CALGARY, March 25, 2014 /CNW/ - Yangarra ResourcesLtd. ("Yangarra" or the "Company") (TSX-V:YGR) releases its 2013 financials and reserves.
2013 Financial and Operating Highlights
During the year ended December 31, 2013 the Company completed the
following significant milestones:
-
Average daily production was 2,206 boe/d, a 15% increase from 2012.
-
Funds flow from operations were $26 million ($0.21 per share - basic), a
76% increase from 2012.
-
Earnings before interest, taxes, depletion & depreciation, amortization
and changes in commodity contracts ("EBITDA") was $27 million.
-
Operating costs, including $1.26/boe of transportation costs, were
$7.56/boe.
-
Operating netback of $36.18 per boe, a 42% increase from the $25.48 per
boe reported in 2012.
-
G&A costs of $2.06/boe, which represents an 18% decrease from 2012.
-
Royalties at 5% of oil and gas revenue.
- $1.2 million of realized hedging gains.
-
Fourth quarter 2013 production was 2,764 boe/d with funds flow from
operations of $8 million ($0.06 per share - basic).
-
Total capital expenditures were $47 million versus $19.8 million in
2012. With the equity raise late in 2013 the Company accelerated the
fourth quarter capital expenditures to $26 million.
-
As at December 31, 2013, the Company had a current bank debt,
subordinated debt and working capital deficit, excluding mark to market
on commodity contracts and flow-through share obligations, of $44.6
million compared to $36.3 million at December 31, 2012.
-
The annualized fourth quarter debt to cash flow ratio was 1.4 : 1.
Reserve Report Highlights:
-
Increased proved plus probable reserves by 39% to 17.5 million barrels
of oil equivalent and proved reserves by 32% to 9.4 million barrels of
oil equivalent.
-
Proved plus probable reserves, net present value discounted at 10% ("NPV
10") at December 31, 2013 was $251.1 million, an increase of 50%
compared to December 31 2012.
-
Replaced 2013 production by 283% on a proved basis and 614% on a proved
plus probable basis.
-
Achieved finding and development costs including changes in future
capital, of $14.07/boe ($8.18 excluding changes in future capital) on
proved plus probable reserves and $17.58/boe on proved ($15.25
excluding changes in future capital).
-
Generated a finding and development recycle ratio of 2.57 times on
proved plus probable reserves including changes in future capital (4.42
times excluding changes in future capital) based on the Company's 2013
operating netback of $36.18 per barrel of oil equivalent.
-
Reserve life index of 16.0 years on a total proved plus probable basis
based on the Company's December, 2013 production rate of 3,000 boe/d.
-
Future development costs (proved plus probable) of $125 million which is
2.5 times the 2014 capital budget.
-
Net Asset Value of $206 million as at December 31, 2013, which is $1.40
per common share.
Operations Update
During the first quarter of 2014 the Company drilled 6 gross (5.9 net)
wells in the Cardium formation. A total of 4 gross (3.9 net) wells were
put on production during the quarter with the final 2 (2.0 net)
expected to be on stream at quarter end. The Company experienced 11
days of shut-in production (approximately 1,200 boe/d) due to the
TransCanada pipeline rupture near Rocky Mountain House and an
additional 150 boe/d average for the quarter of Keyera curtailments at
other facilities. The Company expects first quarter production to be
approximately 2,800 boe/d and full year guidance remains at 3,200
boe/d. The Company will continue to drill through break-up as
conditions permit, with 6 gross (5.2 net) wells planned for the second
quarter.
President's Message to Shareholders
Yangarra is currently drilling its 71st horizontal well in Central Alberta. The experience gained by drilling
this many wells with the team we have put in place over the past four
years has been key to reducing costs to a point where we are top
decile in drilling and completions, operating costs and G&A costs. We
are currently concentrating on "oilier" targets in the Cardium and
Glauconite horizons where we have significant inventory. We also have
a large undrilled inventory in "gassier" Cardium, Glauconite and Rock
Creek zones that we will drill as natural gas prices continue to
improve. These "gassier" targets are extremely "liquids rich", however,
the "oilier" targets still command higher internal rates of return
(IRR). Half cycle IRR's in 2013 were 65%, re-cycle ratios were 2.57
(P+P including changes in future capital) in 2013 and annual production
growth is forecast to be 45% in 2014.
A recent farm-in was negotiated in which the Company added significant
acreage to its Cardium inventory. Yangarra has been active at crown
land sales and has been successful closing deals with industry to add
additional future drilling locations. The Company has added two future
drilling locations for every location drilled in each of the past four
years and we have visibility to do the same going forward.
