TSX Venture Exchange: PRY
CALGARY,
Aug. 15, 2013 /CNW/ - Pinecrest
Energy Inc. ("Pinecrest" or the "Company") is pleased to announce
that it has filed on SEDAR its unaudited financial statements and
related Management's Discussion and Analysis ("MD&A") for the
three and six months ended June 30,
2013. The statements will be available for review at
www.sedar.com or www.pinecrestenergy.com.
Second Quarter 2013 Achievements
Pinecrest is pleased to provide the following
update on our achievements during the three months ended
June 30, 2013:
- Achieved average production of 3,615 boe per day (97%
light oil), an increase of 23% from 2,951 boe per day for the three
months ended June 30, 2012;
- Increased funds from operations to $16.4 million ($0.08 per basic and $0.07 per diluted shares outstanding) compared to
$15.9 million ($0.07 per basic and diluted shares outstanding)
for the quarter ended June 30,
2012;|
- Generated a top quartile field netback of $60.36 per boe for the quarter ended June 30, 2013;
- Completed the conversion of its third (Loon Project #1)
waterflood project and started injecting water in the latter
part of March 2013. Subsequent to
June 30, the Company commenced
injection at two more waterflood projects (Red Earth #1 and Evi #3)
which brings the active waterflood count to five (four Company
operated);
- Reduced average cost to drill, complete, equip and tie-in to
$3.8 million per well.
Pinecrest has been continuously refining its well design and has
most recently achieved a cost savings of approximately $1.4 million per well, compared to the same
period in 2012; and
- Completed the installation of compression and gas
pipeline required to conserve solution gas from the Otter and
Evi fields.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
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June 30 |
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Three months
ended |
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Six months ended |
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2013 |
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2012 |
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% Change |
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2013 |
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2012 |
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% Change |
FINANCIAL |
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Petroleum and natural gas sales |
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29,573 |
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22,426 |
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32 |
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63,402 |
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50,617 |
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25 |
Funds flow from operations
(1) |
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16,374 |
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15,866 |
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3 |
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37,753 |
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36,140 |
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5 |
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Per share - basic |
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$0.08 |
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$0.07 |
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14 |
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$0.17 |
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$0.17 |
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- |
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Per share - diluted |
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$0.07 |
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$0.07 |
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- |
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$0.16 |
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$0.15 |
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7 |
Net income |
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4,196 |
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9,076 |
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(54) |
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7,912 |
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15,023 |
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(47) |
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Per share - basic |
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$0.02 |
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$0.04 |
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(50) |
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$0.04 |
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$0.07 |
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(43) |
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Per share - diluted |
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$0.02 |
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$0.04 |
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(50) |
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$0.03 |
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$0.06 |
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(50) |
Capital expenditures |
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2,331 |
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9,476 |
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(75) |
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55,875 |
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75,500 |
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(26) |
Net debt and working capital deficit
(2) |
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120,774 |
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6,661 |
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1,713 |
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120,774 |
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6,661 |
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1,713 |
Common Shares Outstanding |
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Weighted average - basic |
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216,437 |
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214,158 |
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1 |
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217,071 |
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206,622 |
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5 |
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Weighted average - diluted |
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229,474 |
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241,997 |
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(5) |
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233,977 |
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236,890 |
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(1) |
OPERATING |
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Number of days |
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91 |
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91 |
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181 |
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182 |
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Production |
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Crude oil (bbls/d) |
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3,467 |
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2,934 |
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18 |
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3,855 |
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3,140 |
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23 |
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Natural gas (mcf/d) |
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561 |
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53 |
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959 |
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418 |
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44 |
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850 |
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NGL (bbls/d) |
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54 |
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8 |
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575 |
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38 |
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7 |
