Gran Tierra Energy Inc. — 2018 Form 10-K
Reporting period: Fiscal year ended December 31, 2018. All amounts are U.S. dollars unless noted. Gran Tierra is an oil and gas exploration and production company operating in Colombia; all year-end proved reserves and 2018 revenue and other income were attributable to Colombia.
Business context and reporting period
The company expanded its Colombian interests during 2018, spending $53.2 million on acquisitions, including interests in PUT-1, VMM-2 and the Alea blocks. It drilled 5 exploration and 23 development wells and incurred $347.1 million in capital expenditures. Acordionero, Costayaco and Moqueta together represented 82% of 2018 production and 89% of proved reserves.
Financial and operating metrics
| Metric | 2018 | 2017 |
|---|---|---|
| Oil and natural gas sales | $613.4 million | $421.7 million |
| Net income (loss) | $102.6 million | ($31.7 million) |
| Operating cash flow | $284.5 million | $189.6 million |
| Funds flow from operations (non-GAAP) | $306.4 million | $220.2 million |
| EBITDA (non-GAAP) | $376.7 million | $182.5 million |
| Capital expenditures | $347.1 million | $251.0 million |
| Cash and cash equivalents at year-end | $51.0 million | $12.3 million |
| Working capital | $33.1 million surplus | $11.7 million deficiency |
- Sales volumes rose 8% to 28,717 BOEPD; production NAR rose 8% to 29,053 BOEPD. Average realized sales price increased 35% to $58.53 per BOE, while operating netback increased 42% to $41.85 per BOE.
- Operating expenses increased 27% to $111.3 million; workover expenses increased 56% to $34.4 million. Management attributed higher per-BOE operating costs partly to power generation and equipment rental constraints at Acordionero, and higher workovers to pump failures associated with unreliable power.
- DD&A was $197.9 million, up 51%. No asset impairment was recorded in 2018, compared with $1.5 million in 2017. Income tax expense was $48.9 million; the effective tax rate was 32%.
- Proved reserves declined 8% to 54.3 MMBOE. Proved undeveloped reserves were 17.3 MMBOE, down from 19.6 MMBOE; the company converted 12.9 MMBOE of prior-year undeveloped reserves to developed status.
Debt, liquidity and cash flow
Year-end debt comprised $300 million of 6.25% senior notes due 2025 and $115 million of 5.00% convertible notes due 2021. The revolving credit facility had a $300 million borrowing base and no amount drawn at year-end. The company reported net debt of approximately $366 million and net debt to EBITDA of 1.0 times. It was in compliance with credit-facility covenants. Cash, cash equivalents and restricted cash totaled $54.3 million; 99% of cash and cash equivalents was held outside Canada and the United States.
Operating cash flow was below capital expenditures; financing included $288.1 million of net proceeds from senior notes. Cash and restricted cash increased $27.6 million during the year. The company repurchased 4.8 million shares for $12.7 million. It has not paid dividends and does not anticipate paying them for the foreseeable future.
Material changes and quarterly results
- Revenue increased 45% year over year, reflecting higher sales volumes and realized prices. Average Brent prices rose 31% for the year.
- Production growth was driven by drilling and workover activity, especially at Acordionero and Costayaco. Royalties rose to 20% of working-interest production from 17%, reflecting higher oil prices and high-price royalty triggers.
- Fourth-quarter sales were $136.6 million and the company recorded a net loss of $10.8 million, compared with net income of $75.3 million in the third quarter and a net loss of $40.8 million in fourth-quarter 2017. Management’s quarterly reconciliation identifies lower oil prices as a major sequential headwind.
- In February 2018, the company issued $300 million of senior notes and used proceeds to repay its revolving-credit borrowings and for general corporate purposes.
Outlook, risks and contingencies
- The revised 2019 capital budget is $320–$340 million: $130–$135 million for development, $80–$85 million for exploration, $85–$90 million for facilities and $25–$30 million for seismic and studies. Management expects the program to be funded by operating cash flow; the filing notes this depends in part on Brent prices of $65 per barrel or higher.
- After year-end, Gran Tierra announced an agreement to acquire interests and operatorship in Suroriente, Putumayo-8 and Llanos-5 for $104.2 million, subject to adjustments and customary conditions.
- The company’s largest exposures include oil-price volatility, Colombia-specific political, regulatory and security risks, community disruptions, permitting and environmental obligations, transportation constraints, foreign exchange movements and concentration in a few fields. Two customers were significant in 2018.
- Gran Tierra and Colombia’s hydrocarbons agency (ANH) are discussing whether certain transportation costs may be deducted in calculating high-price royalties. The potential payment could be up to $56.3 million; no liability was accrued because management did not consider a loss probable.
- There is an apparent difference within the filing’s 2019 outlook discussion on the share of capital allocated to facilities and the portion directed to Acordionero expansion. Investors should confirm the definitive revised budget allocation.
- The company reported unqualified audit opinions on its financial statements and internal control over financial reporting. It adopted ASC 606 without a material financial-statement impact.
Important facts for investors to verify
- Whether 2019 operating cash flow can fund the $320–$340 million capital program under actual oil prices, production and working-capital conditions.
- Completion, final purchase price and financing impact of the $104.2 million post-year-end Colombian asset acquisition.
- Resolution and potential financial impact of the ANH high-price royalty dispute, including the unaccrued amount of up to $56.3 million.
- Progress in reducing Acordionero capacity and power constraints, workover costs and transportation exposure.
- Proved-reserve changes and the economics of converting undeveloped reserves, given the 8% year-over-year proved-reserve decline.
- Debt-service capacity and covenant headroom, including the facility’s borrowing-base redetermination and the 2021 convertible-note maturity.