Yangarra is focused on adding shareholder value and to properly gauge
this we have calculated full-cycle rates of return, presented below
which we believe is more indicative of value creation. All capital
costs for each year are included in this calculation including land,
infrastructure, geological work, etc. The chart shows the impact of
focusing on returns rather than focusing on growth.
According to Yangarra's 2013 year end engineering report the Company is
valued at $1.40 per share (2P (pre-tax) at PV 10, net of debt). The
financing late last year provided the necessary liquidity to achieve
the outstanding reserve additions generated by the Company in the
fourth quarter of 2013. There is significant additional intrinsic value
not booked in the reserve report in our 53,000 acres (including farm-in
acreage) of undeveloped Cardium and Glauconite land and for our 39,040
acre net Duvernay land position.
TD Bank recently opined that liquids rich Duvernay lands may be worth
$2,000 - $4,000 per acre in Pembina/Willesden Green which positions our
shareholders with great option value in this rapidly developing play.
Yangarra has recently retained the services of two experienced shale
professionals to develop the asset with plans in progress to drill a
vertical strata-graphic test well.
I would like to thank the shareholders for their support. I thank my
colleagues at Yangarra for their ongoing dedication to the development
of the Company. They have delivered seamless, reliable operations and
demonstrated their ability to quickly interpret, react and adapt to the
technical results of our development drilling efforts. I also wish to
take this opportunity to thank my fellow directors for their support
and leadership.
Financial Summary
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|
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|
|
2013
|
|
|
2012
|
|
|
Year ended
|
|
|
|
Q4
|
|
|
Q3
|
|
|
Q4
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
Statements of Comprehensive Income (Loss) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum & natural gas sales
|
|
$
|
11,087,956
|
|
$
|
9,372,931
|
|
$
|
4,842,343
|
|
$
|
34,726,657
|
|
$
|
21,327,157
|
|
$
|
20,742,259
|
Net income (loss) for the period (before tax)
|
|
$
|
1,576,908
|
|
$
|
39,646
|
|
$
|
(2,409,766)
|
|
$
|
4,146,706
|
|
$
|
21,174
|
|
$
|
4,872,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) for the period
|
|
$
|
750,851
|
|
$
|
11,330
|
|
$
|
340,623
|
|
$
|
2,585,699
|
|
$
|
(217,712)
|
|
$
|
1,385,698
|
Net income (loss) per share - basic and diluted
|
|
$
|
0.01
|
|
$
|
0.00
|
|
$
|
0.00
|
|
$
|
0.02
|
|
$
|
(0.00)
|
|
$
|
0.01
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
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Statements of Cash Flow |
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|
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Funds flow from (used in) operating activities
|
|
$
|
7,975,588
|
|
$
|
6,378,207
|
|
$
|
3,168,328
|
|
$
|
25,648,666
|
|
$
|
14,588,405
|
|
$
|
16,341,180
|
Funds flow from (used in) operating activities per share - basic and
diluted
|
|
$
|
0.06
|
|
$
|
0.05
|
|
$
|
0.03
|
|
$
|
0.21
|
|
$
|
0.12
|
|
$
|
0.15
|
Cash from (used in) operating activities
|
|
$
|
10,757,178
|
|
$
|
3,683,552
|
|
$
|
4,163,347
|
|
$
|
27,077,123
