ANNUAL REPORT 2014
SEVEN GENERATIONS IS A HIGH-GROWTH,
LIQUIDS-RICH MONTNEY INVESTMENT
OPPORTUNITY WITH WORLD-CLASS,
WORLD-SCALE ASSETS.
Operational highlights:
44.2 MBOE/D
Q4 2014 production sales
58% LIQUIDS
Q4 2014 production sales
$35.52/BOE
2014 netback after hedging
55-60 MBOE/D
(50-55% liquids)
2015E production
SIGNIFICANT RESERVES
AND RESOURCES
TO SUPPORT A
MULTI-DECADE
DRILLING PROGRAM
GROWTH SUPPORTED
BY LOCATION
ADVANTAGES AND
FIRM TRANSPORTATION
CONTRACTS
OPERATORSHIP AND
OWNERSHIP OF FACILITIES
TO CONTROL PACE OF
DEVELOPMENT
A PROVEN TEAM WITH
DEMONSTRATED ABILITY
TO ADD VALUE TO
UNCONVENTIONAL PLAYS
Financial and Operating Results Summary | 1 | CEO’s Message to Shareholders | 8 |
Seven Generations Code of Conduct | 19 | Management’s Discussion and Analysis | 20 |
Financial Statements | 49 | Notes to the Financial Statements | 54 | Corporate Information | 79 |
“Seven Generations” is an ecological concept
that urges humans to live sustainably and
work for the benefit of the seventh generation
into the future. It originated with The Great
Law of the Iroquois, which holds that it is
appropriate to think ahead and decide whether
the decisions made today would benefit the
seventh generation. We strongly believe in this
concept, and continually strive to ensure that
our actions will benefit our stakeholders –
both now and in the future.
SEVEN GENERATIONS ANNUAL REPORT 2014
2014 FOURTH QUARTER AND ANNUAL FINANCIAL AND
OPERATING RESULTS
OPERATIONAL
Production
Oil and condensate (bbls/d)
NGLs (bbls/d)
Natural gas (Mmcf/d)
Oil equivalent (boe/d)
Liquids ratio
Realized prices (3)
Oil and condensate ($/bbl)
NGLs ($/bbl)
Natural gas ($/mcf)
Oil equivalent ($/boe)
Operating netback per boe ($) (1)
Oil and natural gas revenue (3)
Royalties
Operating expenses
Transportation expenses (3)
Netback prior to hedging
Realized hedging gain
Netback after hedging
General and administrative expenses per boe
FINANCIAL ($ thousands, except per share amounts)
Oil and natural gas revenue (3)
Funds from operations (1)
Per share – diluted (2)
Operating income (1)
Per share – diluted (2)
Net income (loss)
Per share – diluted (2)
Weighted average shares (000s) – diluted (2)
Total capital investments
Available funding (1)
Net debt (1)
Debt outstanding
Three months ended December 31
Year ended December 31
2014
2013
% Change
2014
2013
% Change
14,747
10,783
112
44,178
58%
69.93
21.50
3.81
38.23
38.23
(3.97)
(4.67)
(3.26)
26.33
5.45
31.78
1.82
155,383
101,503
0.41
34,815
0.14
68,628
0.28
250,223
370,320
1,133,800
158,270
813,880
4,480
2,291
29
11,585
58%
80.63
24.54
3.79
45.49
45.49
(2.99)
(7.90)
(3.09)
31.51
0.05
31.56
1.93
48,484
23,114
0.12
7,127
0.04
(5,625)
(0.03)
192,689
178,238
364,877
210,563
414,525
229
371
286
281
-
(13)
(12)
1
(16)
(16)
33
(41)
6
(16)
10,800
-
(6)
220
339
242
388
250
1,320
1,033
11,061
6,989
79
31,136
58%
85.34
24.10
4.50
47.06
47.06
(4.57)
(4.77)
(3.06)
34.66
0.86
35.52
1.78
534,833
327,933
1.46
119,521
0.53
144,200
0.64
30
108
211
(25)
96
224,717
1,120,336
1,133,800
158,270
813,880
2,390
1,749
22
7,786
53%
85.49
18.76
3.34
39.83
39.83
(2.76)
(7.25)
(2.28)
27.54
0.10
27.64
2.86
113,184
50,273
0.27
5,794
0.03
(14,158)
(0.08)
183,288
574,328
364,877
210,563
414,525
363
300
259
300
9
-
28
35
18
18
66
(34)
34
26
760
29
(38)
373
552
440
1,963
1,667
1,119
900
23
95
211
(25)
96
(1)
Operating netback, funds from operations, operating income, available funding and net debt are not defined under IFRS. See “Non-IFRS Financial Measures”
in Management’s Discussion and Analysis.
(2) In 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares, stock options and performance
warrants on a two-for-one basis. The share split has been reflected for the three months and years ended December 31, 2014 and 2013 on a retroactive basis.
(3) Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation.
1
SEVEN GENERATIONS ANNUAL REPORT 2014 HIGHLIGHTS FOR THE QUARTER AND YEAR ENDED
DECEMBER 31, 2014
¡¡ Fourth quarter 2014 production was 44,178 boe per day representing a 281% increase over fourth quarter 2013 production of
11,585 boe per day. Annual 2014 production averaged 31,136 boe per day compared to 7,786 boe per day during 2013, an
increase of 300%.
¡¡ Liquids ratios for the fourth quarter remained constant at 58% of total production on a boe basis, with fourth quarter condensate
production representing 34% of Seven Generations Energy Ltd. (“Seven Generations”, “7G” or the “Company”) total
production mix.
¡¡ Seven Generations realized a netback after hedging of $35.52 per boe for the year ended December 31, 2014, compared to
$27.64 per boe for the year ended December 31, 2013.
¡¡ The Company achieved record funds from operations of $327.9 million in 2014 compared to $50.3 million in 2013, an increase of
552%. Funds from operations for the fourth quarter of 2014 was $101.5 million, which was a 339% increase over the fourth
quarter 2013.
¡¡ McDaniel & Associates Consultants Ltd.’s (“McDaniel”) estimated total gross proved reserves (“1P”) were 420.7 MMboe, as at
December 31, 2014, which was an increase of 28% and 292% since the Company’s July 1, 2014 and December 31, 2013
reserve evaluations.
¡¡ McDaniel’s estimated total gross proved plus probable reserves (“2P”), as at December 31, 2014, increased to 788.6 MMboe,
a 22% increase over the Company’s July 1, 2014 gross 2P reserves of 649.1 MMboe and a 178% increase over the
December 31, 2013 gross 2P reserves of 283.3 MMboe.
¡¡ McDaniel’s estimated proved developed producing reserves (“PDP”) increased to 34.1 MMboe, an increase of 99% over the
Company’s July 1, 2014 PDP reserves of 17.1 MMboe and a 127% increase over the December 31, 2013 gross PDP reserves of
15.0 MMboe.
¡¡ Before tax net present values, using a discount rate of 10% per annum, were $3.1 billion for proved reserves and $7.1 billion for
proved plus probable reserves, based on McDaniel’s estimates as at December 31, 2014.
¡¡ In the fourth quarter of 2014, the Company closed an initial public offering (“IPO”) for net proceeds of $880.1 million through the
issuance of 51.8 million class A common shares. During the third quarter of 2014, the Company and its lending syndicate agreed
to an amendment to the senior secured revolving credit arrangement that increased the borrowing capacity from $150.0 million
to $480.0 million and extended the maturity date of the credit facility to September 2017. As of December 31, 2014, the
Company had available funding in excess of $1.1 billion.
2
SEVEN GENERATIONS ANNUAL REPORT 2014 OPERATIONAL REVIEW
Fourth quarter production averaged 44,178 boe per day, consisting of 34% condensate and 24% other NGLs, with total liquids
representing 58% of total production on a per boe basis. Average annual production for 2014 was 31,136 boe per day, consisting of
58% liquids, with liquids production consisting of 36% condensate and 22% other NGLs on a per boe basis.
Based on preliminary field estimates, production for the first two months of 2015 averaged approximately 47,500 boe per day, on
track to achieve 7G’s annual production guidance. While production continues to ramp up quite rapidly, growth will be constrained
later in the year by the Lator plant capacity until the Lator 2 plant expansion is completed in the fourth quarter of 2015, therefore
annual production is expected to be consistent with current guidance of 55,000 to 60,000 boe per day.
An average of 10 drilling rigs were operated during the fourth quarter of 2014, with a peak of 14 rigs operating for most of
December. Fourteen wells were rig released in the fourth quarter, including 12 Montney wells in the Nest, one Montney well in the
Deep Sour region, and one First White Specks emerging target well. For the year ended December 31, 2014, the Company drilled
49 gross wells consisting of 44 Montney horizontal wells in the nest, three Montney horizontal delineation wells, one emerging
target well and one vertical well. The average horizontal length for the 12 (12.0 net) Montney wells drilled in the Nest in the fourth
quarter of 2014 was 2,870 meters with an average spud to rig release time of 56.6 days. Average horizontal lengths drilled per well
in 2014 increased 30% over the prior year’s average while average drilling days per well was reduced by 18%.
During the fourth quarter of 2014, 7G completed 10 Montney wells in the Nest, and one Montney horizontal well in the Wapiti
region, stimulating a total of 340 stages, averaging 31 stages per well, 3,800 tonnes of proppant per well, and 1.5 tonnes per meter
of lateral. When compared to 7G’s 2013 activity, average stages completed per well increased 32% and average tonnes of proppant
pumped per well increased 20%. The Company used several completion techniques in the fourth quarter of 2014, including two
slickwater fracs, one HiWay frac (a Schlumberger proprietary technique), six nitrogen foam fracs with ball drop sliding sleeve
systems, and two nitrogen foam fracs using the plug and perf frac delivery system. Two of the fourth quarter 2014 completions
were costlier than expected as a result of having to fish coiled tubing that was stuck downhole during milling operations in one well
and the other due to a frac that was initiated in the first quarter of 2014 that was suspended due to access issues and not
completed until the fourth quarter of 2014.
The company adjusted our liner design and proppant selection mid fourth quarter, which resulted in decreased completions costs
per well. 7G continues to work on optimizing its completion design and has several tests planned for 2015 including experimenting
with inter-stage spacing, produced water re-use, proppant selection, higher proppant concentration, and proppant carrying fluid
type. The Company intends to apply a standard completion design to approximately 85% of its completions while experimenting, in
a controlled fashion, with 15% of its wells. Currently, the Company’s standard completion design is comprised of a 28 stage
ball-drop system, with nitrogen foam as the carrying fluid for approximately 4,500 tonnes of proppant, resulting in a proppant
density of 1.5 tonnes per meter of lateral. These design changes, along with other operational efficiencies are expected to result in
substantially improved completion costs in 2015.
Gross wells rig released
Average measured depth (m)*
Average horizontal length (m)*
Average drilling days per well*
Gross wells completed
Average number of stages
Average tonnes pumped
*excludes one abandoned and two vertical wells.
Three months ended December 31
Year ended December 31
2014
14
6,070
2,870
56
11
31
2013
11
5,280
2,200
52
9
22
2014
49
5,840
2,660
54
38
29
2013
23
5,090
2,050
66
17
22
3,800
2,870
3,330
2,780
3
SEVEN GENERATIONS ANNUAL REPORT 2014 During the fourth quarter of 2014, 7G commissioned the Karr 7-11 to Lator condensate pipeline and completed the Lator to Pembina
liquids pipeline. The Company anticipates that Pembina will complete its Lator to Fox Creek line looping project in the first quarter of
2015, which will result in reduced condensate transportation costs as the Company shifts from trucking volumes to pipeline
connected capacity. Field construction of the 25,000 barrel per day stabilizer at the Karr 7-11 battery also continued in the fourth
quarter. The Company expects that the stabilizer will be fully commissioned in the first quarter of 2015, which will help improve
condensate quality and reduce pricing discounts.
As of December 31, 2014, the Company had 6 satellite pads and 31 well tie-ins under construction in addition to nine well tie-ins
that were completed in the fourth quarter. 7G currently has an inventory of approximately 47 wells at various stages of construction
between drilling and tie-in.
CAPITAL INVESTMENTS
Capital investments totalled $370.3 million for the fourth quarter of 2014 and $1.1 billion for the full year of 2014. 2014 capital
invested was approximately 5% over 7G’s guidance primarily due to progress payments for long lead items for the Lator 2 and
Cutbank area plants, payments associated with a new temporary camp that will be occupied in the first quarter of 2015, earlier than
planned drilling of an emerging target well and a deep sour well in addition to higher than expected completion costs.
During the fourth quarter of 2014, 7G invested $227.6 million to drill 14 wells and complete 11 multi-stage horizontal wells with
a 100% success rate, with nine wells brought onto production. For the year ended December 31, 2014, the Company invested
$742.0 million to drill 49 wells and complete 38 wells, and brought 34 wells onto production, compared to 23 wells drilled, 17 wells
completed and 14 wells brought on production for the year ended December 31, 2013. Drill counts are based on the rig release date
and production counts are based on the first reportable production date.
Number of wells drilled – gross
Number of wells completed – gross
Number of wells brought on production – gross
($ thousands)
Drilling
Completions
Total drill and complete
Three months ended December 31
Year ended December 31
2014
14
11
9
2013
11
9
10
2014
49
38
34
2013
23
17
14
122,493
105,069
227,562
65,093
64,138
129,231
391,169
350,850
742,019
183,375
138,435
321,810
In the fourth quarter 2014, the Company invested $132.6 million into facilities and infrastructure. For the year ended
December 31, 2014, 7G invested $323.0 million into facilities and infrastructure with 44% invested in pad and well equipment,
42% in major facilities, 8% in pipelines and 6% in supporting infrastructure.
Three months ended December 31
Year ended December 31
2014
2013
2014
2013
51,547
29,921
140,835
54,401
68,385
5,575
135,654
33,585
5,087
3,700
25,489
64,102
7,591
5,521
21,058
34,606
132,610
44,717
323,035
186,694
($ thousands)
Pad and well equipment
Major facilities
Pipelines
Supporting infrastructure
Facilities and equipment
4
SEVEN GENERATIONS ANNUAL REPORT 2014 FINANCIAL REVIEW
In the fourth quarter of 2014, the Company closed an initial public offering (“IPO”) for net proceeds of $880.1 million through the
issuance of 51.8 million class A common shares. During the third quarter of 2014, the Company and its lending syndicate agreed to
an amendment to the senior secured revolving credit arrangement that increased the borrowing capacity from $150.0 million to
$480.0 million and extended the maturity date of the credit facility to September 2017. As of December 31, 2014, the Company had
available funding in excess of $1.1 billion.
Despite falling energy prices in the fourth quarter of 2014, 7G generated fourth quarter and full year 2014 funds from operations of
$101.5 million and $327.9 million, which were up 339% and 552%, respectively, over comparable 2013 periods. The increase in
funds from operations was primarily due to the increase in production volumes that more than offset the lower liquids and
gas pricing.
Fourth quarter and full year 2014 netbacks prior to hedging averaged $26.33 per boe and $34.66 per boe, which were 16% lower
and 26% higher than similar periods in 2013, respectively. After hedging, 7G’s fourth quarter and annual 2014 netbacks were
$31.78 per boe and $35.52 per boe, which were equivalent to and 29% higher than comparable periods in 2013.
As of December 31, 2014, 7G had approximately 68,500 GJ/d of 2015 AECO exposed production hedged at an average price
of $3.85/GJ and average 8,200 barrel per day of 2015 liquids production hedged at a WTI price of approximately $101.80 CAD
per barrel.
MARKETING
During the fourth quarter of 2014, 7G converted the portion of its outstanding Alliance pipeline commitments that had initially been
contracted as firm receipt service to firm full path service and extended the expiry on all outstanding Alliance pipeline commitments
to 2022. The conversion in service means that, as of December 2015, all of the Company’s gas delivered onto the Alliance Pipeline
will be transported to Chicago and will have access to US Midwest markets.
The Company’s average realized price for condensate and oil in the fourth quarter of 2014 was $69.93 per barrel, which was an
approximate $10 per barrel discount to the Alberta benchmark CRW condensate price. Condensate pricing is expected to improve
and trade closer to Alberta benchmark pricing as the Company commissions its condensate stabilizer in the first quarter of 2015,
which is expected to improve the quality of marketed product.
The average realized prices for NGLs primarily reflect a combination of prices for NGLs such as ethane, propane, butane and
pentanes plus. The Company’s average realized prices decreased for this product stream in the fourth quarter of 2014 by 12% to
$21.50 per barrel, compared to $24.54 per barrel for the same period in 2013. For the 2014 year end, the Company realized average
prices of $24.10 per barrel for its NGLs as compared to $18.76 per barrel for the comparative period in 2013, an increase of 28%.
The Company’s average realized natural gas price increased by 1% to $3.81 per mcf for the fourth quarter of 2014, compared to
$3.79 per mcf in the same period in 2013. For the year ended December 31, 2014, the Company’s average realized natural gas price
increased by 35% to $4.50 per mcf compared to $3.34 per mcf in 2013. The Company receives a blend of pricing based on AECO
monthly and daily benchmark indexes.
LAND UPDATE
Since the Company’s last land update during the third quarter of 2014, 7G has increased its land holdings by 76,480 (gross and net)
acres at an average cost of $117 per acre. As of December 31, 2014, the Company held more than 424,000 net acres with Montney
rights on 407,475 net acres with an average working interest of 98%. During the fourth quarter of 2014 the Company acquired
approximately 68,800 acres at a total cost of $8.2 million.
5
SEVEN GENERATIONS ANNUAL REPORT 2014 OUTLOOK
On February 24, 2015, the Company announced its plan to reduce 2015 capital investments downwards by $250 to $300 million,
resulting in a revised capital program of $1.30 to $1.35 billion. The Company plans to defer spending of approximately $200 to
$250 million and also expects, through negotiations with suppliers and business partners, to capture additional cost savings on
2015 projects of at least $50 million, resulting in an aggregate capital investment reduction of approximately 15% to 20% from the
earlier announced budget of $1.60 billion.
The Company anticipates 2015 production to be between 55,000 and 60,000 boe per day and plans to drill 77 new wells in 2015
with 60 new producing wells coming on line in 2015. Currently 7G has initiated but not completed work on an in-process inventory
of 47 new wells that will help fuel the Company’s production growth. 7G’s operated drilling rig count is currently 10 and is expected
to ramp up to 13 rigs at mid-year and to 15 rigs for the last two months of 2015.
In 2015, 7G plans to finish the expansion of its Lator refrigeration plant to its 250 Mmcf/d rich gas sales capacity and to initiate the
construction of a second refrigeration plant which, when complete in 2016, will increase processing capacity to 500 Mmcf/d and
allow the Company to continue to profitably deliver rich gas volumes into its firm transportation commitments.
RESERVES
7G’s independent reserves evaluation, effective December 31, 2014, was recently completed by McDaniel & Associates
Consultants Ltd. (“McDaniel”). McDaniel prepared the evaluation in compliance with the standards set out in National Instrument
51-101 of the Canadian Securities Administrators and the Canadian Oil and Gas Evaluation Handbook. For additional information
regarding the independent reserves evaluation that was conducted by McDaniel, as at December 31, 2014, please see the
disclosure that is provided under the heading “Independent Reserves Evaluation” below and the Company’s Annual Information
Form dated March 10, 2015 (“AIF”), which is available on the SEDAR website at www.sedar.com.
¡¡ Total gross 1P reserves of 420.7 MMboe, as at December 31, 2014, represented an increase of 28% and 292% when compared
to the Company’s July 1, 2014 and December 31, 2013 gross 1P reserves of 328.0 MMboe and 107.2 MMboe, respectively.
¡¡ Total gross 2P reserves, as at December 31, 2014, were 788.6 MMboe, a 22% increase over the Company’s July 1, 2014
gross 2P reserves of 649.1 MMboe, and a 179% increase over the Company’s December 31, 2013 gross 2P reserves of
283.3 MMboe.
¡¡ PDP reserves increased to 34.1 MMboe as at December 31, 2014, an increase of 99% over the Company’s July 1, 2014 PDP
reserves of 17.1 MMboe.
¡¡ Before tax net present values, using a discount rate of 10% per annum, were $3.1 billion for gross 1P reserves and $7.1 billion
for gross 2P reserves, as of December 31, 2014.
¡¡ 2014 finding and development (“F&D”) costs, including future development capital, were $14.09 per boe for gross 2P reserves
and $17.76 per boe for gross 1P reserves.
¡¡ The Company had a recycle ratio of 2.46 times for gross 2P reserves evaluated as at December 31, 2014, based on the
aforementioned F&D costs and pre-hedging netbacks of $34.66 per boe, as at December 31, 2014.
6
SEVEN GENERATIONS ANNUAL REPORT 2014 PDP + PDNP (1)
Proved reserves (2)
Proved plus probable reserves (2)
December 31, 2014
July 1, 2014
December 31, 2013
MMboe
39
421
789
$MM (3)
627
3,145
7,108
MMboe
26
328
649
$MM (3)
546
3,285
7,032
MMboe
15
107
283
$MM (3)
315
1,023
3,104
(1) Proved Developed Producing plus Proved Developed Non-producing.
(2) Company gross reserves as determined by Seven Generations’ independent reserve evaluator.
(3) Before Tax Net Present Valued using a 10% Discount Rate.
The Company’s oil, NGLs and natural gas reserves are located primarily in the Kakwa area. The July 1, 2014 reserves and resources
were prepared in conjunction with the Company’s IPO. For definitions and additional information regarding Seven Generations’
reserves estimates, refer to the Company’s AIF which is available on SEDAR at www.sedar.com.
7
SEVEN GENERATIONS ANNUAL REPORT 2014 CEO’S MESSAGE TO THE SHAREHOLDERS
March 2015
The free market system is ruthless. It is
persistent. It is overbearing. It demands
the lowest cost supply and when it has
devoured that, it seeks more but always
the lowest cost available. That is why we
like it. It maximizes the efficiency of our
economy – our wants and needs provided
at the lowest cost. I am a big believer.
If you have been reading my shareholder
messages and our corporate
presentations over the past seven years
you will know that having the lowest cost
supply in our market is a corporate
obsession. Mid to late last decade, we
designed the Company to compete
nose-to-nose with the best in emerging
resource plays. We saw the immense
resource potential of these plays, enough
to flood any established market with new
supply. We recognized that the novelty of
their commercial development put new
entrants on a more level playing field with
established companies. We saw that new
technology would be required and the
experts weren’t far ahead of the new
entrants. Whatever the final outcome, we
figured that there needed to be a battle to
secure the best quality supply, the supply
that had the potential to be delivered to
that overbearing market. We also
suspected that there would be a technical
showdown and that we needed to stay
alert, know what was going on in the
technology world and strategically pick
what appeared to be the best ways to
economize, to reduce supply costs. We
needed to attack those costs by testing
both established technologies and new
ones – all in pursuit of lower supply cost. I
feel that all of our employees, from the
most senior management, to the most
recently hired, understand what we mean
by positioning at the “toe of the supply
cost boot” and the importance of that
statement. The pursuit of lowest cost is
ingrained into the corporate culture of
Seven Generations Energy Ltd. (“Seven
Generations”, “7G” or the “Company”).
WTI OIL BREAKEVEN PRICE ($ PER BBL) COST DEFLATION SCENARIO – AT $3.00/MCF NATURAL GAS
Base
10% Cost Deflation
20% Cost Deflation
30% Cost Deflation
Current 2015 Strip $49.43/Bbl
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The above diagram is what we call a supply cost (or threshold price) “boot” diagram. This one is for oil. Each bar indicates the commodity price that is required for the
project to earn a threshold rate of return (such as a 15% before tax internal rate of return). In aggregate, the bars generally take the shape of a boot with the lowest
supply cost projects at the toe of the boot. Seven Generations seeks to position with the lowest supply cost projects at the “toe” of the supply cost boot.
Graph source: Credit Suisse Oil & Gas Equity Research, February 2015.
8
SEVEN GENERATIONS ANNUAL REPORT 2014
The cruel, discriminating, ruthless market
interested in only the lowest cost supply
arrived last year. We were ready.
On a very personal note, I learned this
market lesson the hard way. At least my
family did. My dad was a hard working
Swedish immigrant, a farmer who left
home to move to Canada, by himself, at
15 years of age. Mom was a daughter of
the Canadian prairie, a pioneer woman
who had turned soil with a horse drawn
plow, whose father helped to win
Canada’s station as a free and
independent nation when he, among his
Princess Patricia’s Canadian Light Infantry
brethren, stormed Vimy Ridge in 1917.
My parents were people who knew the
meaning of hard work. Yet when the
1950’s brought new, bigger, more
efficient machinery that resulted in
consolidation of farms, the more
successful farming operations gobbling up
the less successful, my parents found
themselves to be gobblees not gobblors.
They struggled in poverty until they
surrendered and moved to the city to take
up low-paying, unskilled labour jobs,
usually more than one at one time and,
most of the time, earning a little extra by
hosting boarders.
My parents died when I was a young adult
so I never got a chance to talk about adult
things with them. Why did some farmers go
on to get wealthy while our operation
shriveled? Why didn’t my parents buy
bigger, more efficient machinery? They
were smart and very hard working; why had
the economy graded them off the road?
In 2001, between my first private start-up
and the second and third, I asked the new
owner of my parent’s farm if I could
recover some rocks from my parents’
land, rocks that I would use in a massive
fireplace that was to be built into our new
house in Calgary. A monolith to honour
my parents, their struggle and the values
that they maintained as they walked the
toughest walk that I have ever seen
walked. “I’ve never counted my rocks,”
was the old gentleman’s reply and thus
began one of the greatest learning
experiences of my life.