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443 |
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Barrels of oil equivalent
(boe/d-6:1) |
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3,615 |
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2,951 |
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23 |
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3,963 |
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3,155 |
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26 |
Average realized
price(3) |
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Crude oil ($/bbl) |
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92.40 |
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83.83 |
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10 |
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90.05 |
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88.41 |
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2 |
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Natural gas ($/mcf) |
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3.55 |
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1.58 |
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125 |
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3.22 |
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1.77 |
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82 |
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NGL ($/bbl) |
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48.17 |
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48.81 |
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(1) |
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47.06 |
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60.48 |
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(22) |
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Barrels of oil equivalent ($/boe- 6:1) |
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89.90 |
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83.51 |
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7 |
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88.40 |
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88.16 |
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- |
Netback per boe
($)(1) |
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Petroleum and natural gas sales |
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89.90 |
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83.51 |
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7 |
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88.40 |
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88.16 |
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- |
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Realized gain (loss) on derivative
financial
instruments |
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(3.59) |
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2.02 |
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(278) |
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(2.43) |
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(0.17) |
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1,329 |
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Royalties |
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(7.23) |
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(6.48) |
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12 |
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(6.67) |
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(6.67) |
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- |
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Production and transportation expenses |
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(22.31) |
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(15.08) |
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48 |
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(20.45) |
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(14.41) |
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42 |
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Operating netback |
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56.77 |
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63.97 |
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(11) |
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58.85 |
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66.91 |
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(12) |
Wells drilled |
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Gross |
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- |
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1 |
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(100) |
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12 |
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10 |
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20 |
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Net |
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- |
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0.9 |
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(100) |
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11.3 |
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9.7 |
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17 |
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Success rate (%) |
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- |
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100 |
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- |
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100 |
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100 |
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- |
(1) |
Non-GAAP measures |
(2) |
Includes $3.7 million liability (2012 - $2.8 million
asset) related to the fair value of derivative financial
instruments |
(3) |
Before the effects of commodity price derivative
contracts |
WATERFLOOD UPDATE
The Company continues to see encouraging results
from the two previously announced operated waterflood schemes, Evi
- Project #2 (December 20, 2012
commencement) and Loon - Project #1 (March
21, 2013 commencement).
Both schemes have been on continuous injection
since start-up with voidage replacement ratios (VRR) monitored and
adjusted continuously as fluid production from the schemes steadily
increases. The offsetting producing wells in both schemes
have been on continuous production with the exception of Evi -
Project #2, in which a routine bottomhole pump failure occurred
during breakup causing the offsetting producing well to be down for
27 days (which also necessitated an injection rate
reduction). As indicated, production continues to incline and
water cuts are stable to decreasing as the reservoir is being
re-pressurized.
The following table outlines oil production
rates and water cuts for the project:
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EVI Project #2 |
Loon Project #1 |
Oil Production
per Calendar
Day (bbls) |
Water Cut |
Cumulative
VRR(1) |
Oil Production
per Calendar
Day (bbls) |
Water Cut |
Cumulative
VRR(1) |
April |
130 |
64.6% |
0.42 |
94 |
27.4% |
0.06 |
May |
138 |
64.0% |
0.47 |
99 |
33.8% |
0.12 |
June |
190 |
61.1% |
0.47 |
127 |
35.7% |
0.17 |
July |
208 |
60.9% |
0.53 |
164 |
31.2% |
0.21 |
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(1) Voidage Replacement Ratio |
Response time and production increases are
within Company expectations. As production continues to
increase and the required voidage replacement also increases, the
Company anticipates further gains in production rates from these
and future Pinecrest operated schemes in the Greater Red Earth
area. At year-end, Pinecrest's active waterflood count will
be eight (seven operated) and the Company has identified four
schemes for implementation in 2014.
Subsequent to the quarter, water injection
commenced in late July on the Company's operated projects at Evi
#3, and Red Earth #1. Injection at both these projects has
been continuous and is within the projects designed instantaneous
and maximum VRR target of 2:1. Response from these schemes is
anticipated in late Q3 to early Q4 2013.
Additionally, field facility construction and
injection well conversions are under way at Pinecrest's three
remaining operated waterflood projects in Otter. The Company
remains on track for these schemes to begin injection subject to
Alberta Energy Regulator (AER) approval, late in the third quarter
of 2013, with production response expected late Q4 2013 to Q1
2014.