|
|
$
|
17,016,431
|
|
$
|
6,664,849
|
|
|
|
|
|
|
|
|
|
|
|
|
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Statements of Financial Position |
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Property and equipment
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|
$
|
152,971,016
|
|
$
|
135,892,343
|
|
$
|
121,842,378
|
|
$
|
152,971,016
|
|
$
|
121,842,378
|
|
$
|
119,374,219
|
Total assets
|
|
$
|
169,798,021
|
|
$
|
154,773,403
|
|
$
|
138,894,114
|
|
$
|
169,798,021
|
|
$
|
138,894,114
|
|
$
|
141,291,043
|
Working Capital (deficit), excluding MTM on commodity contracts
|
|
$
|
36,794,243
|
|
$
|
42,594,542
|
|
$
|
(36,301,842)
|
|
$
|
36,794,243
|
|
$
|
(36,301,842)
|
|
$
|
(34,028,162)
|
Subordinated Debt
|
|
$
|
7,786,632
|
|
$
|
-
|
|
$
|
-
|
|
$
|
7,786,632
|
|
$
|
-
|
|
$
|
-
|
Non-Current Liabilities
|
|
$
|
7,523,351
|
|
$
|
13,971,180
|
|
$
|
12,274,710
|
|
$
|
7,523,351
|
|
$
|
(12,274,710)
|
|
$
|
(9,752,766)
|
Shareholders equity
|
|
$
|
95,583,587
|
|
$
|
82,022,213
|
|
$
|
79,689,765
|
|
$
|
95,583,587
|
|
$
|
(79,689,765)
|
|
$
|
(76,627,244)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares - basic
|
|
|
127,219,336
|
|
|
121,718,245
|
|
|
121,711,723
|
|
|
123,101,587
|
|
|
120,663,095
|
|
|
105,960,324
|
Weighted average number of shares diluted
|
|
|
128,322,269
|
|
|
121,987,009
|
|
|
121,711,723
|
|
|
123,101,587
|
|
|
120,663,095
|
|
|
113,781,122
|
|
|
|
|
|
|
|
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|
Operations Summary
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|
2013
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|
|
2012
|
|
|
Year Ended
|
|
|
|
Q4
|
|
|
Q3
|
|
|
Q4
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
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|
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|
Daily production volumes |
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
Natural gas (mcf/d)
|
|
|
8,303
|
|
|
6,983
|
|
|
4,607
|
|
|
6,583
|
|
|
5,586
|
|
Oil (bbl/d)
|
|
|
683
|
|
|
547
|
|
|
418
|
|
|
556
|
|
|
350
|
|
NGL's (bbl/d)
|
|
|
605
|
|
|
450
|
|
|
304
|
|
|
422
|
|
|
341
|
|
Royalty income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf/d)
|
|
|
405
|
|
|
299
|
|
|
956
|
|
|
557
|
|
|
1,273
|
|
|
Oil (bbl/d)
|
|
|
1
|
|
|
1
|
|
|
(7)
|
|
|
1
|
|
|
3
|
|
|
NGL's (bbl/d)
|
|
|
24
|
|
|
26
|
|
|
57
|
|
|
37
|
|
|
77
|
|
Combined (boe/d 6:1)
|
|
|
2,764
|
|
|
2,238
|
|
|
1,700
|
|
|
2,206
|
|
|
1,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum & natural gas sales - Gross
|
|
$
|
11,087,956
|
|
$
|
9,372,931
|
|
$
|
4,842,343
|
|
$
|
34,726,657
|
|
$
|
21,327,157
|
Royalty income
|
|
|
177,335
|
|
|
195,468
|
|
|
216,693
|
|
|
1,108,750
|
|
|
2,024,819
|
Commodity contract settlement
|
|
|
271,387
|
|
|
(326,435)
|
|
|
535,585
|
|
|
1,181,080
|
|
|
907,863
|
Total sales
|
|
|
11,536,678
|
|
|
9,241,964
|
|
|
5,594,621
|
|
|
37,016,487
|
|
|
24,259,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty expense
|
|
|
(557,278)
|
|
|
(701,597)
|
|
|
(3,370)
|
|
|
(1,796,832)
|
|
|
(1,057,597)
|
Petroleum & natural gas sales - Net
|
|
$
|
10,979,400
|
|
$
|
8,540,367
|
|
$
|
5,591,251
|
|
$
|
35,219,655
|
|
$
|
23,202,242
|
Change in fair value of contracts
|
|
$
|
(2,217,286)
|
|
$
|
(2,411,102)
|
|
$
|
(209,267)
|
|
$
|
(6,928,607)
|