The rock masons that we hired were very
particular. They only used a small portion
of the rocks that we collected and so we
went back many times. In the end there
were something like two dozen over-
loaded pick-up loads of rocks. At first I
was very selective, looking for rocks that
had very likely been touched by my
parents hands: rocks from mom’s rock
garden, rocks from the loose stone
foundation of the then still-standing three
room farm house, a rock at the gate post
for the barbed wire fence that kept the
grazing cattle out of the farm yard when
MID-CYCLE GAS PLAYS RANKED BY BREAK-EVEN PRICE (US$81/BBL)
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This boot diagram shows the same concept for gas projects. Note that, at the constant $US 81 for oil used by the analysts several of the gas projects (the ones
at the toe of the boot) do not need any gas revenue to achieve the profitability hurdle that the analyst used. We rely on analyst reports to understand the performance
expectations of other projects. We rigorously analyze our own, partly to check for discrepancies with analyst reports but mostly just to thoroughly understand
our own economics.
Graph source: Scotiabank Equity Research (‘The Playbook’), September 2014
9
SEVEN GENERATIONS ANNUAL REPORT 2014
my family lived there. I quarried the
flat-surfaced, square edged rocks from
the rock piles that my father, mother
and my older siblings had deposited
around the land.
It was a hot summer, that summer of
2001, and eventually, in search of the right
rocks, my wife and I would drive the truck
back and forth across the land checking
the stone strewn fields for rocks of the
right shape and size. That is when the
answer to some of my questions on my
parents’ financial failure occurred to me.
The land was on the flank of the Milk
River Ridge, the escarpment that forms
the continental divide between the
Mississippi – Missouri drainage basin and
the Saskatchewan drainage basin. It is
very hilly and very rocky. It was not high
quality grain farm land – not bad for
pasture but, with just half a section, that
use could not support a family. The land is
beautiful, there is a stunning close up
view of Old Chief Mountain, a mountain a
few miles away in Montana that is a
sacred location for the Blackfoot First
Nation. It should have been a park or, as it
is now, part of a big ranch, not a mixed
farm. My parents fought an unwinnable
battle to eke a living from that land and
lost. The economy rewarded the farmers
with the better land, the ones who used
their winnings to buy more land which
they could more efficiently farm with
modern equipment which they also
bought. As I looked around at the
abandoned equipment, a pull type
combine, multiple horse-drawn wagons,
I realized that my parents never had a
chance in the changing economy of their
day. As the realization came to me my
tears fell to the same soil that my family’s
sweat had so long ago quenched.
My parents’ marketplace for farm
products and ours for hydrocarbons have
four key parallels:
1. Nothing competes with the best
quality land. Both are an over-
supplied market with the strongest
factor in profit margin being the quality
of the land. The price settles, providing
thin margins for many, no profit
potential for some and strong
economics for only a few.
US NATURAL GAS MARKETED PRODUCTION HISTORY (BSCF/D)
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40
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1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
The above chart shows the remarkable growth in US Natural gas production. The growth is attributed mainly to shale and tight gas and oil (solution gas) projects.
The incremental production has displaced some Canadian gas out of some previously held markets in both Canada and the USA.
Data source: US Energy Information Administration (“EIA”).
10
SEVEN GENERATIONS ANNUAL REPORT 2014
food crops based on their market read.
We have consistently observed this in
the gas market since 2008, as year-
over-year, third party research shows
that supply costs are coming down
within the same plays, demonstrating
the impact that technology and
learnings are having on relative
economics.
2. The combination of high-quality
and large-size open doors for
business options, including vertical
integration, to meet the needs of
the business that the marketplace
fails to meet. In both cases,
maximum margin advantages accrue
for large scale and high-quality and it
must be both – the market does not
accept extra size for lack of quality or
extra quality for lack of size. The
biggest and best get bigger; the small
or poor quality, like my parent’s farm,
are likely to struggle to survive. Big,
high-quality operations have the
financial capacity to attract capital, to
adapt to changing markets, to invest in
the equipment needed to transform
products to a more marketable form or
to invest in the infrastructure required
to process and deliver products.
3. Innovation and operating
effectiveness provide advantages,
until competitors imitate or
surpass. With the quality and size to
compete, new technology and better
methods are required to gain the widest
margin. The struggle for market share
at the toe of the supply cost boot, the
fight among those with a chance to
win, is with more efficient machinery
and better methods yielding lower
costs as well as market access
assurance through vertical integration
and/or long-term delivery contracts
which only the most profitable can
undertake. The successful farmers of
my parents’ day were buying bigger
machinery to plant and harvest and
larger trucks to deliver their grain and
they were able to divert their land to
grow feed crops for their livestock or
)
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$120
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NORTH AMERICAN BENCHMARK COMMODITY PRICE HISTORY
CRUDE OIL (WTI)
NATURAL GAS (HENRY HUB)
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2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
The above chart shows that prices have averaged nearly $US 4 per MMBtu since the great recession. Given the US production growth since 2009, it may be prudent
to expect softer prices in the near term.
Data source: US Energy Information Administration (“EIA”).
11
SEVEN GENERATIONS ANNUAL REPORT 2014
4. Product diversity mitigates
commodity downside risk. Finally,
and my parents had just this one of
four on their side, product diversity
helps manage swings in individual
commodities. My parents had a mixed
farm, cattle and grain. 7G has liquids-
rich gas, liquids priced against oil and
natural gas and ethane priced against
gas. A year ago, both gas and
condensate prices were strong. Before
that condensate was strong but gas
was weak. Now both prices are weak
and we have two nearly independent
prospects for revenue recovery – not
just one and we can rail our liquids to
different markets. For the vast majority
of our liquids potential, we aren’t tied
to a low-reward market with a ribbon
of pipe. We are also diversified from a
sales standpoint; starting in December
2015, all of our gas will be sold into the
Chicago gas market, while virtually all
of our condensate will continue to be
sold into the Alberta market, and NGLs
will be split between Alberta sales and
US Midwest sales. Also, forward
curves for different products do not
move in tandem and we have and will
continue to be opportunistic and
hedge to lock-in margins when our
investment economics look attractive
based on prices in the futures market.
Unless a business is built to win in all four
of these areas, it is built to be lucky, not to
be good. Of course, to be successful, a
business needs capital as well but it
seems to me that access to capital is a
derivative of these four advantages – not
an isolated characteristic. I suspect that
with these four advantages a producer,
whether of petroleum or agricultural
products, has a strong probability of
getting access to the capital required to
maximize its shareholder value. As a
management team, over the past four
months since the IPO, 7G’s spokespeople
have expounded upon this fixation on
high-quality land, advancing technology,
product diversity, vertical integration
sufficient to deliver fungible products to
open markets and the size required to do
all of that. I learned these lessons from
my parents’ experience and they learned
them the hard way: the free market
system is ruthless. It is persistent. It is
overbearing. It demands the lowest cost
supply and when it has devoured that, it
seeks more but always the lowest cost
available. In an open market, like the
North American gas market, a business
built with these truths in mind is not so
reliant on luck and has a high probability
of succeeding.
We have been in the spotlight for many
investors and analysts. I can only
speculate as to the reasons: recent
collapse of commodity prices, newly
listed on a public stock exchange, very
high projected growth rate with firm
pipeline transportation commitments,
coverage by a significant number of bank
research analysts, tight liquids-rich gas (a
high profile sub-sector of the industry),
balance between oil and gas price
exposure. Investors and analysts have
been curious to understand our thinking
about business strategy. In the following
paragraphs I will summarize the basis of
our thinking in the areas attracting the
most curiosity:
The North American gas market
is oversupplied.
The North American gas market seems
close to the free market economy that my
introductory economics textbook
described. The majority of gas trading is
done with minimal regulation in free
market economies. Classical supply and
demand theory would suggest that price
can be the mechanism expected to bring
into balance supply and demand. Recent
gas price drops can be attributed to
oversupply, the result of huge growth in
production capability in recent years due
in large part to commercialization of
recovery processes for (largely previously
known) shale gas and tight gas and oil.
Markets tend to overshoot the balance
point when correcting so there may be
some gas price recovery pressure on
recent prices, but increasing supply is
imposing downward pressure on the
price. Gas producers, Seven Generations
included, have been very successful in
reducing their costs. The result is that
more gas can be produced at any given
price creating further downward pressure
on gas prices. Rather than assuming a
recovery to the post January 2009
average of nearly US$4.00/MMBtu, a
safer assumption for strategic planning
purposes would be that gas prices will
12
An aside on commodity
pricing (my view anyway)
For my entire 40 year career,
international oil prices have
been set in the global market,
for seemingly political reasons,
by a small group of producing
countries with both oil supply
and (external and/or internal)
political instability in
abundance. Oil prices have
cycled up and down as global
consumption has increased.
With each wave of new
technology, deep off-shore
drilling and production, arctic
drilling and production, oil
sands recovery technologies,
tight oil recovery, new
business opportunities open
up and the supply keeps
coming. I am among those that
believe that the onset of
permanent oil scarcity is
imminent, that we have nearly
exhausted the earth’s
reasonably accessible supply. I
confess that I started my
career expecting to be in
business the day that oil
production peaked, staking a
claim to that very barrel that
marked the world’s maximum
productivity but now it
appears that I am running out
of career faster than the world
is running out of oil – that is a
good thing.
Gas prices in North America
are set by an open, competitive
market, about as close to the
classic free market described
in my economics text book as
one can get. One significant
barrier to entry for gas
developers, however, is
inadequate transportation and
processing infrastructure in
some regions. Again, the
advantage goes to the
developer that has both the
size and quality and, again, it
must be both to underpin
expansion of market access
infrastructure from local
plants and pipelines to
transcontinental pipelines.
SEVEN GENERATIONS ANNUAL REPORT 2014
remain low and that we can expect gas
prices to average significantly less in near
years. The gas price needs to settle at a
level that will discourage development of
more costly sources and encourage the
development of new markets such as
gas-fired power generation, petrochemical
production and liquefied natural gas
(“LNG”) export.
Margins should yield attractive
economics for projects at the
toe of the supply cost boot.
North America is constantly in need of
renewal of the supply of gas because
production from existing wells generally
declines and there has been some, albeit
modest, growth in the North American
Gas Market in recent years. Back to my
introductory economics textbook: when
an efficient free market needs additional
supply it sends a price signal that
motivates suppliers to deliver sufficient
commodity to meet the demand. If
transportation and processing
infrastructure are in place, the lowest cost
suppliers, those at the toe of the boot,
should be the first to be willing and able to
drill new wells to meet new demand. The
market demand may be such that several
of the projects that are closest to the toe
of the boot are lured into growing supply.
If that is the case then the ones closest to
the toe should have wider margins than
the one which just barely met its owner’s
profitability criterion. In fact, if the market
is calling on enough new supply,
economics can be quite attractive for the
lowest cost suppliers. One inefficiency
that the market has is that it takes time
and capital to respond. The owner of the
lowest cost gas supply will only be able to
bring a portion of its gas to market due to
practical limitations of financing and
managing its rate of growth – so even
though the market calls for the lowest
cost supply, only some of it can be
delivered in short order. To meet demand
prices must be sufficient to call gas from
the second, third, fourth and so on lowest
cost suppliers. This means that the
projects at the toe of the boot can have
quite attractive economics. To illustrate: in
the mid US$2 to US$3/MMBtu range,
where benchmark gas prices have been in
2015, about half of the projects on
Scotiabank’s chart presented previously
would meet the Scotia analysts’
profitability criteria given compliance with
the other assumptions (including oil price)
used in the chart. That means that while a
lot of projects may contribute gas to meet
the demand, some will have marginal
economics, while those nearest the toe of
the boot might still have very attractive
economics. For 7G’s best lands, Nest 2 in
particular (as defined in prior corporate
INTERNAL RATE OF RETURN: TYPE CURVE SENSITIVITIES
(pre-tax, management P50 type curves)
NEST 1
NEST 2
Solid line = 10% IRR
Dotted line = 20% IRR
)
U
T
B
M
M
/
$
D
S
U
(
s
a
G
X
E
M
Y
N
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
-$1.00
-$2.00
-$3.00
-$4.00
$30
$35
$40
$45
$50
$55
$60
$65
$70
$75
$80
$85
$90
$95
$100
WTI (USD $/bbl)
Key Assumptions:
i) Pricing: NGLs as % of WTI: C3 45%, C4, 55%, Alberta C5+ 101%. AECO basis: > of 15% NYMEX or $0.40/MMBTU. $0.82 USD/CAD FX rate.
ii) Transportation: sales gas $0.35/mcf. Recovered liquids: $3.50/bbl. Average opex (first 3 years) = $4.07/boe (Nest 2), $5.17 (Nest 1).
iii) $6.0MM natural gas deep drilling credit pool. 1,193BTU/scf rich gas. 14.7% raw gas shrink (fuel gas & NGL extraction).
13
SEVEN GENERATIONS ANNUAL REPORT 2014
presentations and our IPO prospectus),
recent prices have been sufficient to
encourage the Company to continue
growing production to meet demand and
gain market share.
One aspect of most of the lowest gas
supply cost gas projects on the Scotiabank
chart is that the gas that they produce is
liquids-rich. At the oil price that Scotiabank
used, several of the projects at the toe of
their supply cost boot can meet the
profitability criterion without receiving any
revenue from the gas. For liquids-rich gas
and tight oil that is rich in solution gas,
the second commodity is often very
important to the overall economics. While
the US$81 per barrel (presumably WTI at
Cushing) that Scotiabank used in their
analysis seems high relative to oil prices
that have prevailed so far in 2015, that
number seems quite conservative if we
compare it to the average price since
January 2011 (which, according to the EIA
data presented on a previous chart, was
more than US$90 per barrel). So a question
that arises is: how well do the projects at
the toe of Scotiabank’s boot compete with
the others if the oil price is much lower? To
give you a sense of how Seven
Generations’ Nest 2 Montney type curve
compares, we estimate that the gas price
required to get a 10% before tax internal
rate of return if the oil price is $50 US per
barrel would be US$1.01/MMBtu (see
graph on page 13 for other cost & price
assumptions). While the contribution of the
liquids to the profitability of the well is
greatly reduced on a boe basis, at US$50
the liquids are still fetching nearly three
times the revenue as gas (on a heating
value equivalency basis). We think that,
unless the liquids are severely impairing
productivity (which can happen), rich gas is
still preferable to lean gas given the same
resource rock quality. With a spectrum of
liquid gas ratios to call upon from our lands,
we are still focusing development on
Nest 2 which, on management’s best
estimate type curve, yields 110 barrels of
field separator condensate per million cubic
feet of raw sales gas during the first six
months of production.
How oversupply may ultimately
affect project valuations.
Historically, with an outlook to shortages of
oil and gas and a constant need for the
industry to find more petroleum, and
therefore to develop increasingly marginal
resources, there was some comfort in
valuing projects and companies on the
basis of their reserves. With reserve
evaluation methods largely standardized (at
least within securities trading jurisdictions),
values of projects could be compared
reasonably objectively using reserve
values. These estimates use forecasts of
production, capital expenditures, operating
costs and burdens, along with the
evaluator’s commodity price forecasts, to
estimate a net present value for the
resource. With resource plays and other
large, early stage developments, the
independent evaluators have adopted
standards as to how far into the future, and
on what degree of assurance of
development, production and markets they
will include or not include production. With
resource plays, for example, the evaluator
may book five or 10 years of forecast
production if it is comfortable that the
projects will be sanctioned and financed by
the developer, approved by the regulators
and that the products will have markets
and transportation. For very large
resources, like 7G’s Kakwa River Project,
the five or 10 year forecast may be just a
fraction of what the developer expects to
achieve in terms of recovery and peak
production rate. Using a limitation of
production, given demonstrated operating
costs and other burdens translates quite
well with the finance industry’s standard
practice of evaluating a Company based on
a multiple of its EBITDA or cash flow
generating capacity. Stated differently, in
an oversupplied market, large resources
with early stage projects that are still in a
rapid growth ramp seem likely to be
conservatively valued by standard reserve
valuation processes. Much of the owner’s
expected ultimate recovery does not make
it into a defined reserves category.
The coal-fired power generation industry
may be a good example of where gas
project valuation may evolve. Coal-fired
electric power generation projects may be
backed by decades or even centuries of
coal supply. For many, practically, the coal
reserve backing the forecasted revenue is
irrelevant to value. It doesn’t matter to the
value of the firm if it has 100 or 400 years
of reserves. What matters is how much it
is able to earn in a relatively stagnant
demand market with its market share.
Given the gross oversupply in the gas
market, it may be prudent to consider
market share and earnings more
prominently in valuation.
The most significant conclusion from this
line of thinking is that it is important to
capture and hold market share, including
transportation and processing that
enables market access. This then gets us
to the response to an often asked
question, “Would it be better to shut in
and save the Company’s reserves to
deliver at a higher price?” There are a lot
of reasons why the answer to the
question is “no”, among them:
¡¡ We have robust economics on the
land that we are focusing our
development activity at prices we
have averaged over the past six
months and at forward prices that
we can currently hedge;
¡¡ We have transportation and processing
contracts which are coveted by
other operators who find themselves
already short of market access and the
easiest way to preserve those is to fill
the demand;
¡¡ We have an inventory (by management’s
estimate) of more than 600 wells in our
most economically attractive area. This
inventory represents seven to 10 years
of drilling at the rate required to ramp up
production in accordance with our
marketing agreements. Deferral of
production by more than 10 years is
likely to negatively impact our value for
the most optimistic gas price forecasts
and the lowest costs of capital;
¡¡ It will be easier to capture more
market access as we get larger. With
production at one-fourth to one-third of
our contracted (2018) peak delivery
rate, we presently have less revenue
and less credibility to engage in
negotiating for more pipeline space;
14
SEVEN GENERATIONS ANNUAL REPORT 2014 ¡¡ We need to continue to advance
technology and operating methods
that will reduce the cost and keep the
Company in the race for the toe of the
supply cost boot. We believe we can
find ways to make the more than 300
estimated undeveloped well locations
in Nest 1 more profitable and make
development of those resources more
resilient to low prices. The same can
be said for our deep high pressure
sour lands and our Wapiti lands; and
¡¡ We can use the downturn in the
service and supply industry to engage
the most experienced contractors and
the best equipment under the best
terms, helping to minimize short term
cost and maximize long term value
through accelerated learning and
improved efficiency.
The persistent need for new
supply in the North American
gas market.
The North American gas market is
constantly in need of additional supply.
Existing wells decline and there has been
some growth in demand in recent years.
One presentation that I saw a few years
back suggested that the base gas
production for North America, at the time
dominated by conventional gas
production, declined with a constant
percentage of about 20 to 25% per year.
Early in the development of tight and
shale gas wells, operators often
experienced more than 50% decline in
the first year with lower rates of decline in
successive years, often reaching decline
rates of less than 10%, or nearly flat
production. Since then the market and the
base production has evolved to be
dominated by the steeply declining shale
and tight gas production which should
imply that, if new wells are tied in to just
meet demand, with no surplus capacity to
supply, we should need to replace a large
proportion of North America’s production
each year. As the tight gas industry has
matured, there has been a buildup of late
life wells providing a base of production
that produces with very low decline rates.
The situation may be aggravated by the
learning of 7G and others that, if wells are
constrained when first brought on to
production, the overall decline rate is
reduced such that the cumulative
production of the constrained well
exceeds the cumulative production of the
aggressively produced well, perhaps even
significantly within the first year. What
this means is that producers who have a
low decline rate base, especially those
who have found that initial performance
can be improved by constraining new
STACKED GAS PRODUCTION EXAMPLE: LOW TAIL DECLINE ANALYSIS
60 wells, 1 new per month for 5 years
$5
)
d
/
f
c
M
M
(
n
o
i
t
c
u
d
o
r
p
s
a
G
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100 105 110 115
Months on production
15
SEVEN GENERATIONS ANNUAL REPORT 2014
decades. So North America’s gas
production and gas demand are in
balance and, with minor adjustments
year-over-year, there is enough resource
to keep the market satiated. Some of the
resource producing regions, especially
those with large, high quality resource
plays, have inadequate market access
infrastructure and will have to build
infrastructure to access markets.
In turn, that new infrastructure may
make some existing capacity to higher
cost supplies redundant. To get the
lowest cost supply, North America
needs the new infrastructure to expand
markets beyond our shores. To get market
access, many quality resource owners will
have to tackle the local infrastructure
shortage problem.
Here are some other possible derivatives
of the present market access
infrastructure situation:
¡¡ Astute high-cost developers may
realize their predicament and try to off
load their market access commitments
or they may try to acquire assets from
developers who do not have capacity.
Either way, market access is likely to
become more valuable;
¡¡ There are economies of scale in larger
pipelines, economies that can result in
a lower tariff for the infrastructure
subscribers, economies that can shift
gas resources toward the toe of the
supply cost boot. Developers are
motivated to work with others to
aggregate enough volume to secure
these economies or they may be
motivated to capture additional high
quality resources so that they can
commit to larger volumes themselves;
wells, have an advantage in holding
market share to those who are in early
stages of development and still ramping
up. The latter group have no flat base
production and have to invest in new
gathering, processing and shipping
facilities to establish a market share.
Again, there is a clear first-mover
advantage to securing and holding market
share. The analysis below demonstrates
this point visually: it is a stacked line graph
of gas type curves, with a new type curve
added once every month for five years,
followed by declines on all wells for the
remaining five years. The type curve used
is a typical tight gas well, with a steep
initial decline (77% in the first year)
followed by a flattening in the tail such
that, after 10 years, the annual decline
rate is in the 7 to 8% range and produces
an extremely flat production base. As can
be seen in the graph, after five years of no
drilling, the wells in aggregate are still
producing at 20 to 25% of the peak
production point. We are now five to
seven years out since tight and shale gas
drilling emerged, and this stacked
production base is clearly manifesting
itself as a supply glut, evidenced most
strongly in the persistently high natural
gas storage levels at central storage and
clearing hubs.
Who needs expanded market
access infrastructure?
Gas demand has been relatively stagnant
in North America for a few decades. In
the most recent years demand has risen
to supply new power plants and oil sands
plants. Supply of gas by estimates that I
am aware of has totally outstripped
demand, putting us into a surplus of
supply situation. I think pretty much
everyone accepts that. A problem that has
arisen though, is the location of the
market access infrastructure; the
transcontinental pipelines that ship gas
from producing regions to consuming
regions and the gas plants that convert
raw gas to its marketable components are
not in close proximity to the new lost gas
supply. There is about enough pipe for
producing regions to supply consuming
regions with gas and suppliers in those
producing regions are happy enough.
Owners of new shale and tight resource
developments are more often challenged
to find the infrastructure that they need
now or that they foresee needing in the
future to get their gas to market. Often
the stranded gas, the gas with no market
access, could be the lowest cost supply if
it had access to market. Getting access to
market is not as simple as it may seem.
Developers may not have enough gas to
support a new pipeline by themselves so
they need to act in aggregate. Usually a
mid-stream utility company, a pipelining
and processing specialist, will facilitate
the joint action by a group of resource
owners to support new infrastructure
addition. The producers need to test their
lands to gain an understanding of the
recovery potential and the threshold price.
They then have to determine how much
gas that they can deliver with a strong
expectation of delivering that gas at a
cost that is below the price. Generally
market price contracts float with the
market price – so the producer must
determine his own costs and estimate
where the price will be which, as
discussed earlier in this letter, is really an
exercise in determining where a project
fits on the supply cost boot. The producer
must ask himself, “Will we be able to
produce gas at a profit given the price
pressures due to the oversupplied
market?” Obviously it is going to be tough
for developers with gas supply costs in
the middle of the supply cost boot to
commit to any market. How can their
Boards approve a huge commitment to
pipeline and processing capacity when
they can’t be confident that their gas can
be produced profitably? This implies that
market access infrastructure expansion
must be led by the developers at the toe
of the supply cost boot. For Canada, that
may mean that the projects at the toe of
the supply cost boot (remember: largely
liquids-rich gas projects) are the ones that
need to underpin new LNG projects off of
Canada’s west coast. For developers such
as 7G, those with a lot of growth
potential, those with an array of gas
resources, much of it at or near the toe of
the boot, there is a need to use the low
supply cost and large resource position to
secure the best market access
arrangement possible. That is a focus for
us. In my view, not keeping market access
up with our ability to develop high quality
resources is the biggest risk we have in
maximizing shareholder value. As stated
earlier, reserves and resources aren’t
much good if they cannot be produced for
16
SEVEN GENERATIONS ANNUAL REPORT 2014 ¡¡ Infrastructure expansion projects are
financed over many years, probably a
bias to the high end of the 15 to 30
year range. This is done to keep the
tariff as low as possible given the
expected useful life of plant and
pipeline infrastructure. Developers
need to consider the anticipated
contango as the market works its way
through the lowest cost supply and
takes on more and more expensive
gas to meet its needs over the life of
the infrastructure commitment.
Developers will also consider the
downward pressure on supply costs
resulting from what the industry has
been able to achieve with new
equipment and operating methods
already, and the probability that this
will continue to reduce costs, making
much of the currently marginal
resource more attractive in the future.
Many producers will take the view that
not all of the gas has to have high
profitability in the present market;
¡¡ Coordination of midstream and
upstream companies into a joint
infrastructure expansion and execution
plan can be very time consuming.
Those developers that have the
financial capacity may wish to save
time by driving the terms of the
projects, either for their own gas or
for their own gas plus competitor gas,
but at terms driven by the major
proponent. Developers with large,
high-quality resource positions may
wish to bolster their positions in
order to be in a better position to
drive terms. Gas developers may, at
least temporarily, vertically integrate
into portions of the infrastructure
business to get over the need for
time consuming consensus building.