OPERATIONS UPDATE
As planned, there was no drilling or completion
activity undertaken during the second quarter.
Pinecrest drilled a total of 11 gross (10.3 net) horizontal Slave
Point wells in the first quarter of 2013 and all were placed on
production by April 8, 2013. The
average cost to drill, complete, equip and tie-in the wells drilled
in the first quarter of 2013 was $3.8
million per well, a $1.4
million per well savings as compared to the first quarter of
2012.
The first quarter 2013 well costs represent a
significant reduction to Pinecrest's previous cost structure and
are a function of Pinecrest's modified well design and overall cost
reductions in the industry. Additionally, and as previously
announced, Pinecrest will be moving forward with its plans to
implement a proposed change to its completion method on future
wells. Our industry analysis of the Slave Point formation in
the Greater Red Earth area confirm the superior performance of the
open-hole packer style of completion. We are excited to
implement this new system and look forward to achieving further
cost reductions as well as reporting our results in the latter half
of the year.
Persistent wet weather has delayed the
commencement of the Company's third quarter capital program and
increased unscheduled downtime due to limited access.
Subsequent to the end of the second quarter drilling operations
resumed on August 8, 2013 which is a
full month later than originally planned.
Production for the second quarter of 2013
increased by 23% to 3,615 boe per day from 2,951 boe per day for
the corresponding period in 2012. Production rates increased
as a result of the Company's successful drilling program along with
positive early responses from our waterfloods. Production in
the second quarter of 2013 decreased by 16% from 4,315 boe per day
in the first quarter of 2013. This decrease is a result of normal
reduced activity levels during spring break up, natural production
declines, and unscheduled downtime. Natural gas and natural
gas liquids production (NGL's) increased significantly in the
second quarter of 2013 as a result of the commissioning of a new
compressor and sales gas line earlier in the year.
Pinecrest's commodity mix remains very attractive at 97% oil and
NGL's.
The Company experienced an increase in operating
costs associated primarily with the implementation and operation of
the waterflood schemes. Once the initial injection facilities
have been completed, the Company is focused on reducing operating
costs associated with each waterflood installation.
Initially, water and power for the injection facilities is supplied
via temporary means. Water is trucked to each site and power
is supplied using rental generators and diesel fuel. Field
electrification is now underway at the Red Earth and Loon
fields. By the end of Q4 2013, injection water will be
delivered by pipeline to all but one of the Company's injection
schemes, eliminating significant trucking costs.
The Company expects that these initiatives and
others currently being implemented will have a positive impact on
lowering the Company's overall operating costs. In addition,
costs associated with emulsion trucking will be reduced as the
majority of the wells have now been tied into central production
facilities. Future emulsion hauling will be subjected to a
competitive bidding process.
For the balance of 2013, Pinecrest is targeting
total operating expenses (production and transportation costs) of
approximately $22 per boe. The
implementation of all of Pinecrest's operating cost initiatives
will not be fully realized until Q1 2014.
Current production is approximately 3,200 boed,
with approximately 300 boed shut in due to field conditions.
The Company expects to average 3,100 - 3,200 boed for the third
quarter, while the Company performs a mid-August battery turn
around and converts seven producing wells to injectors, all
affecting production. The Company expects to spend approximately
$16.0 million in capital for the
quarter.