|
$
|
3,889,986
|
Total Revenue - Net of royalties
|
|
$
|
8,762,114
|
|
$
|
6,129,265
|
|
$
|
5,381,984
|
|
$
|
28,291,048
|
|
$
|
27,092,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
2012
|
|
|
|
Year Ended
|
|
|
|
|
Q4
|
|
|
|
Q3
|
|
|
|
Q4
|
|
|
|
2013
|
|
|
|
2012
|
Realized Pricing (Including commodity contracts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/bbl)
|
|
$
|
|
85.56
|
|
$
|
|
96.51
|
|
$
|
|
83.76
|
|
$
|
|
92.08
|
|
$
|
|
84.09
|
|
NGL ($/bbl)
|
|
$
|
|
52.08
|
|
$
|
|
53.33
|
|
$
|
|
25.09
|
|
$
|
|
54.32
|
|
$
|
|
46.78
|
|
Gas ($/mcf)
|
|
$
|
|
3.92
|
|
$
|
|
3.05
|
|
$
|
|
3.02
|
|
$
|
|
3.53
|
|
$
|
|
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Pricing (Excluding commodity contracts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/bbl)
|
|
$
|
|
84.98
|
|
$
|
|
102.99
|
|
$
|
|
77.78
|
|
$
|
|
90.93
|
|
$
|
|
83.07
|
|
NGL ($/bbl)
|
|
$
|
|
51.45
|
|
$
|
|
60.77
|
|
$
|
|
18.27
|
|
$
|
|
52.91
|
|
$
|
|
45.92
|
|
Gas ($/mcf)
|
|
$
|
|
3.67
|
|
$
|
|
2.57
|
|
$
|
|
2.94
|
|
$
|
|
3.25
|
|
$
|
|
2.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate ("WTI") (US$/bbl)
|
|
$
|
|
97.46
|
|
$
|
|
105.81
|
|
$
|
|
88.22
|
|
$
|
|
97.97
|
|
$
|
|
94.21
|
|
Edmonton (C$/bbl)
|
|
$
|
|
86.58
|
|
$
|
|
103.65
|
|
$
|
|
83.99
|
|
$
|
|
93.11
|
|
$
|
|
87.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO gas (Cdn$/GJ)
|
|
$
|
|
3.15
|
|
$
|
|
2.82
|
|
$
|
|
3.06
|
|
$
|
|
3.65
|
|
$
|
|
2.79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S./Canadian Dollar Exchange
|
|
$
|
|
0.953
|
|
$
|
|
0.963
|
|
$
|
|
1.009
|
|
$
|
|
0.971
|
|
$
|
|
1.000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
2012
|
|
|
|
|
Year Ended
|
|
|
|
|
Q4
|
|
|
|
|
Q3
|
|
|
|
|
Q4
|
|
|
|
|
2013
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price
|
|
$
|
|
44.67
|
|
|
$
|
|
43.94
|
|
|
$
|
|
34.39
|
|
|
$
|
|
44.59
|
|
|
$
|
|
31.74
|
|
Royalty income
|
|
|
|
0.70
|
|
|
|
|
0.95
|
|
|
|
|
1.39
|
|
|
|
|
1.38
|
|
|
|
|
2.89
|
|
Royalty expense
|
|
|
|
(2.19)
|
|
|
|
|
(3.41)
|
|
|
|
|
(0.02)
|
|
|
|
|
(2.23)
|
|
|
|
|
(1.51)
|
|
Production costs
|
|
|
|
(6.20)
|
|
|
|
|
(5.45)
|
|
|
|
|
(9.65)
|
|
|
|
|
(6.30)
|
|
|
|
|
(6.81)
|
|
Transportation costs
|
|
|
|
(1.27)
|
|
|
|
|
(1.47)
|
|
|
|
|
(0.95)
|
|
|
|
|
(1.26)
|
|
|
|
|
(0.84)
|
Operating netback
|
|
$
|
|
35.70
|
|
|
$
|
|
34.56
|
|
|
$
|
|
25.16
|
|
|
$
|
|
36.18
|
|
|
$
|
|
25.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A and other (excludes non-cash items)
|
|
|
|
(2.07)
|
|
|
|
|
(1.76)
|
|
|
|
|
(2.25)
|
|
|
|
|
(2.06)
|
|
|
|
|
(2.52)
|
|
Finance expenses
|
|
|
|
(2.59)
|
|
|
|
|
(2.32)
|
|
|
|
|
(2.65)
|
|
|
|
|
(2.32)
|
|
|
|
|
(2.13)
|
Cash flow netback
|
|
|
|
31.04
|
|
|
|
|
30.49
|
|
|
|
|
20.26
|
|
|
|
|
31.80
|
|
|
|
|
20.82
|
|
Depletion and depreciation
|
|
|
|
(15.96)
|
|
|
|
|
(18.05)
|
|
|
|
|
(18.52)
|
|
|
|
|
(17.50)
|
|
|
|
|
(20.67)
|
|
Impairment
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
(19.82)
|
|
|
|
|
-
|
|
|
|
|
(5.76)
|
|
Gain on sale of property and equipment
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
4.15
|
|
|
|
|
-
|
|
|
|
|
0.93
|
|
Accretion
|
|
|
|
(0.16)
|
|
|
|
|
(0.15)
|
|
|
|
|
(0.14)
|
|
|
|
|
(0.18)
|
|
|
|
|
(0.13)
|
|
Stock-based compensation
|
|
|
|
-
|
|
|
|
|
(0.38)
|
|
|
|
|
-
|
|
|
|
|
(0.36)
|
|
|
