Gran Tierra Energy Inc. — Q2 2018 Form 10-Q
Reporting period: Three and six months ended June 30, 2018. Filed August 2, 2018. Unless otherwise stated, amounts are U.S. dollars. Gran Tierra is an oil and gas exploration and production company focused on Colombia; all Q2 2018 revenue was from oil sales.
Financial and operating performance
| Metric | Q2 2018 | Q2 2017 | H1 2018 | H1 2017 |
|---|---|---|---|---|
| Oil and gas sales | $163.4 million | $96.1 million | $301.7 million | $190.8 million |
| Net income (loss) | $20.3 million | $(6.8) million | $38.2 million | $6.0 million |
| Operating netback (non-GAAP) | $121.9 million | $62.4 million | $226.8 million | $126.2 million |
| Funds flow from operations (non-GAAP) | $94.5 million | $50.9 million | $169.3 million | $95.9 million |
| Capital expenditures | $84.4 million | $57.9 million | $157.1 million | $104.0 million |
- Q2 sales rose 70% year over year, reflecting higher realized prices and sales volumes. Average realized price was $64.37 per BOE, up 60%; Brent averaged $74.90 per barrel, up 47%.
- Q2 net margin was approximately 12.4% of sales, versus a 7.1% loss margin in Q2 2017. Q2 operating netback was $47.99 per BOE, up 84% year over year. These margins are calculated from reported figures.
- Q2 working-interest production before royalties reached a company record of 35,400 BOEPD; production net after royalties was 28,198 BOEPD, up 7% year over year. Sales were 27,902 BOEPD, up 6%. Colombia production growth was driven largely by Acordionero and other development activity.
- Operating expenses rose 29% in Q2 to $35.1 million; expenses per BOE rose 21% to $13.81. Management cited field-agreement renegotiation payments, power, equipment rental and accelerated maintenance, mainly at Acordionero. Transportation expense per BOE fell 5% to $2.57.
- H1 cash from operating activities was $130.9 million, versus $67.5 million. Investing activities used $166.3 million, primarily for $157.1 million of property, plant and equipment additions. Financing provided $139.7 million. Cash, cash equivalents and restricted cash ended H1 at $130.9 million.
Balance sheet and liquidity
- At June 30, 2018, cash and cash equivalents were $125.8 million; current assets were $302.4 million and current liabilities $169.4 million.
- Long-term debt carrying value was $398.1 million, comprising $300 million of 6.25% senior notes due 2025 and $115 million of 5.00% convertible notes due 2021, net of unamortized issuance costs. The revolving credit facility was undrawn after repayment of $153 million during H1.
- The revolving facility had a stated $300 million borrowing base, subject to lender redetermination; the next review was due no later than November 2018. The company reported compliance with financial and operating covenants at quarter-end.
- Management said cash, operating cash generation and credit-facility capacity were expected to support 2018 plans, assuming current oil-price trends and production levels. All cash and cash equivalents were held outside Canada and the United States and generally were not available for domestic or head-office use without repatriation; withholding taxes could apply.
Changes, outlook, risks and unusual items
- In February 2018, the company issued $300 million of 6.25% senior notes due 2025, using net proceeds primarily to repay its revolving credit facility. Interest expense doubled to $7.4 million in Q2 from $3.3 million a year earlier.
- The revised 2018 capital budget is $305–325 million: $130–135 million for development, $80–90 million for exploration, $75–80 million for facilities and $20 million for seismic and studies. The plan includes 30–35 gross wells overall and is expected to be fully funded from operating cash flows. Management expanded development spending by $15–30 million for Ayombero appraisal, Costayaco activity and two Acordionero wells accelerated from 2019.
- Q2 included a $14.5 million commodity-derivative loss, partly offset by an $11.6 million unrealized gain on PetroTal shares; total financial-instrument loss was $4.8 million. H1 financial-instrument loss was $11.7 million. Commodity hedges covered 10,000 bopd for July–December 2018 through swaps and participating swaps; no 2019 commodity hedges were outstanding at quarter-end.
- H1 income tax expense was $53.8 million and the effective tax rate was 58%, primarily reflecting Colombian taxes and deferred tax expense related mainly to excess tax depreciation over accounting depreciation.
- Gran Tierra disclosed ongoing discussions with Colombia’s National Hydrocarbons Agency over whether certain transportation costs may be deducted in calculating an additional royalty. Potential compensation could be up to $52.8 million; no amount was accrued because management did not consider a loss probable. Letters of credit and other credit support totaled $69.8 million.
- Operational risks include oil-price volatility, production and transport disruption, Colombian political, geographic and weather conditions, exploration outcomes and execution of development plans. Three ESP failures affected Q2 production, and the Tonga-1 exploration well was plugged and abandoned after failing to find commercial hydrocarbons. Management reported no material change to the risk factors in its 2017 Form 10-K.
- The company adopted ASC 606 in 2018; adoption did not affect financial position, results or cash flows. Management reported effective disclosure controls and no material change in internal control over financial reporting during the quarter.
Most important facts for investors to verify
- Whether production growth and the higher oil-price environment persist, and whether royalties and operating costs continue to rise.
- Whether the $305–325 million capital program is delivered on budget and funded as planned, including facility expansion and exploration results.
- Debt-service capacity, covenant headroom and the outcome of the November 2018 borrowing-base redetermination; also consider the geographic availability of cash.
- Potential exposure and timing of the ANH royalty-cost dispute, which carries a disclosed maximum estimate of $52.8 million but no recorded accrual.
- Commodity-hedge economics and the impact of derivative marks and settlements on reported earnings and cash flow. Funds flow from operations, EBITDA and operating netback are non-GAAP measures and may not be comparable across companies.