During the first half of 2011, Lone Pine completed four vertical wells that had average initial 24-hour production rates of 9 MMcf/d. The results from these four wells bring Lone Pine’s average 24-hour initial production rates from its Nikanassin resource play program to 11 MMcf/d. Through production log information relative to the stacked-pay intervals, the Company has identified specific zones for which it plans a horizontal drilling program to isolate completions in the most productive intervals. Lone Pine’s first horizontal test had a 24-hour initial production rate of 6.4 MMcf/d from a single interval. This first horizontal well was drilled with a 2,200 foot lateral and completed with seven fracture stimulation stages. The well was not drilled to planned specifications of a 4,000 foot lateral and 14 fracture stimulation stages due to slower than expected drilling rates and operational time constraints. The Company is encouraged by the first horizontal well result which has a stabilized 90-day average production rate of approximately 3.2 MMcf/d and intends to further its near term horizontal efforts primarily through identified re-entry candidates.
Second Half 2011 Guidance
The following guidance is subject to all the cautionary statements and limitations described below and under the caption “Forward-Looking Statements”.
Prices for Lone Pine’s products are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic and political conditions, consumer product demand, weather, and other substantially variable factors. The cost of services and materials needed to produce Lone Pine’s products are also determined by prevailing market conditions, both regional and worldwide. These factors are beyond Lone Pine’s control and are difficult to predict. In addition, prices received by Lone Pine for its liquids and gas production may vary considerably due to differences between regional markets, transportation availability, and demand for different grades of products. Lone Pine’s financial results and resources are highly influenced by this price volatility.Estimates for Lone Pine’s future production are based on assumptions of capital expenditure levels and the assumption that market demand, prices for liquids and gas, and the cost of required services and materials will continue at levels that allow for economic production of these products. The production, transportation, and marketing of liquids and gas are complex processes that are subject to disruption due to transportation and processing availability, mechanical failure, human error, and meteorological events (including, but not limited to severe weather, hurricanes, and earthquakes). Lone Pine’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, Lone Pine can give no assurance that its future results will be as estimated. Lone Pine has a 2011 exploration and development capital budget of US$222 – US$232 million, which includes the spending of US$115 – US$125 million in the second half of 2011. The second half capital program will be focused on the Company’s Evi light oil property and the Nikanassin resource play. Highlights from the second half of the 2011 capital program includes the following:
- Allocate 60% of the capital program to Evi where the Company intends to drill 25 gross (25 net) horizontal wells all targeting the Slave Point light oil resource and complete an additional 6 gross (6 net) wells that were drilled prior to spring break-up.
- Complete expansion of the Evi oil battery and initiate waterflood pilot project.
- Intend to drill 3 gross (3 net) wells targeting the Nikanassin resource play and complete an additional 2 gross (1.5 net) wells as vertical multizone completions that were drilled prior to spring break-up.
- Initiate the first high impact exploratory test well in the Liard Basin with a re-entry on the Muskwa shale resource play to prove up the Company’s large acreage position in the area.
|Average Net Sales Volumes||98 - 102 MMcfe/d (24% oil and 1% NGLs)|
|Average Working Interest Sales Volumes||108 - 112 MMcfe/d (24% oil and 1% NGLs)|
|Natural Gas Price Differential (Henry Hub)||US$0.50 – US$0.70 per MMBtu|
|Crude Oil Differential (WTI)||US$6.00 – US$9.00 per Bbl|
|NGL Realization (WTI)||55% - 65%|
|Royalty Rate||7.0 – 9.0 %|
|Net Production Expense||US$1.50 – US$1.60 per Mcfe|
|Working Interest Production Expense||US$1.40 – US$1.50 per Mcfe|
|General & Administrative Expense (1)||US$0.35 – US$0.45 per Mcfe|
|DD&A (2)||US$2.40 – US$2.60 per Mcfe|
|Capital Expenditures||US$115 – US$125 million|
|(1) Includes stock-based compensation.|
|(2) Based on SEC estimated proved reserves.|
|Natural gas swaps:|
|Contract volumes (MMBtu/d)||30,000||25,000|
|Weighted average price (US$ per MMBtu)||$||4.85||5.09|
|Contract volumes (Bbls/d)||-||1,000|
|Weighted average price (US$ per Bbl)||$||-||102.28|
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