Gran Tierra Energy (Nasdaq:GTE)

Gran Tierra Energy is a conventional oil producer, primarily in Columbia.  97% of their 2013 was liquids, very little gas.  In Columbia, they have interests in 22 blocks, 5 of which are producing.  75% of their 2013 production came from the single Chaza block, in which they have 100% interest.  Their production contracts for Chaza expire after 2034.

Revenue

GTE pays royalties, as a percentage of oil produced on a sliding scale according to production volume. The royalty levels are a bit complex (p12), and are different for different fields on each block.  Roughly 25% in 213.  Revenue stated is NAR (Net After Royalties).  Since there's no complex PSC, it is easier to estimate their sensitivity to oil prices - production retained (after royalties) will be the same each year assuming constant production levels.

On average, their oil is sold at a discount to WTI, due to transport costs.

Reserves

Have risen steadily over the years:

Production Costs

Depreciation, Depletion & Armortisation (DDA) forms a high proportion of their costs.  Probably because they use the full cost method to account for exploration costs, where failed exploration efforts are capitalized, then later amortized during production.

In 2013, 49% of oil was sold to a customer requiring trucking 15,000 km away.  The trucking costs were deducted from revenue in 2013, but in previous years were recorded as revenue and expenses (increasing revenue but decreasing margin).

For the spike in 2012 operating expense: $29.3m of it was due to to new pipeline transportation costs of $3.77/BOE and the above mentioned trucking costs.

Other Financials

At the end of 3Q2014, they had $360m cash with no debt.

Planned capex for Q42014 is $220m, and 2015 is $315m.

Management stated they have not taken out any credit lines for contingencies.

Could they survive if oil fell to $40?

• Its reasonable to remove Depreciation, Depletion & Armortisation from the costs to get 'cash costs':  "The cost of repairs and maintenance is charged to expense as incurred.".  So most capex in CFI should be for new exploration or production, not maintenance.  
• They sell at a discount to WTI.  Due to a regional differential, and trucking.  In 2013 the average price received was $90.61 versus $97.97 WTI.  In the first 9 months of 2014, the average price received was $89.41 vs $99.61 WTI.  Lets say an discount to WTI of $7-10.
• So with cash costs between $20 and $26 in the past 5 years, they would generate $4 to $10 cash per barrel for WTI $40.  While making losses on the income statement.

What would its PE be at $60-70 WTI?

• Extrapolating production for the first 9 months of 2014, with WTI $70, and selling oil at a discount of $9, I get EPS of 12c. 
• We should probably factor in some growth, as production has risen 30% in the 4 years from 2010 to 2014 (CAGR of 7%), and reserves have risen  steadily over the past 6 years.

Conclusion

Low cost of production and excellent financials make this a good play for an oil price turnaround.  But the nature of their industry and where they operate makes this a speculative stock.  No more than 2% of my portfolio if I buy.  Still too expensive right now.