoing lawsuits and claims, including a dispute with Colombia’s National Hydrocarbons Agency concerning HPR royalty calculations; management did not expect resolution to materially adversely affect the company. No off-balance-sheet arrangements were reported.
Most important facts for investors to verify
- Whether covenant relief ends October 1, 2020 or October 1, 2021, and the current covenant thresholds, cash restrictions and available revolver capacity.
- Actual tax-refund collections versus management’s $76–$86 million 2020 expectation, and the timing and usability of remaining tax receivables.
- Whether planned field restarts, workovers and year-end drilling occurred, and the resulting production, costs and capital needs.
- Further changes in oil prices, Colombian quality and transportation differentials, realized prices and hedge coverage.
- Whether subsequent reserve or asset valuations, borrowing-base redeterminations, or operating disruptions result in additional impairments or liquidity pressure.
Non-GAAP measures, including Adjusted EBITDA, funds flow from operations and operating netback, are company-defined and may not be comparable with similarly named measures at other companies.