OUTLOOK - GREATER RED EARTH AREA, ALBERTA
Pinecrest commenced operations in early 2011
with a minimal production base and has organically grown the
Company, almost exclusively, through the drill bit by way of an
aggressive capital program focused on the large oil in place Slave
Point formation in the Greater Red Earth area. As a result,
the corporate decline rate has, at times, mimicked that of a
horizontal Slave Point oil well. On average, a Slave Point
horizontal oil well will experience a first year natural decline of
approximately 65%-70%, which is typical for all tight oil
reservoirs. With the licensing and implementation of the
seven operated waterfloods, the Company is now transitioning from a
high decline production base dominated by newly drilled horizontal
wells to a more stable, lower decline asset base. Pinecrest
entered 2013 with an estimated annualized monthly decline rate of
approximately 55% compared to an estimated current decline rate of
35% and it is expected that this overall decline rate will continue
to improve as more waterfloods are commissioned and as our existing
wells mature. This reduction in corporate decline rates
combined with improving capital efficiencies and a focus on
operating cost reductions, allows the Company to grow production
while spending significantly less capital in the upcoming
years. With the anticipated response of the remaining five
operated 2013 waterfloods, the Company expects to generate free
cash flow in calendar year 2014.
Since inception, Pinecrest has established
itself as one of the dominant interest holders in the high quality
Slave Point light oil resource play in the Greater Red Earth
area. The Company has over 400 net risked drilling locations
on its lands which contain an estimated 580 million barrels of
Discovered Oil Initially In Place (1)(2) as of
January 31, 2012 with very low
recovery to date. Sproule & Associates Ltd. conducted an
assessment effective as of January 31,
2012 (the "Assessment") of Pinecrest's Contingent Slave
Point Oil Resources(3) and has assigned the Company a
contingent resource Best Estimate(4)of 67.5 million
barrels using, a 13% recovery factor and based on a drilling
density of 4 wells per section. The Company believes that
significant upside potential, over and above the contingent
resource assignment, can be achieved through further infill
drilling and water flooding. The Assessment was prepared in
accordance with definitions, standards and procedures contained in
the Canadian Oil and Gas Evaluation Handbook and NI
51-101(5).
This resource capture is consistent with the
Company's stated strategy of focusing its capital and resources on
large light oil accumulations with high netback production, long
term upside and the ability to increase recovery factors through
the application of horizontal wells, multi-stage fracture
stimulations and implementing waterflood recovery schemes.
Analogous Slave Point waterfloods in the immediate area have proven
to be very effective and have been assigned incremental recovery
factors ranging between 50 and 100 percent over primary
recovery.
For the balance of 2013, Pinecrest will execute
an integrated capital program that will include selectively
drilling wells for primary production (five wells per section) to
set up future waterflood schemes and finish construction of
facilities and pipelines at Otter to enable the commencement of
injection on an additional three operated waterflood schemes.
INCENTIVE PLAN
In accordance with Pinecrest adopting a
restricted share incentive plan as approved at the June 5, 2013 Annual and Special meeting of the
shareholders, the Board of Directors have approved a total grant of
5,026,500 incentive shares, of which 3,300,000 will be granted to
directors and officers of the Company upon lifting of Pinecrest's
blackout period, anticipated to be August
20, 2013.
Notes
(1) |
"Discovered Oil Initially InPlace" or "DOIIP"means that
quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations prior to production. The
recoverable portion of discovered petroleum initially in place
includes production, reserves and contingent resources. There
is no certainty that it will be commercially viable to produce any
portion of these resources. |
(2) |
All DOIIP other than cumulative production, reserves and
contingent resources have been categorized as unrecoverable.