|
|
(0.71)
|
|
Unrealized gain (loss) on financial instruments
|
|
|
|
(8.72)
|
|
|
|
|
(11.71)
|
|
|
|
|
(1.34)
|
|
|
|
|
(8.60)
|
|
|
|
|
5.55
|
|
Deferred income tax
|
|
|
|
(3.25)
|
|
|
|
|
(0.14)
|
|
|
|
|
17.59
|
|
|
|
|
(1.94)
|
|
|
|
|
(0.34)
|
Net Income (loss) netback
|
|
$
|
|
2.95
|
|
|
$
|
|
0.06
|
|
|
$
|
|
2.18
|
|
|
$
|
|
3.21
|
|
|
$
|
|
(0.31)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
2012
|
|
|
|
|
Year Ended
|
Cash Additions
|
|
|
|
Q4
|
|
|
|
|
Q3
|
|
|
|
|
Q4
|
|
|
|
|
2013
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Land, acquisitions and lease rentals
|
|
$
|
|
(261,263)
|
|
|
$
|
|
307,274
|
|
|
$
|
|
240,777
|
|
|
$
|
|
184,606
|
|
|
$
|
|
734,910
|
Drilling and completion
|
|
|
|
18,958,090
|
|
|
|
|
6,725,516
|
|
|
|
|
6,679,886
|
|
|
|
|
35,705,499
|
|
|
|
|
19,727,708
|
Geological and geophysical
|
|
|
|
170,565
|
|
|
|
|
417,101
|
|
|
|
|
337,060
|
|
|
|
|
756,870
|
|
|
|
|
1,002,064
|
Equipment
|
|
|
|
1,490,863
|
|
|
|
|
1,036,654
|
|
|
|
|
1,758,120
|
|
|
|
|
7,595,294
|
|
|
|
|
2,812,328
|
Other Asset Additions
|
|
|
|
100,771
|
|
|
|
|
80,681
|
|
|
|
|
|
|
|
|
|
318,233
|
|
|
|
|
171,521
|
|
|
$
|
|
20,459,026
|
|
|
$
|
|
8,567,226
|
|
|
$
|
|
9,015,843
|
|
|
$
|
|
44,560,502
|
|
|
$
|
|
24,448,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Disposition of Property and Equipment
|
|
$
|
|
-
|
|
|
$
|
|
-
|
|
|
$
|
|
(4,650,000)
|
|
|
$
|
|
-
|
|
|
$
|
|
(4,650,000)
|
Net Capital Additions
|
|
$
|
|
20,459,026
|
|
|
$
|
|
8,567,226
|
|
|
$
|
|
4,365,843
|
|
|
$
|
|
44,560,502
|
|
|
$
|
|
19,798,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration & evaluation assets additions
|
|
$
|
|
2,461,506
|
|
|
$
|
|
-
|
|
|
$
|
|
-
|
|
$
|
|
|
2,461,506
|
|
|
$
|
|
-
|
Oil and Gas Reserves
The following tables summarize certain information contained in the
independent reserves report prepared by AJM Deloitte as of December 31,
2013. The report was prepared in accordance with definitions, standards
and procedures contained in the Canadian Oil and Gas Evaluation
Handbook ("COGE Handbook") and National Instrument 51-101, Standards of
Disclosure for Oil and Gas Activities ("NI 51-101").
Summary of Oil and Gas Reserves
(based on forecast price and costs)
Reserves Category |
|
|
| Light and Medium Oil (Mbbl) |
|
|
|
|
| Natural Gas Liquids (Mbbl) |
|
|
|
|
| Natural Gas (MMcf) |
|
|
|
|
W.I.
Gross
|
|
Co.Share
Gross
|
|
Net
|
|
W.I.
Gross
|
|
Co.Share
Gross
|
|
Net
|
|
W.I.
Gross
|
|
Co.Share
Gross
|
|
Net
|
Proved Developed Producing
|
|
988
|
|
993
|
|
820
|
|
711
|
|
754
|
|
539
|
|
12,095
|
|
13,209
|
|
11,130
|
Proved Developed Non-Producing
|
|
215
|
|
216
|
|
194
|
|
65
|
|
67
|
|
53
|
|
1,634
|
|
1,679
|
|
1,511
|
Proved Undeveloped
|
|
1,276
|
|
1,289
|
|
1,118
|
|
866
|
|
923
|
|
705
|
|
14,806
|
|
16,304
|
|
14,351
|
Total Proved |
| 2,479 |
| 2,498 |
| 2,132 |
| 1,642 |
| 1,744 |
| 1,297 |
| 28,535 |
| 31,192 |
| 26,992 |
Probable
|
|
2,392
|
|
2,401
|
|
2,031
|
|
1,308
|
|
1,357
|
|
1,010
|
|
24,227
|
|
25,590
|
|
22,739
|
Total Proved Plus Probable |
| 4,871 |
| 4,899 |
| 4,163 |
| 2,950 |
| 3,101 |
| 2,307 |
| 52,762 |
| 56,782 |
| 49,731 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves Category |
|
| Total BOE as at December 31, 2013 (Mboe) |
|
| Total BOE as at December 31, 2012 (Mboe) |
|
|
|
W.I.