Many resource developers, especially
in the US where there is a corporate
vehicle that passes through the
taxation to the shareholder, are
spinning out their midstream assets
now that their needs have been met
under direct management of the
midstream business during the growth
phase; and
¡¡ Full vertical integration may provide
for overall project profitability or at
least provide that appearance
outwardly. It would seem ridiculous
for a high cost developer to develop
its own resources at a higher cost than
it could buy production from others.
If viewed that way, the fully integrated
companies proposing LNG projects
may consider export at the price set
by the LNG exporters on the Gulf of
Mexico to be an alternative to their
own investment (adjusted for land
and shipping transportation cost
and other cost differences). If that is
the case, then announced projects
may be cancelled or delayed if they
can’t compete with buying LNG at
North American benchmark prices
on the Gulf. If such projects are
cancelled or delayed, the proponents
may want to dump gas from the drilled
wells into existing over-loaded North
American infrastructure.
the last five years or so, and with
about 40 wells, by improving many types
of equipment and operating practices,
Seven Generations has been able to cut
its per metre of lateral drilling cost by
roughly 50%. The success ratio of the
techniques tried was very high and the
ideas for further cost cutting have not
been exhausted.)
What this means to us is that, to be
successful, a developer has to have large,
high quality resources and participate in
the technology race. The technology race
is ongoing. As long as competitors are
finding ways to advance the value of their
projects, there is a risk of them leap-
frogging to a position closer to the toe of
the boot, displacing the non-technical
developer out of the market. In other
words, the technology race is a race that
can be lost but never won – another
reason to keep advancing the business in
the current commodity price environment.
The importance of technology.
Summary:
Here are our key strategic leanings and
steps for moving forward:
¡¡ Continue to develop but focus on the
large inventory of Nest 2 drilling
where, we believe, profitability is most
resilient to low prices. We believe that
our Nest 2 asset is among the ‘toe-of-
the-boot” opportunities in the North
American industry and, therefore,
prices will settle at levels than make
its development financeable;
¡¡ Continue to apply learnings in Nest 2
to Nest 1 development pad locations.
The majority of our optimization work
to-date for drilling and completions has
been in Nest 2 and a number of Nest 1
locations have displayed well
performance and early-stage economic
performance well above type curve;
We believe that the gas market is so
competitive that the business has to be
attacked on two fronts to maximize
shareholder value:
1. Securing the highest quality assets
including the hydrocarbon resource
and the market access infrastructure
(which can best be secured with both
size and quality); and
2. Positioning for competency in
capturing the potential benefits
of new technology and better
operating practices.
A business that does not secure high
quality resources cannot compete and
cannot be fixed. A business with high
quality assets must competently search
for more efficient practices, lest it be heft
up into the instep of the supply cost boot
by those who are truly the low cost
suppliers. The shale and tight gas
resource development business is still
fairly new. Individual wells are expensive
so developers use caution when testing
new methods – looking to advance the
business incrementally to reduce both the
risk and the cost of any adjusted practice
that is not successful. (For example, over
17
SEVEN GENERATIONS ANNUAL REPORT 2014 ¡¡ Use the financial options available to
us (debt, equity, joint venture
partnerships, offering transportation
and processing) to the best advantage
in order to continue to grow
shareholder value.
Reader Advisory: for important additional information
regarding the forward-looking statements that are set
forth above and the risks associated with achieving
the results described in those statements, as well as
information regarding certain abbreviations have been
used, please see the Company’s Management’s
Discussion and Analysis dated March 10, 2015 and in
particular the disclosure provided under the heading
“Forward-Looking Information Advisory”.
Finally, I would like to thank the Board,
staff and contractors working for Seven
Generations for their professionalism
and dedication displayed in their work.
I am writing about a dedication that
goes far beyond geological maps, or
invoices processed, or pipe welded.
I am thanking them for the things that
they do to contribute to the workplace
and the community. Our Code of Conduct
is attached. Our broader team strives
to deliver what that Code intends, that
we live up to the spirit of our name,
that we exist to serve the greater good.
We believe that to thrive for the long
term a corporation must stand out as
being different and better than its
competitors in meeting the needs of its
stakeholders. My thanks go to the
employees that talk about their profession
at schools in the region, the contractors
who identify safety hazards so that we
can take measures to protect them and
their coworkers, the suppliers of goods
and services who generously support our
annual golf tournament that benefits
Grande Prairie’s Queen Elizabeth Hospital
Foundation, the employees who proudly
tour regulators and community leaders
through our operations, and everyone
who contributes to our stakeholder
engagement efforts. The Grande Prairie
area, The Peace Region, as they
appropriately call themselves, have
welcomed us to be part of their
community. We proudly call ourselves
Seven Generations Energy Ltd., Grande
Prairie’s Energy Company.
Sincerely,
Pat Carlson, P.Eng.
CEO
¡¡ Shelve the delineation and production
capital used to establish type curves
of deep high pressure sour and Wapiti
sour and zones other than the Upper
and Middle Montney because their
resources are not needed for a long
time without expanded access to
markets and they are not profitable
or, at best, marginal at the current
state of technology adaptation and
price environment;
¡¡ Continue to experiment to find ways
to increase capital efficiency and
reduce costs in search of two
benefits: direct improved profitability
to the lands upon which the
technologies are demonstrated and
possible applications to other lands
such as Deep Southwest and Wapiti
that have the potential to move
development of these resources to the
toe of the supply cost boot;
¡¡ Use the continuing activity in the
industry downturn to upgrade to the
best equipment and services the
Canadian gas industry has to offer, and
negotiate competitive pricing that
recognizes the new market reality;
¡¡ Aggressively pursue quality market
access expansion opportunities
by ourself, with potential upstream
partners and with potential
midstream partners;
¡¡ Look for accretive acquisitions that
offer the potential to assist us to
balance market access with our
resource size. This may include
acquiring more land that has resources
at or near the toe of the boot. It may
include projects or companies that
have excess transportation capacity
that we can use. In all cases we will
look for a strong probability for our
pre-deal shareholder value to increase
as a fully realized result of the
transaction; and
18
SEVEN GENERATIONS ANNUAL REPORT 2014 SEVEN GENERATIONS CODE OF CONDUCT
We believe that companies have only the rights given to them by society. While people have a natural entitlement to basic rights,
corporations are an instrument created by society to provide its needs and ought to have no expectation of basic entitlements other
than equitable rights with other corporations, including those wholly owned by a person. We recognize that rights, sufficient to build
and operate an energy project, can be granted and taken away by society. Over the longer term, companies can only expect to
thrive if they serve the legitimate needs of society in which they exist. To thrive, companies must differentiate, rise above the pack,
standout as being among the best with all of their stakeholders. At Seven Generations Energy Ltd., we acknowledge this granted
entitlement and accept from our stakeholders a duty to thrive and an understanding of the need to differentiate.
Specifically, in acceptance of this challenge to differentiate with all stakeholders, we acknowledge:
1. The need of society for us to conduct our business in a way that protects the natural beauty of the environment and preserves
the capacity of the earth to meet the needs of present and future generations;
2. The need of Canada and Alberta for us to obey all regulations and to proactively assist with the formulation of new policy that
enables our company and our industry to better serve society;
3. The need of the communities where we operate to be engaged in the planning of our projects and to participate in the benefits
arising from them as they are built and operated;
4. The need of our business partners and infrastructure customers to be treated fairly and attentively;
5. The need of our suppliers and service providers to be treated fairly and paid promptly for equipment and services provided to us
and to receive feedback from us that can help them to be competitive and thrive in their businesses;
6. The need of our employees to be compensated fairly and provided a safe, healthy and happy work environment including a
healthy work life – outside life balance; and
7. The need of our shareholders and capital providers to have their investment managed responsibly and ethically and to earn
strong returns.
We see ourselves as being in the service business, serving the needs of our stakeholders. We seek satisfaction for all stakeholders.
Differentiation is imperative. We support an open and competitive business environment, recognizing in the competitive world that
we envision, only those who best serve their stakeholders can expect the support required to survive for the longer term.
19
SEVEN GENERATIONS ANNUAL REPORT 2014 MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”), dated March 10, 2015, is Management’s assessment of the
historical financial position and results of Seven Generations Energy Ltd. (the “Company” or “Seven Generations”) and should
be read in conjunction with the audited annual financial statements (the “financial statements”) as at and for the years ended
December 31, 2014 and 2013. The financial information contained herein has been prepared in accordance with International
Financial Reporting Standards (“IFRS”). All dollar amounts are expressed in Canadian currency, unless otherwise noted.
Certain financial measures referred to in this MD&A are not prescribed by IFRS. See “Non-IFRS Financial Measures” for
information regarding the following non-IFRS financial measures used in this MD&A: “funds from operations”, “operating income”,
“operating netback” and “available funding”. Additional information about Seven Generations is available on SEDAR at
www.sedar.com, including the Company’s Annual Information Form dated March 10, 2015 (“AIF”). The Company’s common
shares are listed on the Toronto Stock Exchange under the trading symbol “VII”.
This MD&A contains additional generally accepted accounting principles (“GAAP”) measures, non-GAAP measures and
forward-looking statements. Readers are cautioned that the MD&A should be read in conjunction with Seven Generations’
disclosure under the headings “Non-GAAP Measures”, “Forward-looking Information and Advisory” included at the end of
this MD&A.
ABOUT SEVEN GENERATIONS ENERGY LTD.
Seven Generations is a Canadian company focused on the acquisition, development and value optimization of high quality tight and
shale hydrocarbon plays. Presently, the Company has a single focus area, the Kakwa River Project, a large-scale, tight, liquids-rich
natural gas property located in the Kakwa area of northwest Alberta (the “Project”).
Seven Generations differentiates itself based on the following core attributes:
¡¡ Quality of Resource – the upper and middle intervals of the Triassic Montney formation in the Project have emerged as a highly
economic play, comparing favourably to other North American tight, liquids-rich natural gas plays based on the low break-even
natural gas and liquids prices required for the Company to earn a minimum rate of return on its investment needed to add wells
to the Project. Horizontal wells in the primary development block of the Project have exhibited high production rates of natural
gas, condensate and other natural gas liquids (“NGLs”);
¡¡ Size of Resource – the Company controls approximately 70,200 net acres of Montney land which as at December 31, 2014, are
estimated by McDaniel & Associates Consultants Ltd. (“McDaniel”), Seven Generations’ independent reserves and resources
evaluator, to hold approximately 680 net wells (89% undrilled), which have gross proved plus probable reserves of 789 MMboe;
¡¡ Location and Market Access – the Company’s lands are close to key infrastructure and take-away capacity, including the
Alliance and Pembina Peace pipelines, on which it has contracted firm transportation capacity for natural gas, condensate, other
NGLs and oil;
¡¡ Control over Operations – Seven Generations operates approximately 98% of its land and it owns a 100% working interest in
its facilities and gathering systems; and
¡¡ Ability to Execute – the Company has assembled a highly skilled technical and business team with a specialized expertise in
resource play identification, capture, development, and production. The team has a track record of growing production, reserves
and funds from operations and enhancing project economics through technical innovation. The Company’s ability to deliver on its
high growth objectives is supported by existing marketing and transportation agreements for the first 500 Mmcf/d of natural gas
production and approximately 40,000 bbls/d of condensate and other NGLs production.
20
SEVEN GENERATIONS ANNUAL REPORT 2014 Independent Reserve Evaluations
Reserves and Resources (MMboe)
Proved reserves (1)
Proved plus probable reserves (1)
December 31, 2014
July 1, 2014
December 31, 2013
421
789
328
649
107
283
(1) Company gross reserves as determined by Seven Generations’ independent reserve evaluator.
The Company’s independent reserve evaluators, McDaniel & Associates Consultants Ltd., completed independent reserve
evaluations effective December 31, 2014. Based on the evaluator’s report and the assumptions made therein, Seven Generations’
gross proved plus probable reserves increased 179% to 789 MMboe (approximately 53% of which is condensate and other NGLs)
when compared to the December 31, 2013 estimates. At December 31, 2014, the independent reserve evaluators estimate the
Company’s total gross proved and probable reserves have a before tax net present value of $7.1 billion compared to $3.1 billion
(using a 10% discount rate) from the December 31, 2013 reserve report. The Company’s oil, NGLs and natural gas reserves are
located primarily in the Kakwa area. The July 1, 2014 reserves and resources were prepared in conjunction with the Company’s IPO.
For definitions and additional information regarding Seven Generations’ reserves estimates, refer to the Company’s AIF which is
available on SEDAR at www.sedar.com.
Selected Financial Information
INCOME STATEMENT
Oil and natural gas sales (1)
Royalties
Risk management contracts – realized gain
Risk management contracts – unrealized gain (loss)
Interest and third party income
Operating expense
Transportation expense (1)
General and administrative expense
Depletion, depreciation and amortization expense
Stock based compensation expense
Finance expense
Foreign exchange loss
Liquidity event expense
Gain on disposition of assets (1)
Income (loss) before taxes
Deferred income tax expense
Net income (loss) and comprehensive income (loss)
Net income (loss) per share – basic
Net income (loss) per share – diluted
Three months ended December 31
Year ended December 31
2014
2013
2014
2013
155,383
(16,145)
139,238
22,163
123,772
1,968
287,141
18,966
13,237
7,393
56,923
3,897
17,058
25,560
35,947
-
178,981
108,160
39,532
68,628
0.30
0.28
48,484
(3,188)
45,296
49
(1,978)
628
43,995
8,425
3,286
2,052
13,708
1,552
9,564
10,740
-
-
49,327
(5,332)
293
(5,625)
(0.03)
(0.03)
534,833
(51,890)
482,943
9,737
141,765
4,987
639,432
54,261
34,833
20,258
159,447
11,950
63,641
47,673
35,947
(4,286)
423,724
215,708
71,508
144,200
0.73
0.64
113,184
(7,853)
105,331
279
(3,299)
2,896
105,207
20,615
6,461
8,117
38,921
9,556
24,447
10,897
-
-
119,014
(13,807)
351
(14,158)
(0.08)
(0.08)
21
(1) Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation.
SEVEN GENERATIONS ANNUAL REPORT 2014 Well Information
Number of wells drilled – gross (net)
Number of wells completed – gross (net)
Number of wells brought on production – gross (net)
Three months ended December 31
Year ended December 31
2014
14 (14.0)
11 (11.0)
9 (9.0)
2013
11 (10.7)
9 (9.0)
10 (10.0)
2014
49 (49.0)
38 (38.0)
34 (33.7)
2013
23 (22.7)
17 (17.0)
14 (14.0)
During the year ended December 31, 2014, the Company drilled 49 gross wells and 34 gross wells started production compared to
23 gross wells drilled and 14 gross wells on production in 2013. The well counts include only horizontal Montney wells. Drill counts
are based on the rig release date and on production counts are based on the first reportable production date.
Results of Operations
Daily Production
Oil and condensate (bbls/d)
NGLs (bbls/d)
Natural gas (Mmcf/d)
Total (boe/d)
Three months ended December 31
Year ended December 31
2014
14,747
10,783
112
44,178
2013
% Change
4,480
2,291
29
11,585
229
371
286
281
2014
11,061
6,989
79
31,136
2013
% Change
2,390
1,749
22
7,786
363
300
259
300
The Company’s production for the fourth quarter of 2014 averaged 44,178 boe/d, which represents a 281% increase over
11,585 boe/d in the fourth quarter of 2013 and a 23% increase from the third quarter of 2014 which averaged 35,820 boe/d.
For the 2014 year, the Company‘s production increased to 31,136 boe/d compared to 7,786 boe/d for the same period in 2013,
an increase of 300%. Since the beginning of 2014, the Company increased the pace of drilling and infrastructure capital
investments that translated into significant increases in production. The Company also utilized various techniques to increase
production rates per well including longer lateral lengths combined with larger fracs. The higher production volumes are also related
to the completed construction of four “super pad” facilities during 2014, which are well pad sites that contain natural gas
compression, separation, dehydration and liquids pumping capabilities.
Commodity Pricing
Average Benchmark Prices
Oil – WTI (US$/bbl)
Oil – Edmonton Par ($/bbl)
Natural gas – AECO NGX 5A ($/mcf)
Average exchange rate – (CAD$ to US$)
Three months ended December 31
Year ended December 31
2014
2013
% Change
2014
2013
% Change
73.15
74.37
3.58
0.881
97.46
86.25
3.48
0.953
(25)
(14)
3
(8)
86.50
93.94
4.78
0.914
97.98
93.24
3.12
0.971
(12)
1
53
(6)
22
SEVEN GENERATIONS ANNUAL REPORT 2014 The Company realized the following commodity prices (before hedging):
Oil and condensate ($/bbl)
NGLs ($/bbl)
Natural gas ($/mcf)
Total ($/boe)
Three months ended December 31
Year ended December 31
2014
69.93
21.50
3.81
38.23
2013
% Change
80.63
24.54
3.79
45.49
(13)
(12)
1
(16)
2014
85.34
24.10
4.50
47.06
2013
% Change
85.49
18.76
3.34
39.83
-
28
35
18
The Company’s average realized price for oil and condensate decreased in the fourth quarter of 2014 by 13% to $69.93/bbl
compared to $80.63/bbl for the same period in 2013. For the 2014 year, the Company realized average price for oil and condensate
decreased by $0.15/bbl to $85.34/bbl compared to $85.49/bbl for the comparative period in 2013. The decrease in oil prices
realized by the Company is consistent with the benchmark Edmonton Par price.
The average realized prices for NGLs primarily reflect a combination of prices for NGLs such as ethane, propane, butane and
pentane. The Company’s average realized prices decreased for this product stream in the fourth quarter of 2014 by 12% to
$21.50/bbl compared to $24.54/bbl for the same period in 2013. For the 2014 year, the Company realized average prices of
$24.10/bbl for NGLs as compared to $18.76/bbl for the comparative period in 2013, an increase of 28%. Quality adjustments,
mainly due to amounts of butane that remain in the condensate shipped, impact the realized prices the Company received.
The Company’s average realized natural gas price increased by 1% in the fourth quarter of 2014 to $3.81/mcf compared to
$3.79/mcf in 2013. For the year ended December 31, 2014, the Company’s average realized natural gas price increased by 35% to
$4.50/mcf compared to $3.34/mcf in 2013. The Company receives a blend of pricing based on AECO monthly and daily benchmark
indexes, with adjustments for heat content. The relative pricing between these two indexes has fluctuated throughout the year.
Revenues
($ thousands)
Oil and condensate
NGLs
Natural gas
Revenues (excluding realized gains or losses
on risk management contracts)
Three months ended December 31
Year ended December 31
2014
94,873
21,329
39,181
2013
% Change
33,226
5,174
10,084
185
312
289
2014
344,512
61,470
128,851
74,548
11,977
26,659
2013
% Change
155,383
48,484
220
534,833
113,184
362
413
383
373
Revenues increased by $106.9 million, or 220%, to $155.4 million in the fourth quarter of 2014 compared to $48.5 million in the
same period of 2013. The increase in revenues is due to higher production volumes ($114.6 million) offset by lower commodity
prices ($7.7 million). For the year ended December 31, 2014, the increase in revenues was $421.6 million, an increase of 373%
compared to the same period in 2013 due to increased production ($401.1 million) and realized prices ($20.5 million).
23
SEVEN GENERATIONS ANNUAL REPORT 2014 Risk Management Contracts
The Company utilizes financial commodity hedges to ensure sufficient revenue exists to cover interest payments on debt and to
partially protect funds from operations against commodity price volatility. Management has set an internal hedge target of 55% of
forecasted production volumes (net of royalties) for the forthcoming four quarters and 30% of net forecasted production volumes
for the next three successive quarters. Price targets are established that will provide a threshold rate of return on capital investment
based on a combination of benchmark oil and gas prices, projected well performance and capital efficiencies. The Company’s risk
management program resulted in the following:
($ thousands)
Realized gain (loss)
Unrealized gain (loss)
Total gain (loss)
Three months ended December 31
Year ended December 31
2014
22,163
123,772
145,935
2013
49
(1,978)
(1,929)
% Change
45,130
6,357
7,665
2014
9,737
141,765
151,502
2013
279
(3,299)
(3,020)
% Change
3,390
4,397
5,117
The fair value of unsettled financial instruments is recorded as an asset or liability with the change in value recorded as an
unrealized gain or loss in the statements of net income and cash flows. At December 31, 2014, the net fair value of the risk
management contracts was an asset of $139.1 million (December 31, 2013 – liability of $2.6 million). Realized gains and losses on
these contracts are recognized on the monthly settlement of the contracts. For the fourth quarter of 2014, the increase in realized
gains of $22.1 million is due to gains on both the oil and natural gas risk management contracts in place. The Company’s risk
management position helped to offset commodity price declines in the latter part of 2014.
The Company had the following risk management contracts in place at December 31, 2014:
Commodity
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Oil
Oil
Oil
Oil
Period
Q1 2015
Q1 2015
Q2 2015
Q3 2015
Q4 2015
Q1 2016
Q1 2015
Q2 2015
Q3 2015
Q4 2015
Volume
Average Minimum Price (1)
15,500 GJ/d
58,000 GJ/d
55,000 GJ/d
25,000 GJ/d
15,000 GJ/d
17,500 GJ/d
11,200 bbls/d
11,000 bbls/d
6,500 bbls/d
1,000 bbls/d
CAD $3.99
CAD $4.00
CAD $3.89
CAD $3.54
CAD $3.77
CAD $3.79
CAD $102.30
CAD $102.15
CAD $101.44
CAD $100.75
(1) For collar contracts, the minimum price has been used in calculating the average for the above table.
For further details of the outstanding contracts, refer to Note 19 of the audited annual financial statements.
24
SEVEN GENERATIONS ANNUAL REPORT 2014 Royalty Expense
($ thousands, except per unit amounts)
Gross royalties
Gas cost allowance (“GCA”)
Net royalties
Per boe
Effective royalty rate – net
Three months ended December 31
Year ended December 31
2014
17,962
(1,817)
16,145
3.97
10%
2013
% Change
4,534
(1,346)
3,188
2.99
6%
296
35
406
33
67
2014
56,256
(4,366)
51,890
4.57
9%
2013
% Change
11,257
(3,404)
7,853
2.76
7%
400
28
561
66
29
The average royalty rate as a percentage of revenues for the fourth quarter of 2014 was 10% compared to 6% in the same period of
2013. Royalty rates were 9% for the full year of 2014 compared to 7% in 2013. The new Montney wells on production qualify for
various royalty incentives for a period of time. The percentage of the Company’s total production eligible for incentives at any one
time will vary depending on the timing that new wells are brought on production and the volumes produced by those wells. The
increase in the overall average royalty rate for the fourth quarter 2014 is due to a lower ratio of production volumes qualifying for
royalty incentives compared to 2013. For the first quarter of 2015, the Company expects the effective royalty rate to continue to be
approximately 10% due to new wells commencing production that will qualify for royalty incentives.
The total dollar amount of royalties have increased 561% in the year and 406% in the quarter, increases due to higher production
and the higher average rates.
For the three months ended December 31, 2014, GCA increased by $0.5 million, or 35%, compared to the same period in 2013.
GCA deductions are estimated during a production year, and are subject to adjustment in the second quarter of the following year
after actual cost filings have been processed by the Alberta Crown. GCA deductions are largely based on amortization of historical
costs, and therefore do not necessarily remain constant on a per unit or percentage of revenue basis.
Interest and Third Party Income
($ thousands, except per unit amounts)
Interest and other income
Processing and third party income
Total
Per boe – interest and other income
Per boe – processing and third party income
Three months ended December 31
Year ended December 31
2014
1,264
704
1,968
0.31
0.17
2013
272
356
628
0.26
0.33
% Change
365
98
213
19
(48)
2014
3,184
1,803
4,987
0.28
0.16
2013
% Change
1,285
1,611
2,896
0.45
0.57
148
12
72
(38)
(72)
The average cash balances held by the Company for the year ended December 31, 2014 were higher than in the same period of
2013 which increased interest and other income by $1.9 million to $3.2 million.
Processing income and third party income increased to $0.7 million in the fourth quarter of 2014 from $0.4 million in the same
period in 2013, which was mainly due to higher volumes from third party wells using Seven Generations’ facilities in the fourth
quarter of 2014. For the year ended December 31, 2014, processing income increased by $0.2 million or, 12%, to $1.8 million from
$1.6 million in the same period of 2013.
25
SEVEN GENERATIONS ANNUAL REPORT 2014 Operating Expenses
($ thousands, except per unit amounts)
Operating expenses
Per boe
Three months ended December 31
Year ended December 31
2014
18,966
4.67
2013
% Change
8,425
7.90
126
(41)
2014
54,261
4.77
2013
% Change
20,615
7.25
163
(34)
Total operating expenses increased in 2014 as a result of higher liquids production and field activity levels, including increased field
staff to accommodate super pad operations. Operating expenses also increased due to rental equipment and temporary facility
costs for flowback of new wells. Temporary facilities are utilized to tie in wells before permanent facilities are constructed.
Operating expenses per boe have improved in the year ended December 31, 2014 with a number of new wells coming on
production. Also, four super pad facilities were constructed and online in the fourth quarter of 2014. The super pad facilities are
sites that contain gas compression, separation, dehydration and liquids pumping capabilities.
On a unit of production basis, operating expenses for the fourth quarter of 2014 decreased by $3.23/boe or, 41%, to $4.67/boe as
compared to $7.90/boe in the fourth quarter of 2013. For the 2014 year end, operating expenses per boe decreased by $2.48/boe
or, 34%, to $4.77/boe as compared to $7.25/boe for the same period in 2013. Since a portion of operating expenses are fixed, the
increase in production volumes has helped to reduce the per unit amounts in 2014.
