Gran Tierra Energy Inc. — Q3 2015 Form 10-Q
Reporting period: Three and nine months ended September 30, 2015. Amounts are in U.S. dollars unless noted. Gran Tierra is an oil and gas exploration and production company operating principally in Colombia, Peru and Brazil.
Financial performance and position
| Metric | Q3 2015 | Q3 2014 | Nine months 2015 | Nine months 2014 |
|---|---|---|---|---|
| Oil and gas sales | $75.7 million | $161.5 million | $221.2 million | $460.5 million |
| Net income (loss) | $(101.9) million | $44.2 million | $(185.3) million | $98.5 million |
| Operating netback, non-GAAP | $41.9 million | $127.6 million | $131.9 million | $379.3 million |
| Funds flow from continuing operations, non-GAAP | $36.6 million | $93.6 million | $91.5 million | $263.6 million |
| Capital expenditures | $24.6 million | $95.4 million | $116.4 million | $268.9 million |
- Q3 sales volumes increased 5% to 21,626 BOE per day; nine-month volumes declined 2% to 18,673 BOE per day. Production net after royalty was broadly stable year over year.
- Realized oil and gas sales price fell 55% to $38.03 per BOE in Q3 and 51% to $43.40 per BOE over nine months. Operating netback per BOE was $21.07 in Q3 versus $67.17, and $25.88 for nine months versus $73.22.
- Operating cash flow was $58.5 million for nine months, versus $142.2 million in 2014. Cash and equivalents fell 44% from year-end 2014 to $187.0 million; working capital was $190.8 million, down from $239.8 million.
- Total assets were $1.271 billion and shareholders’ equity was $1.087 billion at September 30, 2015. The company reported no debt outstanding and had not drawn its new reserve-based credit facility.
- Operating expenses were $33.8 million in Q3 and $89.3 million for nine months. G&A fell 41% and 37%, respectively, compared with 2014; nine-month severance was $6.8 million.
Changes versus prior comparable periods
- Lower benchmark oil prices were the principal cause of sales declines: Brent averaged $50.23 per barrel in Q3 2015 versus $101.82 in Q3 2014.
- Net losses replaced prior-year profits, principally reflecting lower sales and a sharp increase in depletion, depreciation and impairment charges. DD&A was $205.0 million in Q3 and $360.6 million for nine months, compared with $53.9 million and $140.1 million.
- Impairments included a $129.4 million Colombia ceiling-test charge in Q3, Brazil charges of $17.6 million in Q3 and $46.9 million year to date, and Peru Block 95 charges of $3.0 million in Q3 and $41.0 million year to date.
- Lower capital spending and staff and overhead reductions supported cost savings, while Q3 sales benefited from inventory drawdown. For the nine-month period, inventory accumulation reduced sales volumes.
- Cash used in investing activities was $191.2 million for nine months, largely reflecting capital spending and investing-related working capital. Share repurchases used $6.6 million of cash; 3.0 million shares were repurchased and canceled.
Outlook, risks and contingencies
- Management expected the 2015 capital program to total approximately $175–185 million, funded from operating cash flow and cash on hand. The filing says the program could be adjusted as conditions and opportunities change. Management stated that cash resources were expected to be sufficient for the program and strategic objectives under then-current price and production assumptions.
- Management warned of likely further ceiling-test impairment in Q4 2015 if other factors were held constant: potentially more than $15 million in Brazil and $95 million in Colombia. These were estimates based on specified price assumptions, not a guaranteed outcome. Management did not expect a downward adjustment to consolidated NAR reserves under its stated assumptions.
- Oil-price volatility, pipeline restrictions in Colombia, transportation costs, foreign-exchange movements, permitting and contractor availability, and access to capital markets were identified as risks. Colombia accounted for 97% of revenue and other income for the nine months.
- Colombian ANH arbitration over the Chaza Contract HPR royalty remained unresolved. Gran Tierra had begun paying royalty on Moqueta production above the five-million-barrel threshold, but disputed the ANH’s claim for earlier and additional amounts. Potential claimed compensation was estimated at $66.3 million plus interest of $23.6 million using the ANH’s rate; the company estimated interest at $5.7 million using its asserted rate. A separate transportation-cost interpretation could involve up to $43.6 million. No amounts were accrued because management did not consider losses probable.
- A separate Ecopetrol allocation dispute had a $2.4 million accrual. The company also had $75.7 million in promissory notes securing letters of credit for contractual commitments.
- The new credit facility, effective September 18, 2015, had an initial $200 million borrowing base, subject to semiannual redetermination and a $500 million maximum, plus a letter-of-credit sublimit up to $100 million. It matures September 18, 2018; the company reported covenant compliance and no borrowings.
- Approximately 90% of cash was held by subsidiaries or partnerships outside Canada and the United States and might not be available for head-office needs without repatriation, potentially with withholding taxes.
Important facts for investors to verify
- Whether oil prices, realized prices and production or transportation constraints support the company’s capital-spending and liquidity assumptions.
- The amount and timing of any further Colombia and Brazil ceiling-test impairments, and the assumptions used in those calculations.
- Developments in the ANH HPR royalty arbitration and transportation-cost dispute, including potential exposure, interest calculations and accounting treatment.
- Availability and location of cash, working-capital trends, and future borrowing-base determinations and covenant compliance under the new facility.
- Progress and spending against the 2015 capital program, including planned Colombia drilling and the status of Peru permitting and Brazil activities.