Gross
|
|
|
Co.Share
Gross
|
|
|
Net
|
|
|
W.I.
Gross
|
|
|
Co.Share
Gross
|
|
|
Net
|
Proved Developed Producing
|
|
|
3,715
|
|
|
3,949
|
|
|
3,214
|
|
|
2,076
|
|
|
2,381
|
|
|
2,042
|
Proved Developed Non-Producing
|
|
|
552
|
|
|
563
|
|
|
499
|
|
|
433
|
|
|
443
|
|
|
386
|
Proved Undeveloped
|
|
|
4,610
|
|
|
4,929
|
|
|
4,215
|
|
|
4,039
|
|
|
4,338
|
|
|
3,765
|
Total Proved |
|
| 8,877 |
|
| 9,441 |
|
| 7,928 |
|
| 6,548 |
|
| 7,163 |
|
| 6,193 |
Probable
|
|
|
7,738
|
|
|
8,023
|
|
|
6,831
|
|
|
5,058
|
|
|
5,356
|
|
|
4,473
|
Total Proved Plus Probable |
|
| 16,615 |
|
| 17,464 |
|
| 14,759 |
|
| 11,606 |
|
| 12,518 |
|
| 10,667 |
Notes to table: |
(1)
|
Total values may not add due to rounding.
|
(2)
|
BOEs are derived by converting gas to oil equivalent in the ratio of six
thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl).
|
(3)
|
"Working Interest Gross" reserves are the Company's working interest
(operating or non-operating) share before deducting royalty obligations
and without including any royalty interests of the Company.
|
(4)
|
"Company Share Gross" reserves are the Company's working interest
(operating or non-operating) share and before deducting royalty
obligations but including any royalty interests of the Company.
|
(5)
|
"Net" Reserves are the Company's working interest (operating or
non-operating) share after deduction of royalty obligations plus any
royalty interests of the Company.
|
|
|
Summary of Net Present Values of Future Net Revenue (Before Tax)
(based on forecast price and costs)
|
|
| As At December 31, 2013(2) |
|
| As At December 31, 2012 (3) |
Reserves Category |
|
| 0.0% (M$) |
|
| 5.0% (M$) |
|
| 10.0% (M$) |
|
| 10% (M$) |
|
Proved Developed Producing
|
|
|
112,355
|
|
|
92,026
|
|
|
78,259
|
|
|
45,271
|
|
Proved Developed Non-Producing
|
|
|
19,832
|
|
|
16,499
|
|
|
14,239
|
|
|
4,992
|
|
Proved Undeveloped
|
|
|
105,640
|
|
|
75,062
|
|
|
54,859
|
|
|
49,387
|
|
Total Proved |
|
| 237,827 |
|
| 183,587 |
|
| 147,357 |
|
| 99,650 |
|
Probable
|
|
|
257,412
|
|
|
156,838
|
|
|
103,791
|
|
|
67,357
|
|
Total Proved Plus Probable |
|
| 495,239 |
|
| 340,425 |
|
| 251,148 |
|
| 167,381 |
|
Notes to table: |
(1)
|
Total values may not add due to rounding.
|
(2)
|
Forecast pricing used is based on AJM Deloitte published price forecasts
effective December 31, 2013.
|
(3)
|
Forecast pricing used is based on AJM Deloitte published price forecasts
effective December 31, 2012.
|
(4)
|
Cash flows include the effects of the current Alberta Royalty Framework.
The estimated future net reserves are stated before deducting future
estimated site restoration costs and are reduced for future abandonment
costs and estimated capital for future development associated with the
reserves.
|
(5)
|
It should not be assumed that the net present values of future net
revenues estimated by AJM Deloitte represent fair market value of the
reserves. There is no assurance that the forecast price and cost
assumptions will be attained and variances could be material.
|
|
|
Reserve Definitions: |
(a)
|
"Proved" reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves.
|
(b)
|
"Probable" reserves are those additional reserves that are less certain
to be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the
sum of the estimated proved plus probable reserves.
|
(c)
|
"Developed" reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (e.g. when compared to the cost of drilling a well) to put
the reserves on production.