Transportation Expenses
($ thousands, except per unit amounts)
Transportation expenses
Per boe
Three months ended December 31
Year ended December 31
2014
13,237
3.26
2013
% Change
3,286
3.09
303
6
2014
34,833
3.06
2013
% Change
6,461
2.28
439
34
Transportation expenses include condensate and NGL pipeline tariffs and trucking as well as gas pipeline tariffs charged prior to the
custody transfer point. Transportation expenses increase by $9.9 million to $13.2 million for the fourth quarter of 2014 compared to
$3.3 million for the same period in 2013. The increase of 303% is in line with the increase in production (281%) as the majority of
liquids volumes were transported by truck in 2014. The Company has secured pipeline access and transportation arrangements for
2015 and beyond.
On a unit of production basis, transportation expenses increased by $0.17/boe to $3.26/boe in the fourth quarter of 2014 compared
to $3.09/boe for the same period in 2013 primarily due to volumes being trucked further distances.
For the year ended December 31, 2014, on a unit of production basis, transportation expenses increased $0.78/boe or, 34%, to
$3.06/boe from $2.28/boe for the comparative period in 2013. The increase is primarily due to condensate being trucked to more
remote facilities rather than to the closest pipeline terminal as a result of pipeline capacity constraints in the Grande Prairie area.
General and Administrative Expenses
($ thousands, except per unit amounts)
Gross general and administrative expenses
Capitalized overhead costs
Overhead recoveries
Net general and administrative expenses
Per boe – gross
Per boe – net
Three months ended December 31
Year ended December 31
2014
8,321
(523)
(405)
7,393
2.05
1.82
2013
2,817
(559)
(206)
2,052
2.64
1.93
% Change
195
(6)
97
260
(22)
(6)
2014
23,977
(2,661)
(1,058)
20,258
2.11
1.78
2013
% Change
10,943
(2,159)
(667)
8,117
3.85
2.86
119
23
59
150
(45)
(38)
26
SEVEN GENERATIONS ANNUAL REPORT 2014 Gross general and administrative expenses for the fourth quarter of 2014 increased by $5.5 million to $8.3 million from $2.8 million
for the comparative period in 2013. This increase was mostly due to $2.5 million of expenses related to the IPO and the remainder
due to higher head count.
For the year ended December 31, 2014, gross general administrative expenses are higher by $13.0 million or 119%, compared
to the same period in 2013. This increase is primarily attributable to increased personnel costs and additional rent for leased
space to support the Company’s expanded activities as well as costs related to the IPO. However, as a result of higher production
levels, gross general and administration expenses on a unit of production basis decreased by 22% for the three months ended
December 31, 2014 and 45% for the year, when compared to the same periods of 2013.
For capitalized overhead costs, there was a 6% reduction in the fourth quarter of 2014 compared to the same period in 2013. This
decrease is attributable to a lower capitalization rate in 2014 as more of the Company’s activity is focused on operations.
Overhead recoveries increased by $0.4 million to $1.1 million for the year ended December 31, 2014. Overhead recoveries relate to
spending incurred on properties with minority partners.
Depletion, Depreciation and Amortization
($ thousands, except per unit amounts)
Total depletion, depreciation and amortization
Per boe
Three months ended December 31
Year ended December 31
2014
56,923
14.01
2013
% Change
13,708
12.86
315
9
2014
159,447
14.04
2013
% Change
38,921
13.70
310
2
Depletion, depreciation and amortization expense was $57.0 million and $159.4 million for the three months and year ended
December 31, 2014, compared to $13.7 million and $38.9 million in the comparative periods of 2013, respectively. The increase is
consistent with the increase in production and continued capital investments in the Kakwa play.
Stock Based Compensation
($ thousands)
Gross stock based compensation
Capitalized stock based compensation
Net stock based compensation
Three months ended December 31
Year ended December 31
2014
6,060
(2,163)
3,897
2013
% Change
2,796
(1,244)
1,552
117
74
151
2014
18,012
(6,062)
11,950
2013
% Change
13,991
(4,435)
9,556
29
37
25
Stock based compensation is a non-cash expense. Gross stock based compensation for the fourth quarter of 2014 has increased by
$3.3 million to $6.1 million compared to $2.8 million for the same period of 2013. The increase is mostly due the Company’s higher
stock price in 2014 resulting in higher fair values for awards granted, as well as additional awards granted to new employees. For
the year ended December 31, 2014, there was an increase of $4.0 million, or 29%, to $18.0 million in gross stock based
compensation as compared to $14.0 million in the same period of 2013. In both 2014 and 2013, the stock options and performance
warrants granted in 2008 were amended to extend the expiry date by one year. As a result of these amendments, a one-time
charge of $0.8 million (net – $0.6 million) of expense was recognized in 2014 and $2.1 million (net – $1.7 million) in 2013.
The stock based compensation values are estimated using the Black-Scholes pricing model in which estimates for expected life of
the instruments, current market value of the shares compared to exercise price, stock volatility and interest rates are all important
variables. The value of a stock option or performance warrant is calculated on the date of grant and that value is applied throughout
the life of the instrument. Values are not restated for subsequent changes in estimated volatility rates, interest rates or underlying
market values of the Company’s shares.
27
SEVEN GENERATIONS ANNUAL REPORT 2014 Gain on Disposition of Assets
($ thousands)
Gain on disposition of assets
Three months ended December 31
Year ended December 31
2014
-
2013
% Change
-
-
2014
4,286
2013
% Change
-
100
During the year ended December 31, 2014, the Company closed asset swap arrangements in which non-producing assets were
acquired and non-producing assets were disposed of. For purposes of determining the gain on disposition, the estimated fair
market value was based on the fair value of the assets received. The Company recorded a gain of $4.3 million for the year ended
December 31, 2014.
Finance Expense
($ thousands)
Interest on senior notes
Revolving credit facility fees and other
Amortization of premium and debt issue costs
Accretion
Total finance expense
Capitalized interest
Net finance expense
Three months ended December 31
Year ended December 31
2014
16,543
857
(114)
272
17,558
(500)
17,058
2013
% Change
8,735
235
360
234
9,564
-
9,564
89
265
(132)
16
84
100
78
2014
61,303
2,142
(466)
1,162
64,141
(500)
63,641
2013
% Change
22,113
793
808
733
24,447
-
24,447
177
170
(158)
59
162
100
160
On May 10, 2013, the Company issued US$400.0 million of senior unsecured notes. On February 5, 2014, an additional
US$300.0 million (US$321.0 million with premium) of senior unsecured notes were issued under the same indenture. The notes
bear interest at 8.25% per annum (calculated using a 360-day year). Interest expense for the fourth quarter of 2014 was
$16.5 million (US$14.6 million), which is recorded in Canadian dollars using average monthly exchange rates. Interest expense
has increased compared to prior year given the higher average debt balance outstanding in 2014.
The standby fees and other charges associated with the Company’s revolving credit facility increased to $0.9 million and
$2.1 million in the three months and year ended December 31, 2014 compared to $0.2 million and $0.8 million in the same periods
of 2013, respectively. This is due to higher standby fees as a result of the increases to the borrowing capacity on the credit facility in
2014 from $150.0 million to $480.0 million.
Accretion expense relates to decommissioning liabilities which are recorded over time at their present value. For the year ended
December 31, 2014, accretion was $1.2 million compared to $0.7 million for the comparative period in 2013. The increase reflects
the increase in the ARO liability associated with the passage of time and additional field activity. Accretion and amortization of
premium and debt issue costs are non-cash expenses.
In fourth quarter and year ended December 31, 2014, the Company capitalized $0.5 million in interest and financing costs related to
its Cutbank facility that is expected to be onstream in 2016.
Foreign Exchange Loss (Gain)
($ thousands)
Unrealized
Realized
Net foreign exchange loss
As at December 31:
CDN$ equivalent of 1 US$
28
Three months ended December 31
Year ended December 31
2014
27,562
(2,002)
25,560
2013
% Change
12,878
(2,138)
10,740
114
(6)
138
2014
53,406
(5,733)
47,673
19,975
(9,078)
10,897
2013
% Change
0.862
0.940
(8)
0.862
0.940
167
(37)
337
(8)
SEVEN GENERATIONS ANNUAL REPORT 2014 The Company’s exposure to foreign exchange gains and losses relates to the US dollar senior unsecured notes, as well as US dollar
cash balances. The Company’s senior unsecured notes are comprised of US$400.0 million carried forward from December 31, 2013
at an exchange rate of 0.940 and US$300.0 million issued in February 2014 at an exchange rate of 0.901. The exchange rate fell
to 0.862 at December 31, 2014 resulting in total unrealized foreign exchange losses of $53.4 million for the year ended and
$27.6 million for the fourth quarter. The senior unsecured notes do not mature until 2020. Realized foreign exchange gains relate to
the actual conversion of US dollars to Canadian dollars as well as translation of remaining cash balances still held in US dollars and
the settlement of normal revenues and invoices denominated in US dollars. The Company converted a total of US$278.0 million
to Canadian dollars in 2014, most of that in the first half of the year. Total realized foreign exchange gains were $2.0 million and
$5.7 million for the three months and year ended December 31, 2014, respectively.
Liquidity Event Expense
($ thousands)
Liquidity event expense
Three months ended December 31
Year ended December 31
2014
35,947
2013
% Change
2014
2013
% Change
-
100
35,947
-
100
Pursuant to the Amended and Restated Shareholders Agreement, the Company was obligated to compensate, with cash or shares,
certain directors, officers and employees prior to the completion of a change of control, liquidity event or qualified initial public
offering (the “Liquidity Event”). With the closing of the IPO on November 5, 2014, the Liquidity Event condition was satisfied and
the Company recognized a liability of $36.0 million. The settlement of the liability was approved by the Board of Directors to be
payable in cash in 2015.
Deferred Income Tax Expense
($ thousands)
Deferred income tax expense
Three months ended December 31
Year ended December 31
2014
39,532
2013
293
% Change
13,392
2014
71,508
2013
351
% Change
20,273
For the year ended December 31, 2014, deferred income tax expense increased to $71.5 million from $0.4 million in the
same period of 2013. The Company recognized a deferred income tax expense of $39.5 million for the three months ended
December 31, 2014 compared to $0.3 million in the same period of 2013. The increases in both the fourth quarter of 2014 and the
year ended December 31, 2014 reflect higher net income related to increased production volumes and due to higher combined
realized commodity prices for the 2014 year. The Company’s effective income tax rate is impacted by permanent differences.
Stock based compensation is a non-deductible expense and foreign exchange gains or losses relating to the issue of the senior
notes are one-half taxable or deductible. The majority of the permanent differences for the year ended December 31, 2014
relate to $2.8 million for non-taxable stock based compensation expense and $6.3 million for non-taxable portion of foreign
exchange losses arising on the translation of the US dollar denominated senior notes. During the three months ended
December 31, 2014, the Company recognized a valuation allowance for capital losses of $8.2 million.
The Company has no current income tax expense given its total tax pools of $1.7 billion at December 31, 2014. Of this amount,
$0.4 billion is available in 2014 for deduction in computing taxable income.
29
SEVEN GENERATIONS ANNUAL REPORT 2014 Funds from Operations, Operating Income and Net Income (Loss)
($ thousands, except per share amounts)
2014
2013
% Change
2014
2013
% Change
Three months ended December 31
Year ended December 31
Funds from operations
Per share – basic (1)
Per share – diluted (1)
Operating income
Per share – basic (1)
Per share – diluted (1)
Net income (loss)
Per share – basic (1)
Per share – diluted (1)
101,503
23,114
0.45
0.41
34,815
0.15
0.14
68,628
0.30
0.28
0.14
0.12
7,127
0.04
0.04
(5,625)
(0.03)
(0.03)
339
221
242
388
275
250
1,331
1,100
1,033
327,933
50,273
1.65
1.46
119,521
0.60
0.53
0.30
0.27
5,794
0.03
0.03
144,200
(14,158)
0.73
0.64
(0.08)
(0.08)
552
450
441
1,963
1,900
1,667
1,119
1,013
900
(1)
In 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares, stock options and performance
warrants on a two-for-one basis. The share split has been reflected for the three months and years ended December 31, 2014 and 2013 on a retroactive basis.
Funds from operations increased by $78.4 million in the fourth quarter of 2014 to $101.5 million compared to $23.1 million in the
same period of 2013. The increase was mostly due to higher production volumes offset by lower netbacks due to lower commodity
pricing as well as higher interest expense and general administrative expense. For the year ended December 31, 2014, funds from
operations increased by $277.6 million to $327.9 million compared to $50.3 million in the same period of 2013. This increase is
mainly due to higher production volumes.
For the fourth quarter of 2014, operating income was $34.8 million compared to $7.1 million in the same period of 2013. This was
higher by $27.7 million mainly because of higher production volumes offset by lower commodity prices and increased depletion.
Operating income for the year ended December 31, 2014 was $119.5 million compared to $5.8 million in 2013. The increase of
$113.7 million can be attributed to higher production volumes offset by higher depletion.
Net income increased by $74.2 million to $68.6 million for the fourth quarter of 2014 compared to a net loss of $5.6 million in
the comparative 2013 period. The increase in net income was attributable to the items impacting funds from operations noted
above as well as unrealized gains on risk management contracts of $123.8 million. This was offset by higher depletion charges as
production volumes have increased, the liquidity event expense of $36.0 million, $27.6 million of unrealized foreign exchange losses
and $39.5 million for deferred income tax expense. The net income for the year ended December 31, 2014 was $144.2 million as
compared to a net loss of $14.2 million for the same period in 2013. The annual increase was due to higher funds from operations
and unrealized risk management gains offset by unrealized foreign exchange losses, increased depletion charges, the liquidity event
expense and higher deferred income tax expense.
Capital Investments
($ thousands)
Land acquisitions
Geological and geophysical
Drilling and completions
Facilities and equipment
Capitalized salaries and benefits
Capitalized interest
Office and other
Total capital investment
Property dispositions
Three months ended December 31
Year ended December 31
2013
% Change
2014
2013
% Change
2014
8,200
-
227,562
132,610
776
495
677
2,925
77
129,231
44,717
665
-
623
180
(100)
76
197
17
100
9
48,684
61,298
268
742,019
323,035
3,562
495
2,273
82
321,810
186,694
2,315
-
2,129
370,320
178,238
108
1,120,336
574,328
-
-
-
(9,420)
-
(21)
227
131
73
54
100
7
95
(100)
93
Capital investment, net of dispositions
370,320
178,238
108
1,110,916
574,328
30
SEVEN GENERATIONS ANNUAL REPORT 2014 Over the past year, Seven Generations has significantly accelerated its capital investment program. During 2014, the Company had
nine drilling rigs operating in the first half of the year and 13 rigs operating in the second half. By comparison, in 2013, the Company
had two rigs operating in the first half of the year and seven rigs operating in the second half. In addition, there was an increased
level of completion activity in the latter half of 2014 compared to 2013, which resulted in the higher production levels achieved in
the fourth quarter of 2014. In the fourth quarter of 2014, the Company completed the construction and commissioning of a pipeline
from Karr to Lator to help advance tie in to the Pembina mainline. Seven Generations also continued to acquire additional
undeveloped land acreage in the Kakwa area in both 2014 and 2013.
At December 31, 2014, the Company held 354,556 gross acres (348,762 net) of undeveloped land, an increase of 60% (gross and
net) compared to December 31, 2013 landholdings of 222,076 gross acres (218,310 net).
Liquidity and Capital Resources
The capital structure of the Company is as follows:
As at
Total debt (1)
Total equity (2)
Total capital
December 31, 2014
December 31, 2013
813,880
1,910,926
2,724,806
414,525
827,953
1,242,478
(1) Senior unsecured notes.
(2) Equity is defined as share capital plus contributed surplus plus any retained earnings (deficit) and other comprehensive income (deficit).
The Company’s objective for managing capital continues to be to maintain a strong balance sheet and capital base to provide
financial flexibility to position the Company for future growth and development. The Company strives to grow and maximize
long-term shareholder value by ensuring it has the financing capacity to fund projects that are expected to add value to
shareholders. The Company will strive to balance the proportion of debt and equity in its capital structure to take into account the
level of risk being incurred in its capital investments.
On May 10, 2013, the Company closed a private placement of US$400.0 million of senior unsecured notes. On February 5, 2014,
the Company closed a private placement of an additional US$300.0 million of senior unsecured notes issued under the same
indenture. The notes issued in February 2014 were issued at 107% of par, resulting in gross proceeds to the Company of
US$321.0 million. The notes bear interest at 8.25% per annum (calculated using a 360-day year) payable on May 15 and
November 15 of each year. The notes will mature May 15, 2020.
In December 2013, the Company closed a private equity placement of approximately 20.0 million Class A Common Shares at
$12.50 per share, for total gross proceeds of $251.0 million (net $238.3 million).
In the fourth quarter of 2014, the Company closed its IPO for net proceeds of $880.1 million, including the exercise of the
underwriters’ over-allotment option for net proceeds of $121.5 million.
In the fourth quarter of 2014, the Company increased its revolving credit facility to $480.0 million, which has a three year term
ending in September 2017. The credit facility is subject to a redetermination of the borrowing base semi-annually and is secured by
a floating charge over the Company’s assets. The credit facility bears interest rates based on a pricing grid that increases as a result
of the increased ratio of indebtedness to earnings before interest, taxes, depreciation, depletion and amortization. The credit facility
also includes standby fees on balances not drawn.
The Company had available funding of $1.1 billion at December 31, 2014 and plans to use these funds, along with funds
from operations, for the execution of its 2015 capital program. Seven Generations intends to fund continued accelerated
development of the Kakwa Project beyond 2015 with remaining available funding, cash flow from operations and additional
debt or equity financings.
31
SEVEN GENERATIONS ANNUAL REPORT 2014 Contractual Obligations
Seven Generations enters into contractual obligations in the ordinary course of conducting its business. The following table lists the
Company’s estimated material contractual obligations at December 31, 2014:
($ thousands)
Senior notes (1)
Interest on senior notes (1)
Firm transportation and processing agreements (2)
Operating leases (3)
Estimated contractual obligations
Total
812,070
360,103
1,775,622
14,717
2,962,512
Less Than
1 Year
-
66,996
25,788
2,217
95,001
1-3 Years
4-5 Years
Thereafter
-
133,992
386,591
4,295
-
133,992
487,939
3,104
812,070
25,123
875,304
5,101
524,878
625,035
1,717,598
(1) Debt outstanding represents US$700.0 million (2013 – $US400.0 million) principal converted to Canadian dollars at the closing exchange rate for the period end.
(2) Subject to completion of certain pipeline and facility upgrades by the counterparty transportation company.
(3) The Company is committed under operating leases for office premises.
Seven Generations entered into agreements with Pembina Pipeline Corporation for firm transportation and processing services, of
which the above estimates for timing of payments are subject to completion of certain pipeline and facility upgrades by the
counterparty. The Company has an agreement with Aux Sable Canada LP and, separately, with Alliance Pipeline Ltd. to deliver up to
500 Mmcf/d of peak rich gas volumes by 2018. The natural gas agreements expire in 2022. Seven Generations also has take or pay
agreements in place for up to 40,000 bbls/d of condensate and other NGLs production by 2017. The liquids agreements expire in
2026. The minimum commitments under these agreements are reflected in the table above.
In the third quarter of 2014, the Company entered into an agreement to have a third party provide a 24-hour dedicated crew for
hydraulic fracturing. The agreement has an initial term of one year. The Company may terminate the agreement on less than
60 days notice and payment to the third party of an amount equal to $50,000 for each day less than 60 days that notice of the
termination is given.
In November 2014, the Board of Directors approved a retention bonus plan for management and employees. The retention bonuses
will be payable in four equal installments payable every six months starting on May 5, 2015. Each installment payment will be
contingent upon the individual still being employed by the Company on the date of payment. The maximum retention bonuses will
be $6 million, payable over the two-year period starting November 5, 2014.
The Company is also committed to payments of $36.0 million in 2015 as disclosed under the heading “Liquidity Event Expense” in
this MD&A and in Note 18 of the Company’s financial statements for the year ended December 31, 2014.
Off-Balance Sheet Arrangements
The Company has certain fixed lease arrangements which were entered into in the normal course of operations. All leases are
operating leases, where the lease payments are included in operating expenses or G&A expenses depending on the nature of the
lease. These arrangements are disclosed in the Note 22 to the annual financial statements of the Company. No asset or liability has
been recorded for these leases on the balance sheet at December 31, 2014 or December 31, 2013.
The Company did not have any physical delivery contracts outstanding at December 31, 2014 or December 31, 2013.
32
SEVEN GENERATIONS ANNUAL REPORT 2014 Financial Instruments
Financial Instrument Classification and Measurement
The Company’s financial instruments include cash and cash equivalents, outstanding cheques in excess of bank balances, accounts
receivable, deposits, risk management contracts, accounts payable and accrued liabilities, the credit facility and senior notes.
The Company’s financial instruments that are carried at fair value on the balance sheets include cash and cash equivalents,
outstanding cheques in excess of bank balances, risk management contracts and the credit facility. The credit facility has a floating
rate of interest and therefore the carrying value approximates the fair value. The senior notes are carried at amortized cost, net of
transaction costs and accrete to the principal balance on maturity using the effective interest rate method.
Seven Generations classifies the fair value of these instruments according to the following hierarchy based on the amount of
observable inputs used to value the instrument.
¡¡ Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets
are those in which transactions occur in sufficient frequency and volume to provide pricing information.
¡¡ Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or
indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be substantially observed in the marketplace.
¡¡ Level 3 – Valuations in this level are those inputs for the asset or liability that are not based on observable market data.
Cash and cash equivalents and outstanding cheques in excess of bank balances are classified as Level 1 measurements.
Risk management contracts, the credit facility and fair value disclosure for the senior notes are classified as Level 2
measurements. Assessment of the significance of a particular input to the fair value measurement requires judgment and
may affect the placement within the fair value hierarchy level. Seven Generations does not have any fair value measurements
classified as Level 3. There were no transfers within the hierarchy in the years ended December 31, 2014. The carrying value
of the Company’s accounts receivable, deposits, accounts payable and accrued liabilities approximate their fair values due to the
short-term maturity of these instruments.
The classification, carrying values and fair values of the Company’s financial instruments are as follows:
As at December 31
FINANCIAL ASSETS
Fair Value Through Profit and Loss
Cash and cash equivalents
Risk management contracts
Loans and Receivables
Accounts receivable
Deposits
FINANCIAL LIABILITIES
Fair Value Through Profit and Loss
Outstanding cheques in excess of bank balances
Risk management contracts
Other Financial Liabilities
Accounts payable and accrued liabilities
Senior notes payable
2014
2013
Carrying Value
Fair Value
Carrying Value
Fair Value
848,136
139,119
64,417
5,034
848,136
139,119
64,417
5,034
310,737
310,737
-
-
30,500
1,710
30,500
1,710
-
-
-
-
268,108
813,880
268,108
782,000
3,252
2,646
125,687
414,525
3,252
2,646
125,687
434,000
33
SEVEN GENERATIONS ANNUAL REPORT 2014 Financial Assets and Financial Liabilities Subject to Offsetting
The Company’s risk management contracts are subject to master netting agreements that create a legally enforceable right to
offset by counterparty the related financial assets and financial liabilities on the Company’s balance sheets.
The following is a summary of financial assets and financial liabilities that are subject to offset:
As at December 31, 2014
Risk management contracts
Current asset
Long-term asset
Net position
As at December 31, 2013
Risk management contracts
Current asset
Current liability
Net position
Market Risk
Gross Amounts
of Recognized Financial
Assets (Liabilities)
Gross Amounts
of Recognized Financial
Assets (Liabilities) Offset
In Balance Sheet
Net Amounts of Recognized
Financial Assets (Liabilities)
Recognized In Balance Sheet
138,122
997
139,119
-
-
-
138,122
997
139,119
Gross Amounts
of Recognized Financial
Assets (Liabilities)
Gross Amounts
of Recognized Financial
Assets (Liabilities) Offset
In Balance Sheet
Net Amounts of Recognized
Financial Assets (Liabilities)
Recognized In Balance Sheet
68
(2,714)
(2,646)
(68)
68
-
-
(2,646)
(2,646)
Market risk is the risk that changes in market prices including commodity prices, interest rates and foreign exchange risks will affect
the Company’s income (loss) or the value of financial instruments. The objective of market risk management is to reduce exposures
to acceptable limits while optimizing returns.
(a) Commodity price risk
Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes
in commodity prices. Commodity prices for oil and natural gas are impacted by world economic events that dictate the levels of
supply and demand. The Company uses derivative financial instruments to manage its exposure to fluctuations in commodity
prices. The Company considers these transactions to be effective economic hedges; however, the Company’s contracts do not
qualify as effective hedges for accounting purposes. The Company does not enter into commodity contracts other than to meet the
Company’s expected sales requirements.
During the year ended December 31, 2014, the Company’s risk management contracts resulted in a realized gain of $9.7 million
(2013 – $0.3 million) and an unrealized gain of $141.8 million (2013 – unrealized loss of $3.3 million).
The following table demonstrates the impact of changes in commodity pricing on income before tax, based on risk management
contracts in place at December 31, 2014:
10% increase in AECO/GJ
10% decrease in AECO/GJ
10% increase in US$ WTI/bbl
10% decrease in US$ WTI/bbl
34
Gain (Loss)
(7,234)
7,234
(19,514)
19,514
SEVEN GENERATIONS ANNUAL REPORT 2014 (b) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The senior notes
payable bear interest at a fixed rate. The Company’s credit facility bears a floating rate of interest and, accordingly, the Company is
exposed to interest rate fluctuations to the extent that any advances remaining outstanding under the facility. During May 2013, the
Company borrowed up to $30.7 million on the credit facility for a period of one week. During the year ended December 31, 2014, no
amounts were drawn on the credit facility.
