Our results in 2015 reflect the importance of being in the right rock. Despite weak prices, our top tier Montney assets delivered meaningful production and cash flow growth. We drilled longer wells and optimized completions to increase recovery and returns on developing this condensate-rich resource.
Proving up our oil shale resources was setback as Red Leaf and Total delayed their first commercial-scale capsule by two to three years. As they re-engineer the capsule design to be profitable at US$55-$60/bbl, we high-graded our portfolio. We relinquished the rights to our Wyoming acreage, deferred work in Saskatchewan and acquired a new project in the Kingdom of Jordan. Early work suggests this project might have the best rock and right scale to be among the top oil shale resources in the world.
For 2016, our capital program will remain restricted to maintain liquidity. We are participating in additional wells on our Montney acreage selectively. At Antler, we are optimizing wells and our pilot waterflood to incrementally grow production. Limited capital will be invested to evaluate our Jordanian oil shale project and possible development. Lastly, our public and government relations work will continue in Quebec to achieve social acceptability for our Utica shale discovery.
- Recognized as top publicly traded emerging producer by the Explorers and Producers Association of Canada for 2015
- Cash flow from operations of $9.78 million and average daily production of 1,582 boe/d for the year
- Corporate total gross proved plus probable reserves of 12.9 MMboe with a before income tax NPV-10% of $119.34 million
- Kakwa development continued with joint venture facility expansion and extended-reach horizontals using optimized completions
- Rationalized oil shale portfolio with new MOU for acreage in Jordan and terminated agreement for Wyoming acreage
We spud the first well at Kakwa four years ago this February.
Within the Montney fairway covering over 50,000 square miles, we targeted a sweet spot that was between underlying reefs, where condensate rates were likely to be 50 bbls/MMcf or better, the reservoir sufficiently overpressured and not too deep that drilling would be too expensive. Due to the premium value, condensate production rates were very important as natural gas was below $3/Mcf.
The discovery well, 13-17, tested at almost 140 bbls/MMcf of condensate and subsequent wells have produced at similar or higher rates over the last two years. Currently averaging about 180 bbls/MMcf, our rates are in line with our competitors in the vicinity and endorse our ideas that we are in the right rock.
Although condensate rates have been high, payouts with existing recoveries have been challenged by lower prices. In 2015, we made material efficiency gains by optimizing completions and drilling longer wells.
The new completions use a sliding sleeve system that discretely places frac treatments and places them closer together. This is supposed to increase the stimulated reservoir and the volume of gas and condensate produced. The longer horizontals allow us to place more frac treatments at a lower marginal cost. The combination of the longer wells and more effective completions should translate into a higher recovery at a lower overall cost.
Early indications are positive. On section 25, our three recent wells have horizontals averaging 2200m and new completions. We have one well on this section drilled in 2013 that has a horizontal of 1200m using a more dated completion design. Initial production rates over the first thirty days for the newer wells are almost 75% higher and the best estimate of Expected Ultimate Recoveries, as evaluated by our reserve engineers, are almost double at one million boe. Drilling costs per metre of horizontal for the three newer wells are about 40% lower, averaging $1,800/m. Our last well, 03-18, has a horizontal of 2900m and an estimated cost of $1,700/m. We hope to continue this trend of longer horizontals and lower costs with future wells this year.
In addition to drilling longer wells at a lower cost, we could drill more wells than initially planned on the same acreage. The lack of pressure communication between frac treatments, thus far, implies spacing between wells can be reduced further, down to 200m. This means that on our 16 section joint venture block we now estimate there are over 75 gross locations remaining, of which 90% have horizontals of over 2200m.
Based on the results and progress on our joint venture acreage, our offsetting seven net sections could be just as prospective. It has the potential to triple our net locations from 19 above to 58. As the land is held till 2021, we are conserving capital and monitoring the activity around us, including two wells that were recently tied-in.
Oil Shale Mining
While much less mature than our Montney assets, our oil shale assets, particularly the acreage in Jordan, are orders of magnitude larger. They are important to our business plan of capturing large scale and high quality resources early.
Like other large scale oil projects, such as the oil sands, they require higher prices. We are improving the chances for development in the ‘lower for longer’ price environment by high grading projects and focusing on acreage with the right rock. This right rock for oil shale is rich, thick, areally extensive and reasonably close to surface to ensure mining costs are not too expensive.
Our new project in Jordan, covering over 140 square miles, met these criteria. Core we took last fall fits with existing core data, indicating average yields of 25 gallons/ton over a 40m interval. As noted last fall, we are benchmarking against the Green River shale in Utah, the largest oil shale resource in the world, where we estimate the average yield on a selective sweet spot is 21 gallon/ton over an 18m interval.
We are in the very early stages of assessing this resource, and the ore, specifically its suitability for retorting and processing the products from the process – water, sulphur, oil, gas and other minerals. This work is essential to evaluating commercial development under Red Leaf’s EcoShale process and other existing retorting technologies.
The work by Red Leaf to make the EcoShale process profitable at lower prices is encouraging, both from our perspective as a licensee and a shareholder. As detailed in their fourth quarter 2015 report, Red Leaf’s CEO commented that the move from indirect heating, using a series of pipes to circulate heat in the capsule, to direct heating, injecting hot gas directly into the capsule, has enabled them to greatly simplify design and reduce material and construction costs. We are looking forward to the results from the next phase of engineering for the associated oil processing and recovery plant due later this year.
Operational & Financial
The commissioning of the central facility expansion at Kakwa contributed to a 47% increase in production over the prior year to 1,582 boe/d in 2015. Kakwa represented just over 75% of Company volumes in the year compared to just under 50% last year.
Despite the higher production volumes, materially lower realized prices resulted in cash flow from operations of $9.78 million, down from $14.89 million in 2014.
Net income for the year was impacted by impairment charges of $69.6 million. Of this amount, about 40% relates to the carrying value of producing assets which declined due to lower prices, 40% relates to the impairment of its exploration assets, primarily Quebec due to external views on the risk of new legislation, and the remainder relates to the further impairment of our investment in Red Leaf.
Consistent with 2014, Kakwa represented approximately 90% of capital investment that totaled $20.52 million in the year.
Capital for 2016 will be restricted to maintain financial flexibility in the current pricing environment.
Our limited investment at Kakwa could see net declines in production but will help maintain producing reserves that underpin the credit facility. This will build on the successful optimization work last year and is essential to improving our returns. While the economics of the Montney at Kakwa are top decile, we are mindful of over capitalizing this asset with long payouts and our existing balance sheet capability.
Investing in our Jordanian oil shale assets will not add reserves or production in the near term; but we believe the work is warranted relative to its prospectivity.
We are still optimistic about our Quebec Utica shale discovery and eventually resuming the work to prove commerciality.
This has taken considerably longer than we hoped. Our sustained optimism is in part due to the growing coalition of support and the government’s commitment to release its ten-year energy policy and hydrocarbon legislation this spring. Though there have been delays to the original timeline, the government has, for the most part, remained on track.
We are also optimistic that this could be better than we have expected. A Canadian Energy Research Institute report notes that the Utica shale could have the second lowest supply costs for Quebec at C$3.72/Mcf, behind only the Marcellus shale. More interesting are the results from the dry gas window of the same Utica shale in Ohio and Pennsylvania. The US EIA estimates Utica production has grown to approximately 3 Bcf/d in nearly three years and recent wells are reported testing at IP30s of over 30 MMcf/d. We are confident that our acreage has the potential to deliver similar results.
President and Chief Executive Officer