|
(d)
|
"Developed Producing" reserves are those reserves that are expected to
be recovered from completion intervals open at the time of the
estimate. These reserves may be currently producing or, if shut-in,
they must have previously been on production, and the date of
resumption of production must be known with reasonable certainty.
|
(e)
|
"Developed Non-Producing" reserves are those reserves that either have
not been on production, or have previously been on production, but are
shut in, and the date of resumption of production is unknown.
|
(f)
|
"Undeveloped" reserves are those reserves expected to be recovered from
known accumulations where a significant expenditure (for example, when
compared to the cost of drilling a well) is required to render them
capable of production. They must fully meet the requirements of the
reserves classification (proved, probable, possible) to which they are
assigned.
|
(g)
|
The Net Present Value (NPV) is based on AJM Deloitte Forecast Pricing
and costs. The estimated NPV does not necessarily represent the fair
market value of our reserves. There is no assurance that forecast
prices and costs assumed in the AJM Deloitte evaluations will be
attained, and variances could be material.
|
|
|
Finding and Development Costs ("F&D")
Yangarra's F&D costs for 2013, 2012 and the three year average are
presented in the tables below. The costs used in the F&D calculation
are the capital costs related to: land acquisition and retention;
drilling; completions; tangible well site; tie-ins; and facilities,
plus the change in estimated future development costs as per the
independent reserve report. Acquisition costs are net of any proceeds
from dispositions of properties. Due to the timing of capital costs
and the subjectivity in the estimation of future costs, the aggregate
of the exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally will not reflect total finding and
development costs related to reserve additions for that year. The
reserves used in this calculation are Company net reserve additions,
including revisions.
Proved Finding & Development Costs ($ millions)
|
|
| 2013 |
|
| 2012 |
|
| 2011 - 2013 |
Capital expenditures
|
|
| 47.0 |
|
|
19.8
|
|
|
130.8
|
Change in future capital
|
|
| 7.2 |
|
|
23.8
|
|
|
41.3
|
Total capital for F&D
|
|
| 54.2 |
|
|
43.6
|
|
|
172.1
|
|
|
|
|
|
|
|
|
|
|
Reserve additions, net production (Mboe)
|
|
| 3,083 |
|
|
2,409
|
|
|
8,005
|
|
|
|
|
|
|
|
|
|
|
Proved F&D costs - including future capital ($/boe)
|
|
| 17.58 |
|
|
18.09
|
|
|
21.50
|
Proved F&D costs - excluding future capital ($/boe)
|
|
| 15.25 |
|
|
8.22
|
|
|
15.85
|
|
|
|
|
|
|
|
|
|
|
Proved Recycle Ratio |
|
|
|
|
|
|
|
|
|
|
Including future capital
|
|
| 2.06 |
|
|
1.41
|
|
|
|
|
Excluding future capital
|
|
| 2.37 |
|
|
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved plus Probable Finding & Development Costs ($ millions) |
|
|
|
|
|
|
|
|
|
|
|
| 2013 |
|
| 2012 |
|
| 2011 - 2013 |
Capital expenditures
|
|
| 47.0 |
|
|
19.8
|
|
|
130.8
|
Change in future capital
|
|
| 33.9 |
|
|
35.7
|
|
|
78.3
|
Total capital for F&D
|
|
| 80.9 |
|
|
55.5
|
|
|
209.1
|
|
|
|
|
|
|
|
|
|
|
Reserve additions, net production (Mboe)
|
|
| 5,750 |
|
|
4,459
|
|
|
13,141
|
|
|
|
|
|
|
|
|
|
|
Proved plus Probable F&D costs - including future capital ($/boe)
|
|
| 14.07 |
|
|
12.45
|
|
|
15.91
|
Proved plus Probable F&D costs - excluding future capital ($/boe)
|
|
| 8.18 |
|
|
4.44
|
|
|
9.96
|
|
|
|
|
|
|
|
|
|
|
Proved plus Probable Recycle Ratio |
|
|
|
|
|
|
|
|
|
|
Including future capital
|
|
| 2.57 |
|
|
2.05
|
|
|
|
|
Excluding future capital
|
|
| 4.42 |
|
|
5.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Asset Value ("NAV")
As at December 31, 2013 ($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Value of Proved plus Probable Reserves, before tax (discounted
at 10%)
|
|
|
|
$
|
|
251.1
|
Total Debt
|
|
|
|
|
|
(44.6)
|
|
|
|
|
|
|
|
Net Asset Value |
|
|
| $ |
| 206.5 |
|
|
|
|
|
|
|
Common shares outstanding at year end
|
|
|
|
|
|
147.1
|
|
|
|
|
|
|
|
Net asset value per share |
|
|
| $ |
| 1.40 |
Notes to tables: |
(1)
|
The preceding table shows what is customarily referred to as a "produce
out" net asset value calculation under which the current value of
Yangarra's reserves would be produced at the AJM Deloitte forecast
future prices and costs. The value is a snapshot in time as at
December 31, 2013 and is based on various assumptions including
commodity prices and foreign exchange rates that vary over time. In
this analysis, the present value of the proved and probable reserves is
calculated at a before tax 10 percent discount rate.