(c) Foreign currency exchange risk
Foreign currency exchange risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of
changes in foreign exchange rates.
Prices for oil are determined in global markets and generally denominated in US dollars. Natural gas prices obtained by the
Company are influenced by both US and Canadian demand and the corresponding North American supply. The exchange rate effect
cannot be quantified but generally an increase in the value of the Canadian dollar as compared to the US dollar will reduce the prices
received by the Company for its oil and natural gas sales.
The Company is exposed to foreign exchange rate fluctuations on the principal and interest related to the senior notes payable, as
well as on cash balances held in US dollars. The foreign currency risk associated with interest payments is partially offset by a
marketing arrangement for the Company’s natural gas liquids, excluding condensate, which is denominated in US dollars.
The following table demonstrates the impact of changes in the Canadian to US dollar exchange rate on income before tax, based on
US denominated balances outstanding at December 31, 2014:
$0.01 increase in CAD/USD exchange rate
$0.01 decrease in CAD/USD exchange rate
Gain (Loss)
8,538
(8,739)
The carrying amount of the Company’s US dollar denominated monetary assets and liabilities as at December 31 was as follows:
Assets
Liabilities
2014
78,042
822,573
2013
67,053
419,083
35
SEVEN GENERATIONS ANNUAL REPORT 2014 Credit Risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual
obligations, and arises primarily from the Company’s receivables from oil and natural marketers and joint venture partners and hedging
assets. The Company’s maximum exposure to credit risk is equal to the carrying amount of these instruments.
Substantially all of the Company’s accounts receivable are with oil and natural gas marketers and joint venture partners under
normal industry sale and payment terms and are subject to normal industry credit risk. Receivables from oil and natural gas
marketers are normally collected on or about the 25th day of the following month. The Company sells the majority of its production
to two oil and natural gas marketers and is therefore subject to concentration risk. Production is sold to marketers with investment
grade credit ratings, if available in the area of production. The Company historically has not experienced any collection issues with
its oil and natural gas marketers. As at December 31, 2014, the Company’s most significant marketer accounted for $21.1 million
(2013 – $11.6 million) of total receivables and 4% of total revenues (2013 – 10%). Receivables from joint venture partners are
typically collected within one to three months of the joint venture bill being issued. The Company attempts to mitigate the risk from
joint venture receivables by obtaining partner pre-approval of significant capital expenditures. However, the receivables are from
participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as
commodity price fluctuations, escalating costs, the risk of unsuccessful drilling and disagreements with partners. As the operator of
properties, the Company has the ability to withhold production from joint interest partners in the event of non-payment. As at
December 31, 2014, receivables outstanding for more than 90 days totalled less than $0.1 million (2013 – $0.1 million). The
Company believes all of the accounts receivable will be collected. The maximum credit risk exposure associated with accounts
receivable is the total carrying value.
All the Company’s cash and cash equivalents are held with Canadian chartered banks and as such, the Company is exposed to
credit risk on any default by the institutions of amounts in excess of the minimum guaranteed amount. The Company considers the
risk of default by a Canadian chartered bank to be remote. As at December 31, 2014, the Company does not invest any cash in
complex investment vehicles with higher risk such as asset backed commercial paper. All of the Company’s risk management
contracts are with Schedule 1 Canadian chartered banks or high credit-quality financial institutions.
Outstanding Share Data
The Company is authorized to issue an unlimited number of Class A Common Voting Shares and an unlimited number of Class B
Common Non-voting Shares without nominal or par value. As a part of the IPO, the Company agreed to apply restrictions to the
transfer of common shares issued prior to the IPO without the consent of the underwriters. At December 31, 2014, 193.0 million
shares were restricted from trading until 180 days from the IPO or May 5, 2015. As at March 10, 2015, Seven Generations had
244,716,068 Class A Common Voting Shares and 523,475 Class B Common Non-voting Shares issued and outstanding.
On September 8, 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common
Voting Shares on a two-for-one basis. The Class B Common Non-voting Shares were not divided. On conversion of Class B
Common Non-voting Shares into Class A Common Voting Shares, holders will receive two Class A Common Voting Shares for each
Class B Common Non-voting Share converted. In December 2014, the Company amended the terms of the stock options and
performances warrants, issued prior to the completion of the IPO, such that upon exercise, the holders of these instruments will
receive two Class A Common Voting Shares (rather than Class B Non-voting Shares) to reflect the two-for-one stock split.
36
SEVEN GENERATIONS ANNUAL REPORT 2014 Internal Control Over Financial Reporting
The Company is required to comply with National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim
Filings”. Given that Seven Generations became a reporting issuer in the fourth quarter of 2014, the Company is not required to
make any representations regarding the maintenance and establishment of disclosure controls and procedures (“DC&P”) and
internal control over financial reporting (“ICFR”) in place as at December 31, 2014. Management will certify the design of the
Company’s DC&P and ICFR as at March 31, 2015 and the effectiveness of DC&P and ICFR as at December 31, 2015. The
evaluation of ICFR will be based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. A control system, no matter how well conceived or operated, can provide
only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that
the control system will prevent all errors or fraud.
Critical Accounting Policies And Estimates
A summary of the Company’s significant accounting policies can be found in Notes 3 and 4 to the audited financial statements for
the year ended December 31, 2014. The preparation of financial statements in accordance with IFRS requires management to make
judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, income and expenses. The financial
and operating results of Seven Generations incorporate certain estimates including:
¡¡ Estimated revenues, royalties and operating expenses on production as at a specific reporting date but for which actual
revenues and costs have not yet been received;
¡¡ Estimated capital expenditures on projects that are in progress;
¡¡ Estimated depletion, depreciation and amortization charges that are based on estimates of oil and natural gas reserves, and
future costs to develop those reserves, that Seven Generations expects to recover in the future;
¡¡ Estimated fair values of financial instruments that are subject to fluctuation depending on the underlying commodity prices,
foreign exchange rates and interest rates, volatility curves and the risk of non-performance;
¡¡ Estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures;
¡¡ Estimated future recoverable value of oil and natural gas properties and goodwill and any associated impairment charges or
recoveries; and
¡¡ Estimated compensation expense under Seven Generations’ share-based compensation plans.
Seven Generations employs individuals who have the skills required to make such estimates and ensures that individuals or
departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed
and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on
future estimates. For further information on the determination of certain estimates inherent in the financial statements, refer to
Note 5 “Significant Accounting Judgments, Estimates and Assumptions” in the audited financial statements for the year ended
December 31, 2014.
37
SEVEN GENERATIONS ANNUAL REPORT 2014 Risk Assessment
The acquisition, exploration, and development of oil and natural gas properties involve many risks, which may influence the ultimate
success of the Company. While the management of Seven Generations realizes these risks cannot be eliminated, they are
committed to monitoring and mitigating these risks. These risk include, but are not limited to:
¡¡ Volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto;
¡¡ Variance of the Company’s actual capital costs, operating costs and economic returns from those anticipated;
¡¡ The ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on
satisfactory terms;
¡¡ Risks related to the exploration, development and production of oil and natural gas reserves and resources;
¡¡ Negative public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing
and fossil fuels;
¡¡ Actions by governmental authorities, including changes in government regulation, royalties and taxation;
¡¡ The availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel;
¡¡ Dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the Company does not control;
¡¡ The ability to satisfy obligations under the Company’s firm commitment transportation arrangements;
¡¡ The possibility that Company’s drilling activities may encounter Sour Gas;
¡¡ Execution of the Company’s business plan;
¡¡ The concentration of the Company’s assets in the Kakwa area;
¡¡ Management of the Company’s growth;
¡¡ First Nations claims;
¡¡ Limited intellectual property protection for operating practices and dependence on employees and contractors;
¡¡ Environmental, health and safety requirements;
¡¡ Extensive competition in the Company’s industry;
¡¡ Third party credit risk;
¡¡ Dependence upon a limited number of customers;
¡¡ Variations in foreign exchange rates and interest rates;
¡¡ Litigation; and
¡¡ General economic, business and industry conditions.
38
SEVEN GENERATIONS ANNUAL REPORT 2014 For additional information regarding the risks that the Company is exposed to, see the disclosure provided under the heading “Risk
Factors” in the AIF, which is available on the SEDAR website at www.sedar.com.
Changes in Accounting Policies
As of January 1, 2014, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional
provisions of each standard. A brief description of each new accounting policy and its impact on the Company’s financial
statements is provided below.
IAS 36 “Impairment of Assets” has been amended to reduce the circumstances in which the recoverable amount of cash
generating units is required to be disclosed and clarify the disclosures required when an impairment loss has been recovered or
reversed in the period. The retrospective adoption of these amendments will only impact the Company’s disclosures in the notes to
the financial statements in periods when an impairment loss or impairment reversal is recognized.
IAS 32 “Financial Instruments: Presentation” is effective January 1, 2014, and has been amended to clarify certain requirements for
offsetting financial assets and liabilities. IAS 32 relates to presentation and disclosure of financial instruments and the retrospective
adoption of this standard did not have a material impact on the Company’s financial statements.
IAS 39 “Financial Instruments: Recognition and Measurement” has been amended to clarify that there would be no requirement to
discontinue hedge accounting if a hedging derivative was novated, provided certain criteria are met. The retrospective adoption of
the amendments does not have any impact on the Company’s financial statements.
IFRIC 21 “Levies” was developed by the IFRS Interpretations Committee and is applicable to all levies imposed by governments
under legislation, other than outflows that are within the scope of other standards (e.g., IAS 12 “Income Taxes”) and fines or other
penalties for breaches of legislation. The interpretation clarifies that an entity recognizes a liability for a levy when the activity that
triggers payment, as identified by the relevant legislation, occurs. It also clarifies that a levy liability is accrued progressively only if
the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. Lastly, the interpretation
clarifies that a liability should not be recognized before the specified minimum threshold to trigger that levy is reached. The
retrospective adoption of this standard does not have any material impact on the Company’s financial statements.
Future Accounting Policy Changes
In February 2014, the IASB tentatively decided to require an entity to apply IFRS 9 “Financial Instruments” for annual periods
beginning on or after January 1, 2018. IFRS 9 is still available for early adoption. The full impact of the standard on the Company’s
financial statements will not be known until changes are finalized.
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers,” which replaces IAS 18 “Revenue,” IAS 11
“Construction Contracts,” and related interpretations. The standard is required to be adopted either retrospectively or using a
modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be
applied by Seven Generations on January 1, 2017 and the Company is currently evaluating the impact of the standard on the
financial statements.
Non-IFRS Financial Measures
This MD&A includes certain terms or performance measures commonly used in the oil and natural gas industry that are not defined
under IFRS, including “funds from operations”, “operating income”, “operating netback” and “available funding”. The data
presented is intended to provide additional information and should not be considered in isolation or as a substitute for measures of
performance prepared in accordance with IFRS. These non-IFRS measures should be read in conjunction with the Company’s
audited financial statements and the accompanying notes.
39
SEVEN GENERATIONS ANNUAL REPORT 2014 Funds from Operations
“Funds from operations” is a financial measure not presented in accordance with IFRS and is equal to cash provided by operating
activities, adjusted for changes in non-cash operating working capital, decommissioning expenditures and liquidity event expense.
The Company uses funds from operations as an integral part of its internal reporting to measure its performance and is considered
an important indicator of the operational strength of the Company’s business. Funds from operations is a measure of the cash flow
generated by the Company’s operating activities and eliminates the effect of changes in non-cash working capital, which is included
in cash flow provided by operating activities. The liquidity event expense in the fourth quarter of 2014 relating to the IPO has been
excluded as it is not expected to recur and did not arise as a result of the Company’s oil and gas operations. Funds from operations
is not intended to be a performance measure that should be regarded as an alternative to, or more meaningful than, either net
income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition,
funds from operations is not intended to represent funds available for dividends, reinvestment or other discretionary uses.
The following table reconciles the cash flow from operating activities to funds from operations.
($ thousands)
Cash provided by operating activities
Decommissioning expenditures
Liquidity event expense
Changes in non-cash operating working capital
Funds from operations
Operating Income
Three months ended December 31
Year ended December 31
2014
80,667
-
35,947
(15,111)
101,503
2013
744
-
-
22,370
23,114
2014
301,909
206
35,947
(10,129)
327,933
2013
41,875
-
-
8,398
50,273
“Operating income” is a non-IFRS measure which the Company uses as a performance measure to provide comparability of
financial performance between periods by excluding non-operating items. Operating income is defined as net income (loss),
excluding realized foreign exchange gains and losses, unrealized gains and losses on risk management contracts, liquidity event
expense and the respective income tax impact of these adjustments.
The following table reconciles the net income (loss) to operating income.
($ thousands)
Net income (loss)
Unrealized foreign exchange loss (1)
Unrealized (gain) loss on risk management contract (2)
Liquidity event expense (3)
Gain on disposition of assets (4)
Deferred tax expense relating to these adjustments
Operating income
Three months ended December 31
Year ended December 31
2014
68,628
27,562
(123,772)
35,947
-
26,450
34,815
2013
(5,625)
12,878
1,978
-
-
(2,104)
7,127
2014
144,200
53,406
(141,765)
35,947
(4,286)
32,019
119,521
2013
(14,158)
19,975
3,299
-
-
(3,322)
5,794
(1)
Unrealized foreign exchange gains and losses result from the translation of the US$ denominated senior notes and cash and cash equivalents using period end
exchange rates.
(2) Unrealized gains and losses on risk management contracts result from the fair market valuation of the hedge contracts as at December 31, 2014.
(3) Non-recurring costs related to IPO.
(4) Non-recurring gain resulting from disposition of assets.
Operating Netback
“Operating netback” is calculated on a per boe basis and is determined by deducting royalties, operating and transportation expenses
from oil and natural gas revenue and, except where otherwise indicated, after adjusting for realized hedging gains or losses. Operating
netback is utilized by the Company and others to better analyze the operating performance of its oil and natural gas assets.
40
SEVEN GENERATIONS ANNUAL REPORT 2014 Available Funding
“Available funding” is comprised of adjusted working capital and the undrawn credit facility capacity. Adjusted working capital is
comprised of current assets less current liabilities and excludes (current) risk management contracts and deferred credits. The
available funding measure allows management and other users to evaluate the Company’s short term liquidity. A summary of the
reconciliation of available funding is set forth below:
($ thousands)
Current assets
Current liabilities
Working capital
Adjusted for:
Current portion risk management contracts
Current portion of deferred credits
Adjusted working capital
Undrawn credit facility capacity
Available funding
Net Debt
December 31, 2014
December 31, 2013
1,060,030
(268,231)
791,799
(138,122)
123
653,800
480,000
1,133,800
343,816
(131,703)
212,113
2,646
118
214,877
150,000
364,877
“Net debt” is a financial measure not presented in accordance with IFRS and is equal to long-term debt less adjusted working
capital surplus (deficit). Long-term debt for the senior notes is calculated as the principal amount outstanding converted to Canadian
dollars at the closing exchange rate for the period, and excludes unamortized premiums and debt issue costs. Adjusted working
capital surplus (deficit) is calculated as current assets less current liabilities as they appear on the balance sheets, and excludes
current unrealized risk management contracts and deferred credits. The Company uses net debt to assess liquidity and general
financial strength. Net debt should not be considered an alternative to, or more meaningful than, current assets or current liabilities
as determined in accordance with IFRS. The following table presents a calculation of the non-IFRS financial measure of net debt.
($ thousands)
Senior notes at amortized cost
Less unamortized premium and debt issue costs
Senior notes principal
Adjusted for:
Current assets
Current liabilities
Current portion risk management contracts
Current portion of deferred credits
Net debt
December 31, 2014
December 31, 2013
813,880
(1,810)
812,070
(1,060,030)
268,231
138,122
(123)
158,270
414,525
10,915
425,440
(343,816)
131,703
(2,646)
(118)
210,563
41
SEVEN GENERATIONS ANNUAL REPORT 2014 SELECTED QUARTERLY INFORMATION
($ thousands, except per share amounts)
Q4 2014
Q3 2014
Q2 2014
Q1 2014
YE 2014
FINANCIAL
Oil and condensate revenues (3)
NGLs revenues (3)
Natural gas revenues (3)
Total revenues (3)
Realized hedging gain (loss)
Processing and third party income
Interest and other income
Royalties
Operating expenses
Transportation expenses (3)
General and administrative expense
Interest expense
Foreign exchange
Other
Funds from operations (1)
Per share – basic (2)
Per share – diluted (2)
Operating income (1)
Per share – basic (2)
Per share – diluted (2)
Net income
Per share – basic (2)
Per share – diluted (2)
Capital investments
Land
Drilling and completions
Facilities and equipment
Other
Total capital investments
(before dispositions)
Total assets
Total non-current financial liabilities
Available funding (1)
Net debt (1)
Debt outstanding
OPERATING
Average daily production
Oil and condensate (bbls/d)
NGLs (bbls/d)
Natural gas (Mmcf/d)
Total (boe/d)
Realized prices (3)
Oil and condensate ($/bbl)
NGLs ($/bbl)
Natural gas ($/mcf)
94,873
21,329
39,181
155,383
22,163
704
1,264
(16,145)
(18,966)
(13,237)
(7,393)
(16,905)
(5,334)
(31)
101,503
0.45
0.41
34,815
0.15
0.14
68,628
0.30
0.28
8,200
227,562
132,610
1,948
370,320
3,114,797
813,880
1,133,800
158,270
813,880
14,747
10,783
112
44,178
69.93
21.50
3.81
104,628
19,416
35,920
159,964
(148)
571
512
(20,925)
(14,245)
(7,277)
(4,457)
(16,037)
8,367
(31)
106,294
0.55
0.48
41,972
0.22
0.19
30,482
0.16
0.14
1,408
234,879
90,447
1,689
328,423
2,019,134
785,830
547,700
716,300
785,830
12,580
8,289
90
35,820
90.41
25.46
4.35
82,049
10,418
28,282
120,749
(6,873)
243
782
(9,434)
(9,659)
(7,693)
(5,233)
(16,262)
(618)
(30)
65,972
0.35
0.31
18,253
0.10
0.09
43,926
0.23
0.20
30,057
155,284
34,172
1,531
221,044
1,844,172
748,596
427,222
469,678
748,596
9,264
4,741
60
23,999
97.32
24.15
5.18
62,962
10,307
25,468
98,737
(5,405)
285
626
(5,386)
(11,391)
(6,626)
(3,175)
(13,746)
223
22
54,164
0.29
0.25
24,481
0.13
0.11
1,164
0.01
0.01
9,019
124,294
65,806
1,430
200,549
1,818,627
776,277
574,581
349,269
775,809
7,554
4,054
52
20,231
92.61
28.25
5.47
344,512
61,470
128,851
534,833
9,737
1,803
3,184
(51,890)
(54,261)
(34,833)
(20,258)
(62,950)
2,638
(70)
327,933
1.65
1.46
119,521
0.60
0.53
144,200
0.73
0.64
48,684
742,019
323,035
6,598
1,120,336
3,114,797
813,880
1,133,800
158,270
813,880
11,061
6,989
79
31,136
85.34
24.10
4.50
See “Non-IFRS Financial Measures”.
(1)
(2) On September 8, 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares on a two-for-one
basis. As of December 1, 2014, all options and performance warrants issued prior to the completion of the IPO (as defined herein) were exercisable into twice as
many Common Shares as the number of Class B Common Non-voting Shares they were exercisable for prior to December 1, 2014. The share split has been
reflected in the condensed interim statements for the three months and year ended December 31, 2014 and on a retroactive basis.
(3) Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation.
42
SEVEN GENERATIONS ANNUAL REPORT 2014
SELECTED QUARTERLY INFORMATION – continued
($ thousands, except per share amounts)
Q4 2013
Q3 2013
Q2 2013
Q1 2013
YE 2013
FINANCIAL
Oil and condensate revenues (3)
NGLs revenues (3)
Natural gas revenues (3)
Total revenues (3)
Realized hedging gain
Processing and third party income
Interest and other income
Royalties
Operating expenses
Transportation expenses (3)
General and administrative expense
Interest expense
Foreign exchange
Other
Funds from operations (1)
Per share – basic (2)
Per share – diluted (2)
Operating income (loss) (1)
Per share – basic (2)
Per share – diluted (2)
Net income (loss)
Per share – basic (2)
Per share – diluted (2)
Capital investments
Land
Drilling and completions
Facilities and equipment
Other
Total capital investments
(before dispositions)
Total assets
Total non-current financial liabilities
Available funding (1)
Net debt (1)
Debt outstanding
OPERATING
Average daily production
Oil and condensate (bbls/d)
NGLs (bbls/d)
Natural gas (Mmcf/d)
Total (boe/d)
Realized prices (3)
Oil and condensate ($/bbl)
NGLs ($/bbl)
Natural gas ($/mcf)
33,226
5,174
10,084
48,484
49
356
272
(3,188)
(8,425)
(3,286)
(2,052)
(8,970)
(133)
7
23,114
0.14
0.12
7,127
0.04
0.04
(5,625)
(0.03)
(0.03)
2,925
129,231
44,717
1,365
178,238
1,408,213
414,525
364,877
210,563
414,525
4,480
2,291
29
11,585
80.63
24.54
3.79
14,346
2,830
4,992
22,168
17
501
506
(2,227)
(4,502)
(962)
(2,006)
(8,691)
(24)
-
4,780
0.03
0.03
(8,053)
(0.05)
(0.05)
(955)
(0.01)
(0.01)
8,991
102,314
29,707
1,173
142,185
1,134,257
404,208
189,586
282,534
404,208
1,614
1,639
23
7,084
96.63
18.77
2.36
13,568
1,421
6,592
21,581
53
347
274
(318)
(4,168)
(1,326)
(2,175)
(5,051)
6
-
9,223
0.06
0.05
5,246
0.03
0.03
(8,454)
(0.05)
(0.05)
35,875
44,697
39,806
1,058
121,436
1,103,583
412,293
328,137
152,583
412,293
1,681
1,313
19
6,182
88.67
11.89
3.79
13,408
2,552
4,991
20,951
160
407
233
(2,120)
(3,520)
(887)
(1,884)
(194)
10
-
13,156
0.08
0.08
1,474
0.01
0.01
876
0.01
0.01
13,507
45,568
72,464
930
132,469
698,450
59
16,441
23,559
-
1,760
1,749
16
6,240
84.62
16.22
3.38
74,548
11,977
26,659
113,184
279
1,611
1,285
(7,853)
(20,615)
(6,461)
(8,117)
(22,906)
(141)
7
50,273
0.30
0.27
5,794
0.03
0.03
(14,158)
(0.08)
(0.08)
61,298
321,810
186,694
4,526
574,328
1,408,213
414,525
364,877
210,563
414,525
2,390
1,749
22
7,786
85.49
18.76
3.34
See “Non-IFRS Financial Measures”.
(1)
(2) On September 8, 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares on a two-for-one
basis. As of December 1, 2014, all options and performance warrants issued prior to the completion of the IPO (as defined herein) were exercisable into twice as
many Common Shares as the number of Class B Common Non-voting Shares they were exercisable for prior to December 1, 2014. The share split has been
reflected in the condensed interim statements for the three months and year ended December 31, 2014 and on a retroactive basis.
(3) Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation.
43
SEVEN GENERATIONS ANNUAL REPORT 2014
SELECTED QUARTERLY INFORMATION – continued
($ thousands, except per share amounts)
Q4 2012
Q3 2012
Q2 2012
Q1 2012
YE 2012
FINANCIAL
Oil and condensate revenues (3)
NGLs revenues (3)
Natural gas revenues (3)
Total revenues (3)
Realized hedging gain
Processing and third party income
Interest and other income
Royalties
Operating expenses
Transportation expenses (3)
General and administrative expense
Interest expense
Foreign exchange
Other
Funds from operations (1)
Per share – basic (2)
Per share – diluted (2)
Operating income (loss) (1)
Per share – basic (2)
Per share – diluted (2)
Net loss
Per share – basic (2)
Per share – diluted (2)
Capital investments
Land
Drilling and completions
Facilities and equipment
Other
Total capital investments
(before dispositions)
Total assets
Total non-current financial liabilities
Available funding (1)
Net debt (1)
Debt outstanding
OPERATING
Average daily production
Oil and condensate (bbls/d)
NGLs (bbls/d)
Natural gas (Mmcf/d)
Total (boe/d)
Realized prices (3)
Oil and condensate ($/bbl)
NGLs ($/bbl)
Natural gas ($/mcf)
8,992
1,627
5,627
16,246
224
405
433
(2,922)
(3,233)
(73)
(1,808)
(50)
-
(618)
8,604
0.05
0.05
162
-
-
(379)
-
-
16,775
43,007
42,346
669
102,797
679,271
5
135,089
(95,089)
-
1,143
296
17
4,316
85.52
59.81
3.54
9,379
1,539
4,462
15,380
520
485
431
(959)
(2,227)
(61)
(1,491)
(51)
-
-
12,027
0.07
0.07
258
-
-
(247)
-
-
21,461
25,545
14,331
477
7,507
1,420
3,561
12,488
655
575
223
(859)
(2,204)
(15)
(1,324)
(117)
-
-
9,422
0.07
0.07
(152)
-
-
(875)
(0.01)
(0.01)
10,916
13,169
3,496
522
61,814
629,064
-
229,336
(189,336)
-
28,103
566,205
-
235,286
(195,286)
-
1,205
323
20
4,763
84.58
51.85
2.50
1,042
313
19
4,512
79.15
49.92
2.07
5,444
1,376
2,723
9,543
404
568
93
(793)
(2,101)
(52)
(1,304)
(49)
-
-
6,309
0.05
0.05
(1,688)
(0.01)
(0.01)
(1,073)
(0.01)
(0.01)
10,584
21,196
10,033
442
42,255
370,750
-
56,605
(16,605)
-
692
220
13
3,123
86.43
68.76
2.26
31,322
5,962
16,373
53,657
1,803
2,033
1,180
(5,533)
(9,765)
(201)
(5,927)
(267)
-
(618)
36,362
0.25
0.24
(1,420)
(0.01)
(0.01)
(2,574)
(0.02)
(0.02)
59,736
102,917
70,206
2,110
234,969
679,271
5
135,089
(95,089)
-
1,021
288
17
4,180
83.78
59.81
3.54
See “Non-IFRS Financial Measures”.