Pursuant to the Assessment, as at January 31, 2012, 9.1 mmbbl of
oil was classified as cumulative production and proved plus
probable reserves. |
(3) |
"Contingent Oil Resources" are those quantities of
petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations using established technology
or technology under development, but which are not currently
considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as
distance from existing production, economic, legal, environmental,
political, and regulatory matters or a lack of markets. It is also
appropriate to classify as contingent resources the estimated
discovered recoverable quantities associated with a project in the
early evaluation stage. |
(4) |
"Best Estimate" is considered to be the best
estimate of the quantity that will actually be recovered. It is
equally likely that the actual remaining quantities recovered will
be greater or less than the best estimate. If probabilistic methods
are used, there should be at least a 50 percent probability (P50)
that the quantities actually recovered will equal or exceed the
best estimate. |
(5) |
Please refer to the Company's March 22, 2012 press release for
additional details in respect of the Assessment. |
Advisory
The information in this press release
contains certain forward-looking statements. These statements
relate to future events or our future performance. All statements
other than statements of historical fact may be forward-looking
statements. Forward-looking statements are often, but not always,
identified by the use of words such as "seek", "anticipate",
"plan", "continue", "estimate", "expect", "may", "will", "project",
"predict", "potential", "targeting", "intend", "could", "might",
"should", "believe", "would" and similar expressions. In
particular, forward looking statements in this press release
includes, but is not limited to: Pinecrest's capital program and
2013 business objectives, Pinecrest's 2013 budget, oil recovery
rates, the effects of waterfloods on recovery factors, the
potential success of waterfloods in the Slave Point area, decline
rates and type curves for wells, production rates, effect of
operations initiatives, timing for implementation of operating cost
initiatives, exit rates for production and bank debt, downspacing
opportunities, the quantity of reserves, and projections of market
prices and costs. These statements involve substantial known and
unknown risks and uncertainties, certain of which are beyond
Pinecrest's control, including: the impact of general economic
conditions; industry conditions; regulatory approvals and permits;
changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are
interpreted and enforced; fluctuations in commodity prices and
foreign exchange and interest rates; stock market volatility and
market valuations; volatility in market prices for oil and natural
gas; liabilities inherent in oil and natural gas operations;
uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital,
acquisitions, of reserves, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; changes in
income tax laws or changes in tax laws and incentive programs
relating to the oil and gas industry; geological, technical,
drilling and processing problems and other difficulties in
producing petroleum reserves. Pinecrest's actual results,
performance or achievement could differ materially from those
expressed in, or implied by, such forward-looking statements and,
accordingly, no assurances can be given that any of the events
anticipated by the forward-looking statements will transpire or
occur or, if any of them do, what benefits that Pinecrest will
derive from them. Except as required by law, Pinecrest undertakes
no obligation to publicly update or revise any forward-looking
statements.
Statements relating to "reserves" or
"resources" are deemed to be forward-looking statements, as they
involve the implied assessment, based on certain estimates and
assumptions, that the resources or reserves described can be
profitably produced in the future.
The Corporation uses the following terms for
measurement within this press release that do not have a
standardized prescribed meaning under GAAP and these measurements
may differ from other companies and accordingly may not be
comparable to measures used by other companies. The terms "funds
from operations" and "operating netback" are not recognized
measures under the applicable GAAP. Management of the Corporation
believes that these terms are useful, in addition to profit and
loss and cash flow from operating activities as defined by GAAP,
for evaluating the Corporation's operating performance and
leverage. Funds from operations is expressed as cash flow from
operating activities before changes in non-cash working capital and
asset retirement expenditures. Operating netback is a measure of
operating margin used in capital allocation decisions. Pinecrest
defines operating netback as average realized price per BOE, less
royalties per BOE, less operating and transportation expenses per
BOE, plus any realized gain or loss per BOE on financial
instruments.
Certain information provided in this press
release in relation to the results of waterflooding Slave Point
reservoirs on lands in close proximity to the land in which the
Company has an interest, is considered analogous information under
National Instrument 51-101 - Standards of Disclosure for Oil
and Gas Activities. Such information is based on publicly
available information from governmental agencies and other industry
producers and has been provided to give an indication of possible
incremental recovery factors in the specified area. Other
than comparing such information to the Company's own limited
results in the specified area, the Company has not independently
confirmed the accuracy of this information. There is no
certainty that such incremental recovery factors will be obtained
of even if so obtained, whether such factors can be achieved on an
economic basis.
Barrels of Oil Equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion
ratio of 6MCF:1bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency
of 6:1,utilizing a conversion on a 6:1 basis may be misleading as
an indication of value.
Neither the TSX Venture Exchange nor its
Regulation Services Provider (as that term is defined in the
policies of the TSX Venture Exchange) accepts responsibility for
the adequacy or accuracy of this news release.
SOURCE Pinecrest Energy Inc.