|
(2)
|
The 2013 total debt, excludes non-cash items (MTM on commodity contracts
and flow through share obligations).
|
|
|
Advance Notice Bylaw
Yangarra is announcing that its Board of Directors approved the adoption
of an advance notice by-law (the "Advance Notice By-law"). Among other
things, the Advance Notice By-law fixes a deadline by which
shareholders must submit a notice of director nominations to Yangarra
prior to any annual or special meeting of shareholders where directors
are to be elected and sets forth the information that a shareholder
must include in the notice for it to be valid.
The Advance Notice By-law is similar to the advance notice requirements
adopted by many other Canadian public companies. Specifically, the
Advance Notice By-law requires advance notice to the Corporation in
circumstances where nominations of persons for election as a director
of Yangarra are made by shareholders other than pursuant to (i) a
requisition of a meeting made pursuant to the provisions of the
Business Corporations Act (Alberta) (the "Act"), or (ii) a shareholder
proposal made in accordance with the provisions of the Act.
In the case of an annual meeting of shareholders, notice to the
Corporation must be given not less than 30 or more than 65 days prior
to the date of the annual meeting. In the event that the annual meeting
is to be held on a date that is less than 50 days after the date on
which the first public announcement of the date of the annual meeting
was made, notice may be given not later than the close of business on
the 10th day following such public announcement.
In the case of a special meeting of shareholders (which is not also an
annual meeting), notice to the Corporation must be given not later than
the close of business on the 15th day following the day on which the
first public announcement of the date of the special meeting was made.
The Advance Notice By-law is effective immediately. At the next meeting
of shareholders of the Corporation, shareholders will be asked to
confirm and ratify the Advance Notice By-law. The full text of the
Advance Notice By-law is available under Yangarra's profile at www.sedar.com.
Annual General Meeting of Shareholders
The Company's Annual General and Special Meeting of Shareholders is
scheduled for 10:00 AM on Tuesday May 27, 2014 in the Tillyard
Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary,
AB.
Year End Disclosure
The Company's Annual Report (financial statements, notes to the
financial statements and management's discussion and analysis) will be
filed on SEDAR (www.sedar.com) and be available on the Company's website (www.yangarra.ca).
Additional reserve information as required under NI 51-101 will be
included in the Company's Annual Information Form which will be filed
on SEDAR by April 30, 2014.
Natural gas has been converted to a barrel of oil equivalent (Boe) using
6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil
(6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1
Bbl is based on an energy equivalency conversion method and does not
represent a value equivalency; therefore Boe's may be misleading if
used in isolation. References to natural gas liquids ("NGLs") in this
news release include condensate, propane, butane and ethane and one
barrel of NGLs is considered to be equivalent to one barrel of crude
oil equivalent (Boe). One ("BCF") equals one billion cubic feet of
natural gas. One ("Mmcf") equals one million cubic feet of natural
gas.
Certain information regarding Yangarra set forth in this news release,
including management's assessment of future plans, operations and
operational results may constitute forward-looking statements under
applicable securities law and necessarily involve risks associated with
oil and gas exploration, production, marketing and transportation such
as loss of market, volatility of prices, currency fluctuations,
imprecision of reserves estimates, environmental risks, competition
from other producers and ability to access sufficient capital from
internal and external sources. As a consequence, actual results may
differ materially from those anticipated in the forward-looking
statements.
The initial production rates discussed in this press release are not
necessarily indicative of long-term performance or of ultimate recovery
due to high initial decline rates.
All reference to $ (funds) are in Canadian dollars.
Neither the TSX Venture Exchange nor its Regulation Service Provider (as
that term is defined in the Policies of the TSX Venture Exchange)
accepts responsibility for the adequacy and accuracy of this release.
SOURCE Yangarra Resources Ltd.
Image with caption: "1) Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2) Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) (CNW Group/Yangarra Resources Ltd.)". Image available at: http://photos.newswire.ca/images/download/20140325_C6908_PHOTO_EN_38294.jpg