(1)
(2) On September 8, 2014, the Company amended its articles of incorporation to divide the issued and outstanding Class A Common Voting Shares on a two-for-one
basis. As of December 1, 2014, all options and performance warrants issued prior to the completion of the IPO (as defined herein) were exercisable into twice as
many Common Shares as the number of Class B Common Non-voting Shares they were exercisable for prior to December 1, 2014. The share split has been
reflected in the condensed interim statements for the three months and year ended December 31, 2014 and on a retroactive basis.
(3) Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation.
44
SEVEN GENERATIONS ANNUAL REPORT 2014
Forward-Looking Information Advisory
This document contains certain forward-looking information and statements that involves various risks, uncertainties and other
factors. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”,
and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting
the foregoing, this document contains forward-looking information and statements pertaining to the following: expectations
regarding the balancing of debt and equity in the Company’s capital structure; the mitigation of risk associated with Company’s
capital investments; the Company’s estimates of its future obligations under the heading “Contractual Obligations”; the number
of wells that can or will be drilled; the number of wells expected to come on production in 2015; the number of drilling rigs
expected to be utilized; the Company’s expected sources of financing; anticipated supply costs; future cost savings to be realized;
plans to defer spending; projected capital expenditures; anticipated break-even market prices and project economics; the
Company’s prospects for revenue recovery; expectations for the transportation of the Company’s products; anticipated production
and recovery; revenue growth projections; opportunities for increased market share; commodity price projections; estimated
internal rates of return; anticipated type-curves and well production and decline profiles; the use of hedging in the future; the
expected timing and completion of: the Lator 2 plant expansion, the Pembina Lator to Fox Creek pipeline, the 25,000 bbl/d
stabilizer at the Karr 7-11 battery and the expected benefits to the derived therefrom; the expected timing of the completion and
occupation of a temporary camp being set up by the Company; anticipated go-forward strategy; expectations regarding future
market access; and other market predictions. In addition, references to reserves are deemed to be forward-looking information, as
they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the
quantities predicted or estimated.
With respect to forward-looking information contained in this document, assumptions have been made regarding, among other
things: future oil, natural gas liquids and natural gas prices; the Company’s ability to obtain qualified staff and equipment in a timely
and cost efficient manner; the Company’s ability to market production of oil, NGLs and natural gas successfully to customers; the
Company’s future production levels; the applicability of technologies for the Company’s reserves; future capital investments by the
Company; future cash flows from production; future sources of funding for the Company’s capital program; the Company’s future
debt levels; geological and engineering estimates in respect of the Company’s reserves, the geography of the areas in which the
Company is conducting exploration and development activities, and the access, economic and physical limitations to which the
Company may be subject from time to time; the impact of competition on the Company; and the Company’s ability to obtain
financing on acceptable terms.
Actual results could differ materially from those anticipated in this forward-looking information as a result of the risks and risk
factors that are set forth in the AIF, which is available on SEDAR at www.sedar.com, including, but not limited to: volatility in market
prices and demand for oil, natural gas liquids and natural gas and hedging activities related thereto; general economic, business and
industry conditions; variance of the Company’s actual capital costs, operating costs and economic returns from those anticipated;
risks related to the exploration, development, production and transportation of oil and natural gas reserves and resources; negative
public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels;
actions by governmental authorities, including changes in government regulation, royalties and taxation; the management of the
Company’s growth; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; the absence
or loss of key employees; uncertainty associated with estimates of oil, natural gas liquids and natural gas reserves and the variance
of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities,
certain of which the Company does not control; shortage or lack of available of pipeline capacity or other transportation facilities;
the ability to satisfy obligations under the Company’s firm commitment transportation arrangements; uncertainties related to the
Company’s identified drilling locations; the concentration of the Company’s assets in the Kakwa area; unforeseen title defects; First
Nations claims; failure to accurately estimate abandonment and reclamation costs; changes in the interpretation and enforcement of
applicable laws and regulations; terrorist attacks or armed conflicts; reassessment by taxing authorities of the Company’s prior
transactions and filings; variations in foreign exchange rates and interest rates; third-party credit risk including risk associated with
counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance
policies; potential for litigation; variation in future calculations of non-IFRS measures; sufficiency of internal controls; impact of
expansion into new activities on risk exposure; risks related to the senior unsecured notes and other indebtedness, including:
potential inability to comply the covenants in the credit agreement related to the Company’s credit facilities and/or the covenants in
the indenture in respect of the senior secured notes; seasonality of the Company’s activities and the Canadian oil and gas industry;
and extensive competition in the Company’s industry.
Any financial outlook and future-oriented financial information contained in this document regarding prospective financial
performance, financial position or cash flows is based on assumptions about future events, including economic conditions and
proposed courses of action, based on management’s assessment of the relevant information that is currently available. Projected
operational information contains forward-looking information and is based on a number of material assumptions and factors, as
45
SEVEN GENERATIONS ANNUAL REPORT 2014 are set out above. These projections may also be considered to contain future oriented financial information or a financial outlook.
The actual results of the Company’s operations for any period will likely vary from the amounts set forth in these projections, and
such variations may be material. Actual results will vary from projected results. Readers are cautioned that any such financial
outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is
disclosed herein.
The forward-looking information and statements contained in this document speak only as of the date hereof, and the Company
does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be
required pursuant to applicable laws.
Independent Reserves Evaluation
Estimates of the Company’s reserves and the net present value of future net revenue attributable to the Company’s reserves: (i) as
at December 31, 2014, are based upon the report that was prepared by McDaniel, evaluating the Company’s oil, natural gas and
NGL reserves, dated February 19, 2015; (ii) as at July 1, 2014, are based upon the report that was prepared by McDaniel, evaluating
the Company’s oil, natural gas and NGL reserves, dated July 23, 2014; and, as at December 31, 2013, are based upon the report
that was prepared by McDaniel, evaluating the Company’s oil, natural gas and NGL reserves, dated February 24, 2014. The
estimates of reserves provided in this document are estimates only and there is no guarantee that the estimated reserves will be
recovered. Actual reserves may be greater than or less than the estimates provided in this in this document, and the difference may
be material. Estimates of net present value of future net revenue attributable to the Company’s reserves do not represent fair
market value of the Company’s reserves. There is no assurance that the forecast price and cost assumptions applied by McDaniel in
evaluating Seven Generations’ reserves will be attained and variances could be material. For important additional information
regarding the independent reserves evaluations that were conducted by McDaniel, please refer to the AIF and to the Company’s
Supplemented PREP Prospectus dated October 29, 2014, which are available on the SEDAR website at www.sedar.com.
Finding and development costs have been calculated for proven reserves by taking the sum of: (i) exploration costs; (ii) development
costs; and (iii) the change in estimated future development costs relating to proved reserves during the year; divided by the
additions to proved reserves during the year. Finding and development costs for proved plus probable reserves have been
calculated by taking the sum of: (i) exploration costs; (ii) development costs; and (iii) the change in estimated future development
costs during the year; divided by the additions to proved plus probable reserves during the year. Comparative information for 2013
and the average of the three most recent years has not been provided for finding and development costs as no independent reserve
reports were prepared for the Company as at December 31, 2012 or 2011. 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 reserves additions for that year.
46
SEVEN GENERATIONS ANNUAL REPORT 2014 Oil and Gas Definitions
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.
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.
gross means:
¡¡ In relation to the Company’s interest in production or reserves, its “company gross reserves”, which are the Company’s
working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests
of the Company;
¡¡ In relation to wells, the total number of wells in which a company has an interest; and
¡¡ In relation to properties, the total area of properties in which a company has an interest.
net means:
¡¡ In relation to the Company’s interest in production or reserves, the Company’s working interest (operating or non-operating)
share after deduction of royalty obligations, plus the Company’s royalty interest in production or reserves;
¡¡ In relation to the Company’s interest in wells, the number of wells obtained by aggregating the Company’s working interest in
each of its gross wells; and
¡¡ In relation to the Company’s interest in a property, the total area in which the Company has an interest multiplied by the working
interest owned by the Company.
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.
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.
reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of
established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are
classified according to the degree of certainty associated with the estimates.
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) to which they are assigned.
47
SEVEN GENERATIONS ANNUAL REPORT 2014 Abbreviations
AECO
physical storage and trading hub for
natural gas on the TransCanada
Alberta transmission system which
is the delivery point for various
benchmark Alberta index prices
m
Mcf
metres
thousand cubic feet
Mmcf
million cubic feet
bbl
bbls
barrel
barrels
bbls/d
barrels per day
boe (1)
barrels of oil equivalent
Mmcf/d
million cubic feet per day
MMboe
millions of barrels of oil equivalent
MMBtu
million British thermal units
NGLs
natural gas liquids
boe/d
barrels of oil equivalent per day
NYMEX
New York Mercantile Exchange
Btu
British thermal units
US$ or $US
United Stated dollars
Btu/scf
British thermal units per standard cubic foot
WTI
West Texas Intermediate
$MM
millions of dollars
C3
C4
C5+
propane
butane
pentanes plus
CAD$
Canadian dollars
GJ
GJ/d
IRR
gigajoule
gigajoules per day
internal rate of return
(1)
Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting natural gas to oil equivalent. Condensate and other NGLs are converted to oil
equivalent at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based roughly on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the Company’s sales point. Given the value
ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf:1 bbl, utilizing a conversion ratio
at 6 Mcf:1 bbl may be misleading as an indication of value.
48
SEVEN GENERATIONS ANNUAL REPORT 2014
INDEPENDENT AUDITOR’S REPORT
TO THE SHAREHOLDERS OF SEVEN GENERATIONS ENERGY LTD.:
We have audited the accompanying financial statements of Seven Generations Energy Ltd., which comprise the balance sheets as
at December 31, 2014 and 2013 and the statements of income (loss) and comprehensive income (loss), statements of changes in
equity and statements of cash flows for the years then ended, and a summary of significant accounting policies and other
explanatory information.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International
Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of
financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from
material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the
financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant
to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit
also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by
management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of Seven Generations Energy Ltd.
as at December 31, 2014 and 2013, and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards
Chartered Accountants
March 10, 2015
Calgary, Canada
49
SEVEN GENERATIONS ANNUAL REPORT 2014
BALANCE SHEETS
(thousands of Canadian dollars)
As at December 31
Assets
Current assets
Cash and cash equivalents
Accounts receivable
Risk management contracts
Deposits and prepaid expenses
Risk management contracts
Oil and natural gas assets
Goodwill
Liabilities
Current liabilities
Outstanding cheques in excess of bank balances
Accounts payable and accrued liabilities
Risk management contracts
Current portion of deferred credits
Senior notes
Deferred credits
Decommissioning liabilities
Deferred income taxes
Equity
Share capital
Contributed surplus
Retained earnings (deficit)
See accompanying notes to the financial statements.
Approved by the Board of Directors
Dale Hohm
Kent Jespersen
50
Notes
2014
2013
6
19
19
7
10
19
23
9
23
11
12
13
848,136
64,417
138,122
9,355
1,060,030
997
2,049,760
4,010
3,114,797
-
268,108
-
123
268,231
813,880
973
52,163
68,624
1,203,871
1,719,779
54,684
136,463
1,910,926
3,114,797
310,737
30,500
-
2,579
343,816
-
1,060,387
4,010
1,408,213
3,252
125,687
2,646
118
131,703
414,525
1,048
23,656
9,328
580,260
790,064
45,626
(7,737)
827,953
1,408,213
SEVEN GENERATIONS ANNUAL REPORT 2014
STATEMENTS OF INCOME (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
(thousands of Canadian dollars, except per share amounts)
Year ended December 31
Revenues
Oil and natural gas sales
Royalties
Risk management contracts
Realized gain
Unrealized gain (loss)
Interest and third party income
Expenses
Operating
Transportation
General and administrative
Depletion, depreciation and amortization
Stock based compensation
Finance expense
Foreign exchange loss
Liquidity event expense
Gain on disposition of assets
Income (loss) before taxes
Taxes
Deferred income tax expense
Net income (loss) and comprehensive income (loss)
Net income (loss) per share
Basic
Diluted
See accompanying notes to the financial statements.
Notes
2014
2013
19
19
16
14
17
21
18
7
12
15
534,833
(51,890)
482,943
9,737
141,765
4,987
639,432
54,261
34,833
20,258
159,447
11,950
63,641
47,673
35,947
(4,286)
423,724
215,708
71,508
144,200
0.73
0.64
113,184
(7,853)
105,331
279
(3,299)
2,896
105,207
20,615
6,461
8,117
38,921
9,556
24,447
10,897
-
-
119,014
(13,807)
351
(14,158)
(0.08)
(0.08)
51
SEVEN GENERATIONS ANNUAL REPORT 2014
STATEMENTS OF CHANGES IN EQUITY
(thousands of Canadian dollars)
Balance at December 31, 2012
Net loss for the year
Issue of common shares
Share issue costs (net of deferred tax)
Stock based compensation
Value attributed to modification of stock
options and performance warrants
Exercise of stock options
Exercise of performance warrants
Balance at December 31, 2013
Net income for the year
Issue of common shares
Share issue costs (net of deferred tax)
Stock based compensation
Exercise of stock options
Exercise of performance warrants
Balance at December 31, 2014
Notes
Share Capital
13
13
14
13,14
13,14
13,14
13
13
14
13,14
13,14
545,057
-
250,992
(9,535)
-
-
1,383
2,167
790,064
-
931,500
(36,637)
-
15,708
19,144
1,719,779
Contributed
Surplus
32,581
-
-
-
11,915
2,076
(518)
(428)
45,626
-
-
-
18,012
(5,668)
(3,286)
54,684
Retained
Earnings (Deficit)
6,421
(14,158)
-
-
-
-
-
-
(7,737)
144,200
-
-
-
-
-
Total
584,059
(14,158)
250,992
(9,535)
11,915
2,076
865
1,739
827,953
144,200
931,500
(36,637)
18,012
10,040
15,858
136,463
1,910,926
See accompanying notes to the financial statements.
52
SEVEN GENERATIONS ANNUAL REPORT 2014
STATEMENTS OF CASH FLOWS
(thousands of Canadian dollars)
Year ended December 31
Notes
2014
2013
Operating activities
Net income (loss) for the year
Deferred income tax expense
Depletion, depreciation and amortization
Unrealized loss (gain) on risk management contracts
Stock based compensation
Amortization of premium and debt issue costs
Accretion
Gain on disposition of assets
Unrealized foreign exchange loss
Decommissioning expenditures
Other
Changes in non-cash working capital
Cash provided by operating activities
Financing activities
Issue of common shares
Share issue costs
Issue of senior notes
Debt issue costs
Borrowings under revolving credit facility
Repayments under revolving credit facility
Cash provided by financing activities
Investing activities
Oil and natural gas asset additions
Proceeds on disposition of property
Changes in non-cash working capital
Cash used in investing activities
19
14
17
17
21
13
13
9
9
8
8
7
7
21
144,200
71,508
159,447
(141,765)
11,950
(471)
1,162
(4,286)
50,311
(206)
(70)
10,129
301,909
957,398
(48,849)
356,342
(9,840)
-
-
1,255,051
(1,120,336)
9,420
91,512
(1,019,404)
(14,158)
351
38,921
3,299
9,556
808
733
-
10,756
-
7
(8,398)
41,875
253,596
(12,714)
404,960
(11,201)
30,700
(30,700)
634,641
(574,328)
-
49,873
(524,455)
Foreign exchange gain on cash held in foreign currencies
3,095
9,219
Increase in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
Cash and cash equivalents are comprised of:
Cash and cash equivalents
Outstanding cheques in excess of bank balances
Supplementary disclosure of cash flow information (Note 21).
See accompanying notes to the financial statements.
540,651
307,485
848,136
848,136
-
848,136
161,280
146,205
307,485
310,737
(3,252)
307,485
53
SEVEN GENERATIONS ANNUAL REPORT 2014
NOTES TO THE FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013
(all tabular amounts in thousands of Canadian dollars, except share, per share and price information)
Financial Statement Note
Nature of business
Basis of preparation
Significant accounting policies
New accounting policies
Significant accounting judgments, estimates and assumptions
Cash and cash equivalents
Oil and natural gas assets
Bank debt
Senior notes
Accounts payable and accrued liabilities
Decommissioning liabilities
Deferred income taxes
Share capital
Stock based compensation
Per share amounts
General and administrative expenses
Finance expense
Liquidity event expense
Financial instruments and risk management contracts
Capital management
Supplemental cash flow information
Commitments
Deferred credits
Related party transactions
1
2
3
4
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7
8
9
10
11
12
13
14
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16
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18
19
20
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23
24
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77
78
78
SEVEN GENERATIONS ANNUAL REPORT 2014 1. NATURE OF BUSINESS
Seven Generations Energy Ltd. (“Seven Generations” or the “Company”) is incorporated under the Canada Business Corporations Act
and commenced operations in 2008. Seven Generations is a Canadian company focused on the exploration, development and
production of oil and natural gas properties in western Canada. Seven Generations’ principal place of business is located at 300, 140 –
8th Avenue SW, Calgary, Alberta T2P 1B3. The Company is publicly traded on the Toronto Stock Exchange as of November 5, 2014,
under the symbol “VII”.
2. BASIS OF PREPARATION
These financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the
International Accounting Standards Board (“IASB”).
These financial statements have been prepared on the historical cost basis, except for certain financial instruments which are
measured at fair value as explained in Note 20. The financial statements are presented in Canadian dollars, which is Seven
Generations’ functional currency.
The financial statements were approved and authorized for issue by the Board of Directors on March 10, 2015.
Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation. Certain pipeline tariffs
after the custody transfer point have been reclassified from transportation expense to oil and natural gas revenues in the statements of
income (loss) and comprehensive (loss). Exploration and evaluation assets have been separately disclosed from developed and producing
properties in Note 7, Oil and natural gas assets.
3. SIGNIFICANT ACCOUNTING POLICIES
Property, Plant and Equipment
(a) Oil and Natural Gas Assets
Oil and natural gas properties are carried at cost, less accumulated depletion and depreciation and accumulated impairment losses,
if any.
Oil and natural gas properties represent all costs directly attributable to development of oil and natural gas reserves after technical
feasibility and commercial viability have been established. These include lease acquisitions, geological and geophysical costs,
drilling and completion costs, production equipment, pipelines and gathering equipment, processing facilities and associated
turnarounds, other directly attributable costs, borrowing costs of qualifying assets and estimates of decommissioning liabilities.
Depletion of intangible oil and natural gas assets is calculated using the unit-of-production method based on estimated recoverable
reserves before royalties. Natural gas reserves and production are converted to equivalent barrels of oil based upon the relative
energy content (6:1). The depletion base includes capitalized costs, plus future costs to be incurred in developing estimated
recoverable reserves and excludes the cost of assets not yet available for use. Tangible oil and natural gas assets are depreciated
over their estimated useful lives, which may be the same as the estimated life of the underlying reserves.
(b) Exploration and Evaluation Assets
Exploration and evaluation (“E&E”) assets are those expenditures for an area or project for which technical feasibility and
commercial viability have not yet been determined. The Company capitalizes all E&E costs after the right to explore has been
obtained related to exploration properties, including geological and geophysical costs, land acquisition costs and costs for drilling,
completion and testing of exploration wells. When technical feasibility and commercial viability is established, the associated E&E
assets are tested for impairment at the lower of cost and the estimated recoverable amount is transferred to property, plant and
equipment. Any costs in excess of the estimated recoverable amount are charged to expense.
E&E assets are not amortized.
55
SEVEN GENERATIONS ANNUAL REPORT 2014 Farm-in and farm-out arrangements for E&E properties are accounted for at cost. No gain or loss is recognized on the disposition of
a working interest through a farm-out arrangement.
(c) Other Fixed Assets
Other fixed assets include office furniture and fixtures, computer equipment and field vehicles. They are carried at cost and
depreciated over their estimated useful lives at annual rates ranging from 20% to 100%.
Financial Instruments
Financial assets and liabilities are recognized when the Company becomes party to the contractual provisions of the instrument and
are initially measured at fair value. Transaction costs, other than for financial instruments at fair value through profit and loss, are
added to or deducted from the fair value of the financial instrument on recognition. Transaction costs for financial instruments at fair
value through profit and loss are recognized immediately in net income (loss).
Measurement in subsequent periods is dependent upon whether the financial instrument has been classified as fair value through
profit and loss, available for sale, held to maturity, loans and receivables or other financial liabilities. The classification depends on
the nature and purposes of the financial instrument and is determined at the time of initial recognition.
Financial instruments designated as fair value through profit and loss are subsequently measured at fair value with changes to those
fair values recognized immediately in net income (loss). Available for sale financial assets are subsequently measured at fair value
with changes in fair value recognized in other comprehensive income (loss), net of tax. Amounts recognized in other comprehensive
income (loss) for available for sale financial assets are transferred to net income (loss) when realized through disposal or
impairment. Held to maturity investments, loans and receivables and other financial liabilities are subsequently measured at
amortized cost using the effective interest method less any impairment.
An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts are
considered to consist of a host contract plus an embedded derivative. The embedded derivative is separated from the host contract
and accounted for as a derivative unless the economic characteristics and risks of the embedded derivative are closely related to
the host contract. The Company has no material embedded derivatives.
Impairment
(a) Financial Assets
A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A
financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative impact on
the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying
amount and the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed
collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in net income (loss). An impairment loss is reversed if the reversal can be related objectively to
an event occurring after the impairment loss was recognized. The impairment reversal is recognized in net income (loss).
(b) Non-Financial Assets
The carrying amount of property, plant and equipment is reviewed at each reporting date to determine whether there is any
indication of impairment. If such indication exists, then the asset’s recoverable amount is estimated. For goodwill, an impairment
test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment
and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
56
SEVEN GENERATIONS ANNUAL REPORT 2014 For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows
that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”). The
recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell.
In assessing value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects
current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by
reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves.
For the purpose of impairment testing, the goodwill acquired in a business combination is allocated to the CGUs that are
expected to benefit from the synergies of the combination. E&E assets are allocated to related CGUs when they are assessed for
impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to property,
plant and equipment.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount.
Impairment losses are recognized in net income (loss). Impairment losses recognized in respect of CGUs are allocated first to
reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amount of the other assets in the
unit (or group of units) on a prorata basis.
At each reporting date, E&E assets are reviewed for indications of impairment. When the carrying amount of a particular asset
exceeds its recoverable amount, an impairment loss is charged to expense.
An impairment loss in respect of goodwill is not reversed. In respect of property, plant and equipment, impairment losses
recognized in prior years are assessed at each reporting date for any indication that the loss has decreased or no longer exists. An
impairment loss is reversed if there has been a change in the estimates that were used to determine the recoverable amount when
the impairment was recognized. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed
the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had
been recognized.
Provisions
(a) General
Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is
probable that the Company will be required to settle the obligation and a reliable estimate can be made of the amount of the
obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation
at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is
measured using the cash flows estimated to settle the obligation, its carrying amount is the present value of those cash flows
where the effect of the time value of money is material.
(b) Decommissioning Liabilities
The Company records a liability for obligations associated with the decommissioning of its oil and natural gas assets in the period in
which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding
increase in the carrying amount of the related asset, which is depleted on a unit-of-production basis over the life of the reserves.
The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings. Estimates used
are evaluated on a periodic basis and any adjustments are applied prospectively. Actual costs incurred upon settlement of the
obligations are charged against the liability.
Income Taxes
Income tax comprises current and deferred taxes. Income tax is recognized in net income (loss), except when it relates to items
that are recognized in other comprehensive income (loss) or directly in equity, in which case the related tax expense or recovery is
also recognized in other comprehensive income (loss) or equity, respectively.
57
SEVEN GENERATIONS ANNUAL REPORT 2014 Current income tax expense is the expected cash tax payable on the taxable income for the period, using tax rates that have been
enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized on temporary differences between the carrying amount of assets and liabilities for financial reporting
purposes and the amounts used for taxation purposes. Deferred tax liabilities are generally recognized for all temporary differences,
except for temporary differences arising from goodwill or from the initial recognition (other than in a business combination) of other
assets and liabilities in a transaction that affects neither taxable income nor accounting net income (loss). Deferred income tax is
determined on a non-discounted basis using tax rates that have been enacted or substantively enacted at the reporting date and
that are expected to apply in the periods that the temporary differences reverse. A deferred tax asset is recognized to the extent
that it is probable that future taxable profits will be available against which the temporary differences can be utilized. Deferred tax
assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will
be realized.
Stock Based Compensation
The Company follows the fair value method of valuing equity-settled stock based payments which include stock options and
performance warrants. Under this method, compensation cost attributable to stock options and performance warrants granted to
employees, officers, and directors of Seven Generations is measured at fair value at the date of grant and expensed over the
vesting period with a corresponding increase in contributed surplus. Upon the exercise of the stock options and performance
warrants, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to
share capital.
Business Combinations and Goodwill
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as cash paid and the
fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired
identifiable assets and liabilities assumed, including contingent liabilities, are measured at their fair values at the date of acquisition.
Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. Goodwill is
subsequently carried at cost less accumulated impairment losses, if any. Any deficiency of the cost of acquisition below the fair
value of the net identifiable assets acquired is credited to net income (loss) in the period of acquisition. Associated transaction costs
are expensed when incurred.
Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at balance sheet
date. Non-monetary assets and liabilities are translated at the historical exchange rate in effect when the asset was acquired or the
liability was incurred. Revenues and expenses are translated at average exchange rates for the period. Translation gains and losses
are recognized in the statement of net income (loss) and comprehensive income (loss) in the period in which they are incurred and
are reported on a net basis.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, deposits held with financial institutions and other short-term highly liquid
investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Revenue Recognition
Revenue from the sale of oil and natural gas is recognized when title passes from the Company to its customers.
Borrowing Costs
Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to
complete and prepare the assets for their intended use or sale. A qualifying asset is an asset that requires a period of one year or
58
SEVEN GENERATIONS ANNUAL REPORT 2014 greater to complete or prepare for its intended use or sale. All other borrowing costs are recognized in net income (loss) using the
effective interest method. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted
average interest rate applicable to the Company’s outstanding borrowings during the period.
Jointly Operated Assets
The Company’s oil and natural gas activities may involve jointly operated assets. The financial statements of the Company include
the Company’s share of these jointly operated assets and a proportionate share of the related revenue and costs.
Per Share Information
Basic per share information is calculated on the basis of the weighted average number of common shares outstanding during the
period. For diluted per share information, the weighted average number of shares outstanding is adjusted for the potential number
of shares which may have a dilutive effect on net income (loss). Diluted per share information is calculated using the treasury stock
method which assumes that proceeds received from the exercise of in-the-money stock options plus the unamortized stock based
compensation expense would be used to buy back common shares at the average market price for the period.
4. NEW ACCOUNTING POLICIES
Changes in Accounting Polices
As of January 1, 2014, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional
provisions of each standard. A brief description of each new accounting policy and its impact on the Company’s financial
statements is provided below.
International Accounting Standard (“IAS”) 36 “Impairment of Assets” has been amended to reduce the circumstances in
which the recoverable amount of cash generating units is required to be disclosed and clarify the disclosures required when
an impairment loss has been recovered or reversed in the period. The retrospective adoption of these amendments will only
impact the Company’s disclosures in the notes to the financial statements in periods when an impairment loss or impairment
reversal is recognized.
IAS 32 “Financial Instruments: Presentation” is effective January 1, 2014, and has been amended to clarify certain requirements for
offsetting financial assets and liabilities. IAS 32 relates to presentation and disclosure of financial instruments and the retrospective
adoption of this standard did not have a material impact on the Company’s financial statements.
IAS 39 “Financial Instruments: Recognition and Measurement” has been amended to clarify that there would be no requirement to
discontinue hedge accounting if a hedging derivative was novated, provided certain criteria are met. The retrospective adoption of
the amendments does not have any impact on the Company’s financial statements.
International Financial Reporting Interpretations Committee (“IFRIC”) 21 “Levies” was developed by the IFRS Interpretations
Committee and is applicable to all levies imposed by governments under legislation, other than outflows that are within the scope
of other standards (e.g., IAS 12 “Income Taxes”) and fines or other penalties for breaches of legislation. The interpretation clarifies
that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs.
It also clarifies that a levy liability is accrued progressively only if the activity that triggers payment occurs over a period of time, in
accordance with the relevant legislation. Lastly, the interpretation clarifies that a liability should not be recognized before the
specified minimum threshold to trigger that levy is reached. The retrospective adoption of this standard does not have any material
impact on the Company’s financial statements.
Future Accounting Policy Changes
In February 2014, the International Accounting Standards Board (“IASB”) tentatively decided to require an entity to apply
IFRS 9 “Financial Instruments” for annual periods beginning on or after January 1, 2018. IFRS 9 is still available for early adoption.
The impact of the standard on the Company’s financial statements is currently being evaluated.
59
SEVEN GENERATIONS ANNUAL REPORT 2014 In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers,” which replaces IAS 18 “Revenue,” IAS 11
“Construction Contracts,” and related interpretations. The standard is required to be adopted either retrospectively or using a
modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be
applied by Seven Generations on January 1, 2017 and the Company is currently evaluating the impact of the standard on the
financial statements.
5. SIGNIFICANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS
The preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and
assumptions that affect the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these
estimates. The estimates and associated assumptions are based on historical experience and management’s judgment regarding
other factors that are considered to be relevant and reasonable in the circumstances. Anticipating future events involves uncertainty
and consequently the estimates used by management in the preparation of financial statements may change as future events
unfold, additional experience is acquired or the Company’s operating environment changes.
The amounts recorded for depletion and depreciation of oil and natural gas properties are based on estimated recoverable reserves
and future costs. The level of estimated recoverable reserves and associated future cash flows are also key determinants in
assessing whether the carrying values of the Company’s oil and natural gas properties and goodwill have been impaired. By their
nature, these estimates of reserves and future cash flows are subject to measurement uncertainty. Reserve estimates are
determined in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The determination of
reserve estimates involves the exercise of judgment and the use of estimates for oil and natural gas volumes in place, recovery
factors, production rates, future commodity prices and future royalty, operating and capital costs.
IFRS requires that the Company’s oil and natural gas properties be aggregated into CGUs, based on their ability to generate largely
independent cash flows, which are used to assess the properties for impairment. The determination of the Company’s CGUs is
subject to management’s judgment. The Company’s assets are currently held in one CGU.
The Company’s provisions for decommissioning liabilities are based on judgment regarding interpretation of current legal and
constructive requirements and estimates of future costs and expected timing for remediation. Actual costs may differ from
estimated costs because of changes in laws and regulations, reserves, market conditions, discovery and analysis of site conditions
and changes in technology.
The Company uses the Black-Scholes model to estimate the fair value of stock options and performance warrants granted. This
requires assumptions regarding interest rates, dividend rates, the underlying volatility of the shares and the expected life and
forfeitures of the stock options and performance warrants.
The estimated fair values of financial instruments, by their very nature, are subject to measurement uncertainty. Fair value of
financial instruments, where active market quotes are not available, are estimated using the Company’s assessment of available
market inputs and other assumptions. These estimates may vary from the actual prices that will be achieved upon settlement of the
financial instruments.
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations.
As such, income taxes are subject to measurement uncertainty. All tax filings are subject to audit and potential reassessment
after the lapse of considerable time. In addition, the recoverability of loss carryforwards and investment tax credits is uncertain.
The Company records deferred income tax assets and liabilities using income tax rates substantively enacted at the balance
sheet date.
60
SEVEN GENERATIONS ANNUAL REPORT 2014 6. CASH AND CASH EQUIVALENTS
As at December 31
Cash
Government securities, bearing interest at a weighted average rate of 0.8%
(December 31, 2013 – 0.7%) (1)
2014
1,448
846,688
848,136
2013
4,329
306,408
310,737
(1)
Includes term deposit balance of US$66.0 million ($76.6 million) (December 31, 2013 – US$58.0 million ($61.7 million)).
7. OIL AND NATURAL GAS ASSETS
Cost
Balance at December 31, 2012
Additions
Non-cash capitalized costs (1)
Balance at December 31, 2013
Additions
Dispositions
Non-cash capitalized costs (1)
Balance at December 31, 2014
Exploration and
Evaluation
Developed and
Producing
Other
Total
79,999
60,343
-
140,342
61,652
-
-
499,338
510,697
7,219
1,017,254
1,056,411
(5,134)
33,618
835
3,288
-
4,123
2,273
-
-
580,172
574,328
7,219
1,161,719
1,120,336
(5,134)
33,618
201,994
2,102,149
6,396
2,310,539
Accumulated depletion, depreciation and amortization
Balance at December 31, 2012
Depletion, depreciation and amortization expense
Balance at December 31, 2013
Depletion, depreciation and amortization expense
Balance at December 31, 2014
-
-
-
-
-
61,982
38,618
100,600
158,387
258,987
429
303
732
1,060
1,792
62,411
38,921
101,332
159,447
260,779
Net book value
Balance at December 31, 2013
Balance at December 31, 2014
140,342
201,994
916,654
1,843,162
3,391
4,604
1,060,387
2,049,760
(1)
Non-cash capitalized costs include capitalized stock based compensation, decommissioning obligation assets, land swap additions and non-cash interest
and financing.
As at December 31, 2014, the calculation for depletion included an estimated $8.9 billion (2013 – $2.7 billion) for future
development capital associated with undeveloped estimated recoverable proved plus probable reserves and excluded $144.7 million
(2013 – $140.1 million) for the cost of undeveloped land for which no recoverable reserves have been assigned and for other capital
projects not yet in use.
During the year ended December 31, 2014, the Company capitalized $9.8 million (2013 – $6.7 million) of general and administrative
expenses based on actual direct salaries and benefits paid to development personnel specifically related to capital activities,
including $6.1 million (2013 – $4.4 million) related to stock based compensation.
61
SEVEN GENERATIONS ANNUAL REPORT 2014
During the years ended December 31, 2014, the Company capitalized $0.5 million (2013 – $Nil) of borrowing costs.
During the year ended December 31, 2014, the Company closed asset swap arrangements of non-producing assets. For purposes
of determining the gain on disposition, the estimated fair market value was based on the fair value of the asset received. The
Company recorded a gain of $4.3 million on the assets disposed of for the year ended December 31, 2014.
At the end of each reporting period, the Company performs an asset impairment review to ensure that the carrying value of its oil
and natural gas properties and associated goodwill is recoverable. The Company also performs an annual goodwill impairment test.
The Company determined that oil and natural gas properties and goodwill were not impaired at December 31, 2014 and 2013. In
determining the recoverable amount, the Company calculated a value in use of its oil and natural gas properties applying a pre-tax
discount rate of 10% on cash flows from proved plus probable reserves. The estimated cash flows were consistent with the
estimates of the Company’s independent reserves evaluator. The Company also considered additional values for other reserves and
resources and undeveloped land not included in proved plus probable reserves.
8. BANK DEBT
At December 31, 2014, the Company had available a $480.0 million revolving credit facility (2013 – $150.0 million) with a syndicate
of banks (the “credit facility”), which has a three year term ending in September 2017. The credit facility is subject to a
redetermination of the borrowing base semi-annually and is secured by a floating charge over the Company’s assets. The credit
facility bears interest rates based on a pricing grid that increases or decreases based on the ratio of indebtedness to earnings before
interest, taxes, depreciation, depletion and amortization. The credit facility also includes standby fees on balances not drawn.
During the year ended December 31, 2014, no amounts were drawn on the credit facility. During the year ended December 31, 2013,
the Company borrowed up to $30.7 million on the credit facility for a period of one week. As at December 31, 2014 and
December 31, 2013, there was no balance outstanding on the credit facility.
9. SENIOR NOTES
Year ended December 31
Balance, beginning of year
Issuance of debt
Debt issue costs
Unrealized foreign exchange loss
Amortization of premium and debt issue costs
Balance, end of year (1)
2014
414,525
356,342
(9,840)
53,319
(466)
813,880
2013
-
404,960
(11,201)
19,958
808
414,525
(1) Balance of debt and unamortized discount and premium at December 31, 2014 is US$701.1 million ($814.3. million) (2013 – US$388.9 million ($403.3 million)).
On May 10, 2013, the Company closed a private placement of US$400.0 million of senior unsecured notes. The notes bear
interest at 8.25% per annum (calculated using a 360-day year) payable on May 15 and November 15 of each year, commencing
on November 15, 2013. The notes will mature May 15, 2020. After May 15 of each of the following years, the notes are redeemable
at the Company’s option, in whole or in part, at the following redemption prices (expressed as a percentage of the principal
amount of the notes): 2016 at 106.188%, 2017 at 104.125%, 2018 at 102.063% and 2019 at 100%. At any time prior to
May 15, 2016, the Company may redeem up to US$140.0 million principal amount of the notes at a redemption price equal to
108.250% of the principal amount of the notes redeemed with the net proceeds of an equity offering by the Company. In addition,
at any time prior to May 15, 2016, the Company may redeem all or a part of the notes at a redemption price equal to 100% of the
aggregate principal amount plus an applicable premium that will be the greater of: (a) 1.0% of the principal amount; and (b) an
amount equal to the excess of the present value at such redemption date of the redemption price at May 15, 2016 (106.188%) plus
all accrued interest due through May 15, 2016 over the principal amount of the note, with the present value being computed using a
discount rate based on current US Treasury yields plus 50 basis points. The Company reviewed the terms of the senior notes to
determine if the prepayment options were embedded derivatives. While the prepayment options meet the definition of an
embedded derivative, the Company determined the fair value of the prepayment options was not material and an embedded
derivative has not been recorded.
62
SEVEN GENERATIONS ANNUAL REPORT 2014 On February 5, 2014, the Company closed a private placement of US$300.0 million of senior unsecured notes issued under
a supplemental indenture to the indenture governing the terms of the US$400.0 million of senior unsecured notes issued
on May 10, 2013. The February 2014 notes were issued at 107% of par, resulting in gross proceeds to the Company of
US$321.0 million. The terms for this second placement are the same as above.
Subject to certain exceptions and qualifications, the senior unsecured notes have no financial covenants but limit the Company’s
ability to, among other things: make payments and distributions; incur additional indebtedness; issue disqualified or preferred
stock; create or permit liens to exist; make certain dispositions; transfers of assets; and engage in amalgamations, mergers
or consolidations.
The notes are carried at amortized cost, net of transaction costs. The notes accrete up to the principal balance on maturity
using the effective interest rate method and an effective interest rate of 7.3% and 8.6% for each respective 2014 and 2013
issuance. Exchange rates used for the 2014 issuance of US$300.0 million and the 2013 issuance of $400.0 million was 0.901
and 0.940, respectively.
10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31
Trade
Accrued liabilities
11. DECOMMISSIONING LIABILITIES
Year ended December 31
Balance, beginning of year
Liabilities incurred
Changes in estimates (1)
Changes in estimated discount rates
Decommissioning expenditures
Accretion
Balance, end of year
2014
18,849
249,259
268,108
2014
23,656
20,873
2,367
4,311
(206)
1,162
52,163
2013
72,892
52,795
125,687
2013
21,298
2,621
2,683
(3,679)
-
733
23,656
(1) Changes in the status of wells and the estimated costs of abandonment and reclamation are factors resulting in a change in estimate.
The total future decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities,
the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in
future periods. The total undiscounted amount of the estimated cash flows required to settle the decommissioning liabilities at
December 31, 2014 is approximately $90.9 million (2013 – $46.4 million) which is expected to be incurred over the next 35 years
with the majority of costs incurred between 2036 and 2049. At December 31, 2014 a risk-free rate of 2.3% (2013 – 3.2%) and an
inflation rate of 2.0% (2013 – 2.0%) were used to calculate the provision for decommissioning liabilities.
63
SEVEN GENERATIONS ANNUAL REPORT 2014 12. DEFERRED INCOME TAXES
The provision for deferred income tax expense is different from the amount computed by applying the combined Canadian federal
and provincial income tax rate to income (loss) before income taxes. The reasons for the differences are as follows:
Year ended December 31
Income (loss) before taxes
Canadian statutory income tax rate
Expected income tax expense (recovery)
Add (deduct):
Non-deductible stock based compensation
Non-deductible portion of foreign exchange losses
Valuation allowance
Other
Changes in the components of the deferred tax liability are as follows:
2014
215,708
25.0%
53,927
2,987
6,308
8,210
76
71,508
2013
(13,807)
25.0%
(3,452)
2,389
1,487
-
(73)
351
January 1, 2014
Movement
December 31, 2014
35,957
(661)
(9,127)
(4,668)
(5,914)
(3,758)
(2,191)
(310)
9,328
-
9,328
43,190
35,441
-
-
(7,127)
(8,695)
(6,704)
(5,019)
51,086
8,210
59,296
79,147
34,780
(9,127)
(4,668)
(13,041)
(12,453)
(8,895)
(5,329)
60,414
8,210
68,624
January 1, 2013
Movement
December 31, 2013
33,680
163
(9,127)
(4,740)
(5,324)
(2,066)
-
(410)
(20)
12,156
2,277
(824)
-
72
(590)
(1,692)
(2,191)
410
(290)
(2,828)
35,957
(661)
(9,127)
(4,668)
(5,914)
(3,758)
(2,191)
-
(310)
9,328
Property, plant and equipment
Mark-to-market financial instruments
Investment tax credits
Non-capital losses
Decommissioning liabilities
Financing costs
Unrealized foreign exchange losses
Other
Valuation allowance
Property, plant and equipment
Mark-to-market financial instruments
Investment tax credits
Non-capital losses
Decommissioning liabilities
Financing costs
Unrealized foreign exchange losses
Capital loss
Other
64
SEVEN GENERATIONS ANNUAL REPORT 2014 The changes in the deferred tax liability were allocated to:
Year ended December 31
Income statement
Share capital
2014
71,508
(12,212)
59,296
2013
351
(3,179)
(2,828)
The Company has no current income tax expense given its total tax pools of $1.7 billion at December 31, 2014 (2013 – $0.9 billion).
As at December 31, 2014, the Company had non-capital losses of approximately $18.7 million (2013 – $18.7 million) available
for deduction against future taxable income which mostly expire after 2027 and investment tax credits of $9.1 million
(2013 – $9.1 million) with expiries starting in 2021.
13. SHARE CAPITAL
Authorized
Unlimited number of Class A Common Voting Shares
Unlimited number of Class B Common Non-voting Shares
Unlimited number of A, B, C, and D Preferred Shares
Unlimited number of Special Voting Shares
On May 29, 2014, shareholders approved a resolution to amend the Company’s Articles of Incorporation to allow holders of Class B
Common Shares to convert into Class A Common Shares on a 1 for 1 basis.
On September 8, 2014, the Company amended its Articles of Incorporation to divide the issued and outstanding Class A Common
Voting Shares on a two-for-one basis. As a result of this division of the Class A Common Voting Shares, Class B Common
Non-voting Shares may now be converted, at the option of the holder of Class B Common Non-voting Shares or the Company,
on the basis of one Class B Common Non-voting Share for two Class A Common Voting Shares (on a post-division basis). In
December 2014, the Company amended the terms of the stock options and performances warrants, issued prior to the completion
of the initial public offering (“IPO”), such that upon exercise, the holders of these instruments will receive two Class A Common
Voting Shares (rather than Class B Non-voting Shares) to reflect the two-for-one stock split.
The share split has been reflected in these financial statements for the year ended December 31, 2014 on a retroactive basis for the
Class A Common Voting Shares, stock options, performance warrants and per share information.
At December 31, 2014 and 2013, there are no Preferred Shares or Special Voting Shares issued and outstanding.
65
SEVEN GENERATIONS ANNUAL REPORT 2014 Issued and Outstanding
Year ended December 31
Class A Common Voting Shares
Balance, beginning of year
Issued on IPO (a)
Issued for cash (b)
Share issue costs, net of deferred tax (a,b)
Issued on exercise of stock options
Transfer from contributed surplus on exercise of
stock options
Conversion of Class B Common Non-voting Shares (1)
Balance, end of year
2014
2013
Number (000s)
Amount
Number (000s)
Amount
185,420
51,750
-
-
110
-
7,436
244,716
783,514
931,500
-
(36,637)
275
130
37,268
165,340
542,057
-
20,080
-
-
-
-
-
250,992
(9,535)
-
-
-
1,716,050
185,420
783,514
(1) Class B Common Non-voting shares convert into Class A Common Voting Shares on a two-for-one basis.
(a) On November 5, 2014, the Company closed an IPO for gross proceeds of $931.5 million through the issuance of 51.8 million
Class A Common Voting Shares at a price of $18.00 per common share including an over-allotment option exercised by the
underwriters for gross proceeds of $121.5 million. Share issue costs related to the IPO and equity financing were $51.4 million,
including the underwriters’ commission for 5% of the gross proceeds of the IPO. Of this amount, the Company expensed
$2.5 million (Note 17) in the income statement with the remainder charged against share capital. The Company also recognized
a deferred income tax benefit of $12.2 million related to the share issue costs. As a part of the IPO, the Company agreed
to apply restrictions to the transfer of common shares issued prior to the IPO without the consent of the underwriters.
At December 31, 2014, 193.0 million shares were restricted from trading until 180 days from the IPO or May 5, 2015.
(b) In December 2013, the Company issued 20.0 million Class A shares at $12.50 per share for gross proceeds of $251.0 million.
Share issue costs related to the equity financing were $12.7 million and the Company recognized a deferred income tax benefit
of $3.2 million related to the share issue costs.
Year ended December 31
Class B Common Non-voting Shares
Balance, beginning of year
Issued on exercise of stock options
Issued on exercise of performance warrants
Transfer from contributed surplus on exercise of
stock options and performance warrants
Conversion to Class A Common Voting Shares (1)
Balance, end of year
2014
2013
Number (000s)
Amount
Number (000s)
Amount
966
1,770
1,505
-
(3,718)
523
6,550
9,765
15,858
8,824
(37,268)
3,729
600
173
193
-
-
966
3,000
865
1,739
946
-
6,550
(1) Class B Common Non-voting shares convert into Class A Common Voting Shares on a two-for-one basis.
66
SEVEN GENERATIONS ANNUAL REPORT 2014 14. STOCK BASED COMPENSATION
Stock Options
The Company has issued stock options to its directors, officers, and employees to acquire up to 12.4 million Class A Common
Voting Shares. These stock options (“Pre-IPO stock options”) were granted under the stock option plan provided for in the
Amended and Restated Shareholder Agreement (“USA”) effective while Seven Generations was a private company. These stock
options originally granted the holders the right to acquire one Class B Common Non-voting Share for each stock option exercised.
In December 2014, the terms of the Pre-IPO stock options were amended to provide consistency with the two-for-one stock
split of Class A Common Voting Shares that occurred in September 2014. After the amendment in December 2014, each stock
option grants the holder the right to acquire one Class A Common Voting Share instead of a Class B Common Non-voting
Share. The number of Pre-IPO stock options outstanding was doubled as a result of the stock split and the exercise price of each
option outstanding was reduced by one-half. The Pre-IPO stock options have a seven-year term from the date of grant and vest
over a period of three years. After the November 5, 2014 closing of the IPO, no additional Pre-IPO stock options may be granted
under this plan.
In anticipation of an IPO, the Company’s stock option plan was amended and restated on August 27, 2014 (the “New Plan”). Stock
options awarded after the closing of the IPO are issued under the New Plan. These stock options are exercisable for Class A
Common Voting Shares rather than Class B Common Non-voting Shares. The stock options will vest over a period of three years, or
as otherwise set out by the Board in the applicable grant agreement, and have a maximum term of ten years. The maximum
number of Class A Common Voting Shares issuable under the New Plan and other share based compensation arrangements
(excluding the performance warrants) must not exceed 10% of the aggregate of the number of outstanding Class A Common Voting
Shares plus two times the number of outstanding Class B Common Non-voting Shares. As at December 31, 2014, no stock options
were issued under the New Plan.
The following table sets forth a reconciliation of stock options exercisable into Class A Common Voting Shares:
Number of
Options (000s)
Weighted Average
Exercise Price ($)
Balance at December 31, 2012
Granted
Exercised
Forfeited
Balance at December 31, 2013
Granted
Exercised
Forfeited
Balance at December 31, 2014
11,650
2,257
(346)
(135)
13,426
2,927
(3,650)
(318)
12,385
3.02
5.71
2.50
2.86
3.49
17.11
2.75
5.81
6.71
67
SEVEN GENERATIONS ANNUAL REPORT 2014 A summary of stock options outstanding and exercisable into Class A Common Voting Shares at December 31, 2014 is as follows:
2.6
4.9
5.9
-
-
3.2
2013
2.13
1.1
2.1
3.0
65.0
-
Exercise price ($)
2.50
5.50
12.50
17.50
18.00
Options Outstanding
Options Vested
Number of
Options (000s)
Weighted Average
Remaining Life
(Years)
Number of
Options (000s)
Weighted Average
Remaining Life
(Years)
5,736
3,760
489
1,892
508
12,385
2.7
5.0
6.2
6.4
6.7
4.3
5,723
1,824
15
-
-
7,562
The fair value of stock options granted was estimated using a Black-Scholes pricing model with the following weighted
average assumptions:
Year ended December 31
Fair value of options granted ($/option)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%) (1)
Expected dividend yield (%)
2014
7.81
1.4
3.9
3.0
60.0
-
(1) Expected volatility is based on the historical share price volatility from a peer group of listed companies.
During the year ended December 31, 2013, the stock options granted in 2008 were amended to extend the expiry date by one year
in order to realign compensation with the Company’s business plan. The incremental fair value of the stock option modifications of
$0.4 million was expensed in the year ended December 31, 2013. The fair value was estimated using a Black-Scholes pricing model
with the following weighted average assumptions:
Fair value of option modification ($/option)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%)
Expected dividend yield (%)
0.11
1.22
2.5
3.0
65
-
During the year ended December 31, 2014, the stock options granted in 2008 were amended to extend the expiry date by one year
in order to realign compensation with the Company’s business plan. The incremental fair value of the stock option modifications
was a nominal amount for the year ended December 31, 2014. The fair value was estimated using a Black-Scholes pricing model
with the following weighted average assumptions:
Fair value of option modification ($/option)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%)
Expected dividend yield (%)
68
0.02
1.13
1.5
3.0
60
-
SEVEN GENERATIONS ANNUAL REPORT 2014 Performance Warrants
The Company has issued performance warrants to its directors, officers, and employees to acquire up to 26.0 million Class A
Common Non-voting Shares. These performance warrants were granted pursuant to the USA effective while Seven Generations
was a private company. These performance warrants originally granted the holders the right to acquire one Class B Common
Non-voting Share for each performance warrant exercised. In December 2014, the terms of the performance warrants were
amended to provide consistency with the two-for-one stock split of Class A Common Voting Shares that occurred in September
2014. After the amendment in December 2014, each warrant grants the holder the right to acquire one Class A Common Voting
Share instead of a Class B Common Non-voting Share. The number of performance warrants outstanding was doubled as a result
of the stock split and the exercise price of each warrant outstanding was reduced by one-half. The performance warrants have a
seven-year term from the date of grant and vest over a period of five years. After the November 5, 2014 closing of the IPO, no
additional performance warrants may be granted.
The following table sets forth a reconciliation of performance warrants exercisable into Class A Common Voting Shares:
Balance at December 31, 2012
Granted
Exercised
Forfeited
Balance at December 31, 2013
Granted
Exercised
Forfeited
Balance at December 31, 2014
Number of
Warrants (000s)
Weighted Average
Exercise Price ($)
27,792
2,236
(386)
(817)
28,825
1,350
(3,011)
(1,196)
25,968
5.33
6.01
4.50
5.28
5.39
17.38
5.27
6.31
5.99
A summary of performance warrants outstanding and exercisable into Class A Common Voting Shares at December 31, 2014 is
as follows:
Weighted average exercise price ($)
5.25
5.85
12.50
17.50
Warrants Outstanding
Warrants Vested
Number of
Warrants (000s)
Weighted Average
Remaining Life
(Years)
Number of
Warrants (000s)
Weighted Average
Remaining Life
(Years)
19,121
5,545
94
1,208
25,968
2.6
4.8
6.1
6.4
3.2
15,050
1,810
7
-
16,867
2.4
4.7
5.9
-
2.6
69
SEVEN GENERATIONS ANNUAL REPORT 2014 The fair value of performance warrants granted was estimated using a Black-Scholes pricing model with the following weighted
average assumptions:
Year ended December 31
Fair value of warrants granted ($/warrant)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%) (1)
Expected dividend yield (%)
2014
8.87
1.4
4.9
3.0
60.0
-
2013
2.02
1.1
2.1
3.0
65.0
-
(1) Expected volatility is based on the historical share price volatility from a peer group of listed companies.
During the year ended December 31, 2013, the performance warrants granted in 2008 were amended to extend the expiry date by
one year in order to realign compensation with the Company’s business plan. The incremental fair value of the performance warrant
modifications of $1.7 million was expensed in the year ended December 31, 2013. The fair value was estimated using a Black-
Scholes pricing model with the following weighted average assumptions:
Fair value of option modification ($/option)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%)
Expected dividend yield (%)
0.21
1.22
2.5
3.0
65
-
During the year ended December 31, 2014, the performance warrants granted in 2008 were amended to extend the expiry date
by one year in order to realign compensation with the Company’s business plan. The incremental fair value of the performance
warrant modifications of $0.8 million was expensed in the year ended December 31, 2014. The fair value was estimated using a
Black-Scholes pricing model with the following weighted average assumptions:
Fair value of option modification ($/option)
Risk-free interest rate (%)
Expected life (years)
Expected forfeiture rate (%)
Expected volatility (%)
Expected dividend yield (%)
Compensation Plans
0.12
1.13
1.5
3.0
60
-
On August 27, 2014, the Board of Directors (the “Board”) adopted a Performance and Restricted Share Unit (“PRSU”) Plan and a
Deferred Share Unit (“DSU”) Plan. The maximum number of Class A Common Voting Shares that may be issued to officers and
employees under the PRSU Plan is 1,000,000. Each Share Unit issued under the PRSU Plan will grant to the holder the right to
receive a Class A Voting Common Share or, in certain circumstances, the cash equivalent of a Class A Common Share, based on
the achievement of certain performance criteria. The vesting schedule of the PRSUs will be determined at the discretion of the
Compensation Committee of the Board. The maximum number of Class A Common Voting Shares that may be issued to non-
executive directors under the DSU Plan is 600,000. Each DSU may be redeemed for a Class A Common Voting Share issued by the
Company from treasury. The vesting schedule of the DSUs will be determined at the discretion of the Compensation Committee,
but generally in the case of DSUs granted in lieu of director retainers or as annual incentives, the DSUs vest immediately on the
award date. At December 31, 2014, no units had been issued for either of these plans.
70
SEVEN GENERATIONS ANNUAL REPORT 2014 15. PER SHARE AMOUNTS
Basic and diluted per share amounts have been calculated based on the following:
Year ended December 31 (1)
In (000s)
Weighted average number of common shares – basic
Effect of outstanding stock options and performance warrants (2)
Weighted average number of common shares – diluted
2014
198,742
25,975
224,717
2013
167,802
15,486
183,288
(1) All numbers reflect two-for-one share split.
(2) 2,399,468 anti-dilutive stock options and 1,207,670 anti-dilutive performance warrants have been excluded above (2013 – 33,000 anti-dilutive stock options).
16. GENERAL AND ADMINISTRATIVE EXPENSES
Year ended December 31
Personnel
IPO expenses
Professional fees
Rent
Other office costs
Gross expenses
Capitalized salaries and benefits
Operating overhead recoveries
17. FINANCE EXPENSE
Year ended December 31
Interest on senior notes
Revolving credit facility fees and other
Amortization of premium and debt issue costs
Accretion
Total finance costs
Capitalized borrowing costs
Total finance expense
18. LIQUIDITY EVENT EXPENSE
2014
12,912
2,506
2,636
1,210
4,713
23,977
(2,661)
(1,058)
20,258
2014
61,303
2,142
(466)
1,162
64,141
(500)
63,641
2013
7,227
-
739
453
2,524
10,943
(2,159)
(667)
8,117
2013
22,113
793
808
733
24,447
-
24,447
Pursuant to the USA, the Company was obligated to compensate, with cash or shares, certain directors, officers and employees
prior to the completion of a change of control, liquidity event or qualified initial public offering (the “Liquidity Event”). With the
closing of the IPO on November 5, 2014, the Liquidity Event condition was satisfied and the Company recognized a liability of
$36.0 million. The settlement of the liability was approved by the Board of Directors to be payable in cash in 2015.
For purposes of Note 24, the allocation of Liquidity Event payments to key management personnel will be determined in 2015.
71
SEVEN GENERATIONS ANNUAL REPORT 2014 19. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT CONTRACTS
Financial Instrument Classification and Measurement
The Company’s financial instruments include cash and cash equivalents, outstanding cheques in excess of bank balances, accounts
receivable, deposits, risk management contracts, accounts payable and accrued liabilities, the credit facility and senior notes.
The Company’s financial instruments that are carried at fair value on the balance sheets include cash and cash equivalents,
outstanding cheques in excess of bank balances, risk management contracts and the credit facility. The credit facility has a floating
rate of interest and therefore the carrying value approximates the fair value. The senior notes are carried at amortized cost, net of
transaction costs and accrete to the principal balance on maturity using the effective interest rate method.
Seven Generations classifies the fair value of these instruments according to the following hierarchy based on the amount of
observable inputs used to value the instrument.
¡¡ Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets
are those in which transactions occur in sufficient frequency and volume to provide pricing information.
¡¡ Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or
indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be substantially observed in the marketplace.
¡¡ Level 3 – Valuations in this level are those inputs for the asset or liability that are not based on observable market data.
Cash and cash equivalents and outstanding cheques in excess of bank balances are classified as Level 1 measurements. Risk
management contracts, the credit facility and fair value disclosure for the senior notes are classified as Level 2 measurements.
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement
within the fair value hierarchy level. Seven Generations does not have any fair value measurements classified as Level 3.
There were no transfers within the hierarchy in the years ended December 31, 2014. The carrying value of the Company’s
accounts receivable, deposits, accounts payable and accrued liabilities approximate their fair values due to the short-term maturity
of these instruments.
72
SEVEN GENERATIONS ANNUAL REPORT 2014 The classification, carrying values and fair values of the Company’s financial instruments are as follows:
As at December 31
FINANCIAL ASSETS
Fair Value Through Profit and Loss
Cash and cash equivalents
Risk management contracts
Loans and Receivables
Accounts receivable
Deposits
FINANCIAL LIABILITIES
Fair Value Through Profit and Loss
Outstanding cheques in excess of bank balances
Risk management contracts
Other Financial Liabilities
Accounts payable and accrued liabilities
Senior notes payable
2014
2013
Carrying Value
Fair Value
Carrying Value
Fair Value
848,136
139,119
64,417
5,034
848,136
139,119
64,417
5,034
310,737
310,737
-
-
30,500
1,710
30,500
1,710
-
-
-
-
268,108
813,880
268,108
782,000
3,252
2,646
125,687
414,525
3,252
2,646
125,687
434,000
Financial Assets and Financial Liabilities Subject to Offsetting
The Company’s risk management contracts are subject to master netting agreements that create a legally enforceable right to
offset by counterparty the related financial assets and financial liabilities on the Company’s balance sheets.
The following is a summary of financial assets and financial liabilities that are subject to offset:
As at December 31, 2014
Risk management contracts
Current asset
Long-term asset
Net position
As at December 31, 2013
Risk management contracts
Current asset
Current liability
Net position
Market Risk
Gross Amounts
of Recognized Financial
Assets (Liabilities)
Gross Amounts
of Recognized Financial
Assets (Liabilities) Offset
in Balance Sheet
Net Amounts of
Recognized Financial Assets
(Liabilities) Recognized
in Balance Sheet
138,122
997
139,119
-
-
-
138,122
997
139,119
Gross Amounts
of Recognized Financial
Assets (Liabilities)
Gross Amounts
of Recognized Financial
Assets (Liabilities) Offset
in Balance Sheet
Net Amounts of
Recognized Financial Assets
(Liabilities) Recognized
in Balance Sheet
68
(2,714)
(2,646)
(68)
68
-
-
(2,646)
(2,646)
Market risk is the risk that changes in market prices including commodity prices, interest rates and foreign exchange risks will affect
the Company’s income (loss) or the value of financial instruments. The objective of market risk management is to reduce exposures
to acceptable limits while optimizing returns.
73
SEVEN GENERATIONS ANNUAL REPORT 2014 (a) Commodity Price Risk
Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes
in commodity prices. Commodity prices for oil and natural gas are impacted by world economic events that dictate the levels of
supply and demand. The Company uses derivative financial instruments to manage its exposure to fluctuations in commodity
prices. The Company considers these transactions to be effective economic hedges; however, the Company’s contracts do not
qualify as effective hedges for accounting purposes. The Company does not enter into commodity contracts other than to meet the
Company’s expected sales requirements.
The following risk management contracts were outstanding at December 31, 2014:
Commodity
Term
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Oil
Oil
Oil
Oil
Oil
Jan 2015 – Dec 2015
Jan 2015 – Mar 2015
Jan 2015 – Mar 2015
Jan 2015 – Mar 2015
Jan 2015 – Mar 2015
Apr 2015 – Dec 2015
Apr 2015 – Jun 2015
Jul 2015 – Dec 2015
Jul 2015 – Sept 2015
Jul 2015 – Dec 2015
Oct 2015 – Dec 2015
Jan 2016 – Mar 2016
Apr 2015 – Jun 2015
Jan 2015 – Dec 2015
Jan 2015 – Mar 2015
Jul 2015 – Sept 2015
Oct 2015 – Dec 2015
Contract
Fixed Price
Fixed Price
Volume
Average Price/Unit
8,500 GJ/d
2,000 GJ/d
CDN$3.82
CDN$4.70
Costless Collar
39,000 GJ/d
CDN$4.00 – $5.45
Fixed Price
Costless Collar
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
Fixed Price
5,000 GJ/d
CDN$4.00
19,000 GJ/d
30,000 GJ/d
25,000 GJ/d
10,000 GJ/d
5,000 GJ/d
10,000 GJ/d
15,000 GJ/d
17,500 GJ/d
CDN$4.00 – $5.39
CDN$3.91
CDN$3.86
CDN$3.43
CDN$3.86
CDN$3.50
CDN$3.77
CDN$3.79
11,000 bbls/d
CDN$102.15
1,100 bbls/d
CDN$99.81
10,100 bbls/d
6,500 bbls/d
1,000 bbls/d
CDN$102.57
CDN$102.57
CDN$100.75
During the year ended December 31, 2014, the Company’s risk management contracts resulted in a realized gain of $9.7 million
(2013 – $0.3 million) and an unrealized gain of $141.8 million (2013 – unrealized loss of $3.3 million).
The following table demonstrates the impact of changes in commodity pricing on income before tax, based on risk management
contracts in place at December 31, 2014:
10% increase in AECO/GJ
10% decrease in AECO/GJ
10% increase in US$ WTI/bbl
10% decrease in US$ WTI/bbl
(b) Interest Rate Risk
Gain (Loss)
(7,234)
7,234
(19,514)
19,514
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The senior notes
payable bear interest at a fixed rate. The Company’s credit facility bears a floating rate of interest and, accordingly, the Company is
exposed to interest rate fluctuations to the extent that any advances remaining outstanding under the facility. During May 2013, the
Company borrowed up to $30.7 million on the credit facility for a period of one week. During the year ended December 31, 2014, no
amounts were drawn on the credit facility.
74
SEVEN GENERATIONS ANNUAL REPORT 2014 (c) Foreign Currency Exchange Risk
Foreign currency exchange risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of
changes in foreign exchange rates.
Prices for oil are determined in global markets and generally denominated in US dollars. Natural gas prices obtained by the
Company are influenced by both US and Canadian demand and the corresponding North American supply. The exchange rate effect
cannot be quantified but generally an increase in the value of the Canadian dollar as compared to the US dollar will reduce the prices
received by the Company for its oil and natural gas sales.
The Company is exposed to foreign exchange rate fluctuations on the principal and interest related to the senior notes payable, as
well as on cash balances held in US dollars. The foreign currency risk associated with interest payments is partially offset by a
marketing arrangement for the Company’s natural gas liquids, excluding condensate, which is denominated in US dollars.
The following table demonstrates the impact of changes in the Canadian to US dollar exchange rate on income before tax, based on
US denominated balances outstanding at December 31, 2014:
$0.01 increase in CAD/USD exchange rate
$0.01 decrease in CAD/USD exchange rate
Gain (Loss)
8,538
(8,739)
The carrying amount of the Company’s US dollar denominated monetary assets and liabilities as at December 31 was as follows:
Assets
Liabilities
Credit Risk
2014
78,042
822,573
2013
67,053
419,083
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual
obligations, and arises primarily from the Company’s receivables from oil and natural marketers and joint venture partners and hedging
assets. The Company’s maximum exposure to credit risk is equal to the carrying amount of these instruments.
Substantially all of the Company’s accounts receivable are with oil and natural gas marketers and joint venture partners under
normal industry sale and payment terms and are subject to normal industry credit risk. Receivables from oil and natural gas
marketers are normally collected on or about the 25th day of the following month. The Company sells the majority of its production
to two oil and natural gas marketers and is therefore subject to concentration risk. Production is sold to marketers with investment
grade credit ratings, if available in the area of production. The Company historically has not experienced any collection issues with
its oil and natural gas marketers. As at December 31, 2014, the Company’s most significant marketer accounted for $21.1 million
(2013 – $11.6 million) of total receivables and 4% of total revenues (2013 – 10%). Receivables from joint venture partners are
typically collected within one to three months of the joint venture bill being issued. The Company attempts to mitigate the risk from
joint venture receivables by obtaining partner pre-approval of significant capital expenditures. However, the receivables are from
participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as
commodity price fluctuations, escalating costs, the risk of unsuccessful drilling and disagreements with partners. As the operator of
properties, the Company has the ability to withhold production from joint interest partners in the event of non-payment. As at
December 31, 2014, receivables outstanding for more than 90 days totalled less than $0.1 million (2013 – $0.1 million). The
Company believes all of the accounts receivable will be collected. The maximum credit risk exposure associated with accounts
receivable is the total carrying value.
All the Company’s cash and cash equivalents are held with Canadian chartered banks and as such, the Company is exposed to
credit risk on any default by the institutions of amounts in excess of the minimum guaranteed amount. The Company considers the
risk of default by a Canadian chartered bank to be remote. As at December 31, 2014, the Company does not invest any cash in
complex investment vehicles with higher risk such as asset backed commercial paper. All of the Company’s risk management
contracts are with Schedule 1 Canadian chartered banks or high credit-quality financial institutions.
75
SEVEN GENERATIONS ANNUAL REPORT 2014 Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meets its financial obligations as they fall due. The Company manages
its liquidity risk through ensuring, as reasonably as possible, that it will have sufficient liquidity to meets its liabilities when due
without incurring unacceptable losses or risking damage to the Company’s reputation. At December 31, 2014, the Company had
$848.1 million of cash and cash equivalents on hand, plus a $480.0 million undrawn revolving credit facility. Management believes it
has sufficient funding to meet foreseeable liquidity requirements. The Company prepares capital expenditure budgets which are
regularly monitored and updated as considered necessary. As well, the Company utilizes authorizations for expenditures on both
operated and non-operated projects to manage capital expenditures.
The following are the contractual maturities of financial liabilities at December 31, 2014:
Accounts payable and accrued liabilities
Senior notes payable (1)
Interest on senior notes payable (1)
Total
Less Than
1 Year
268,108
-
66,996
335,104
1-3 Years
4-5 Years
Thereafter
-
-
-
-
133,992
133,992
133,992
133,992
-
812,070
25,123
837,193
Total
268,108
812,070
360,103
1,440,281
(1) Balances denominated in US dollars have been translated at the December 31, 2014 exchange rate of 0.862.
20. CAPITAL MANAGEMENT
The capital structure of the Company is as follows:
As at December 31
Total debt (1)
Total equity (2)
Total capital
2014
813,880
1,910,926
2,724,806
2013
414,525
827,953
1,242,478
(1) Senior unsecured notes.
(2) Equity is defined as share capital plus contributed surplus plus any retained earnings (deficit) and other comprehensive income (deficit).
The Company’s objective for managing capital continues to be to maintain a strong balance sheet and capital base to provide
financial flexibility to position the Company for future growth and development. The Company strives to grow and maximize
long-term shareholder value by ensuring it has the financing capacity to fund projects that are expected to add value to
shareholders. Near-term major acquisitions and capital development will be funded by funds flow from operations, cash or cash
equivalents, equity financings, the credit facility (Note 8) and debt financings (Note 9). The Company will strive to balance the
proportion of debt and equity in its capital structure to take into account the level of risk being incurred in its capital expenditures.
The Company had working capital of $653.8 million (current assets less current liabilities excluding current portion of risk
management contracts and deferred credits) plus $480.0 million of undrawn credit facility capacity creating available funding of
$1.1 billion at December 31, 2014 and plans to use these funds, along with funds from operations, for the execution of its 2015
capital program.
Subject to certain exceptions and qualifications, the senior unsecured notes limit the Company’s ability to, among other things:
make restricted payments, incur additional indebtedness, issue disqualified or preferred stock; create or permit liens to exist; create
or permit to exist restrictions on the ability to make payments and distributions; make certain dispositions; transfers of assets; and
engage in amalgamations, mergers or consolidations; and engage in certain transactions with affiliates.
76
SEVEN GENERATIONS ANNUAL REPORT 2014 21. SUPPLEMENTAL CASH FLOW INFORMATION
Change in Non-Cash Working Capital
Year ended December 31
Accounts receivable
Deposits and prepaid expenses
Accounts payable and accrued liabilities
Relating to:
Operating activities
Investing activities
Foreign Exchange Loss (Gain)
Year ended December 31
Unrealized foreign exchange loss
Realized foreign exchange gain
Other Cash Flow Information
Year ended December 31
Cash interest paid
Cash taxes paid
22. COMMITMENTS
2014
(33,917)
(6,776)
142,334
101,641
10,129
91,512
2014
53,406
(5,733)
47,673
2014
57,271
-
2013
(20,883)
(1,559)
63,917
41,475
(8,398)
49,873
2013
19,975
(9,078)
10,897
2013
22,906
-
The following table lists the Company’s estimated material contractual commitments at December 31, 2014:
Senior notes (1)
Interest on senior notes (1)
Firm transportation and processing agreements (1)
Operating leases
Estimated contractual obligations
Total
812,070
360,103
1,775,622
14,717
2,962,512
Less Than
1 Year
-
66,996
25,788
2,217
95,001
1-3 Years
4-5 Years
Thereafter
-
133,992
386,591
4,295
-
133,992
487,939
3,104
812,070
25,123
875,304
5,101
524,878
625,035
1,717,598
(1) Balances denominated in US dollars have been translated at the December 31, 2014 exchange rate of 0.862.
Seven Generations entered into agreements with Pembina Pipeline Corporation for firm transportation and processing services, of
which the above estimates for timing of payments are subject to completion of certain pipeline and facility upgrades by the
counterparty. The Company has an agreement with Aux Sable Canada LP and, separately, with Alliance Pipeline Ltd. to deliver up to
500 Mmcf/d of peak rich gas volumes by 2018. The natural gas agreements expire in 2022. Seven Generations also has take or pay
agreements in place for up to approximately 40,000 bbls/d of condensate and other NGLs production by 2017. The liquids
agreements expire in 2026. The minimum commitments under these agreements are reflected in the table above.
77
SEVEN GENERATIONS ANNUAL REPORT 2014
Effective August 27, 2014, the Company entered into an agreement to have a third party provide a 24-hour dedicated crew for
hydraulic fracturing. The agreement has an initial term of one year. The Company may terminate the agreement on less than
60 days notice and payment to the third party of an amount equal to $50,000 for each day less than 60 days that notice of the
termination is given.
23. DEFERRED CREDITS
Leasehold inducements were received in 2013 when the Company entered into a corporate office lease. These inducements are
recognized as a deferred liability and amortized over the term of the lease.
24. RELATED PARTY TRANSACTIONS
Key management personnel are comprised of all directors and officers of the Company. Excluding the Liquidity Event expense
disclosed in Note 18, the amounts recognized in the financial statements for transactions with key management personnel are
as follows:
Year ended December 31
Salaries, benefits and other short-term compensation
Stock based compensation
2014
6,276
9,538
15,814
2013
3,782
9,691
13,473
In November 2014, the Board of Directors approved a retention bonus plan for management and employees. The retention bonuses
will be payable in four equal installments payable every six months starting on May 5, 2015. Each installment payment will be
contingent upon the individual being employed by the Company on the date of payment. The maximum retention bonuses will be
$6 million, payable over the two-year period starting November 5, 2014. The allocation payments to key management for this
retention plan will be determined in 2015.
78
SEVEN GENERATIONS ANNUAL REPORT 2014 CORPORATE INFORMATION
MANAGEMENT
Pat Carlson
Chief Executive Officer
Marty Proctor
President and Chief Operating Officer
Harry Cupric
Chief Financial Officer
Randy Evanchuk
Executive Vice President
Steve Haysom
Senior Vice President
Susan Targett
Vice President, Land
Christopher Law
Vice President, Corporate Planning
Glen Nevokshonoff
Vice President, Development
Merlyn Spence
Vice President, Construction and Marketing
Barry Hucik
Vice President, Drilling
Randall Hnatuik
Vice President, Business Development
Kevin Johnston
Vice President, Accounting and Controller
DIRECTORS
Kent Jespersen
Chairman
Pat Carlson
Chief Executive Officer
Michael Kanovsky
Kevin Brown
Jeff van Steenbergen
Jeff Donahue
Kaush Rakhit
Dale Hohm
Bill McAdam
INVESTOR RELATIONS
Brian Newmarch
Manager Investor Relations
Christopher Law
Vice President, Corporate Planning
Email: investors@7genergy.com
Website: www.7genergy.com
TRUSTEE AND TRANSFER AGENT
Computershare Trust Company of Canada
600, 530 – 8th Avenue SW
Calgary, Alberta, T2P 3S8
BANKS
RBC Royal Bank of Canada
Credit Suisse AG, Toronto Branch
Bank of Montreal
Canadian Imperial Bank of Commerce
The Bank of Nova Scotia
The Toronto-Dominion Bank
Alberta Treasury Branches
Canadian Western Bank
National Bank of Canada
AUDITORS
Deloitte LLP
LEGAL COUNSEL
Stikeman Elliott LLP
INDEPENDENT EVALUATORS
McDaniel & Associates Consultants Ltd.
STOCK SYMBOL
VII
Toronto Stock Exchange
CORPORATE OFFICE
300, 140 – 8th Avenue SW, Calgary, Alberta, T2P 1B3
Telephone: (403) 718-0700
Fax: (403) 532-8020
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SEVEN GENERATIONS ANNUAL REPORT 2014 Seven Generations Energy Ltd. is an independent petroleum company focused on
the acquisition, development and value optimization of high quality tight and shale
hydrocarbon resource plays. Presently, the Company has a single focus area, the
Kakwa River Project, a large-scale, tight, liquids- rich natural gas property located in
the Kakwa area of northwest Alberta. 7G has a corporate headquarters in Calgary,
Alberta and an operations headquarters in Grande Prairie, Alberta. Seven Generations
shares are traded on the Toronto Stock Exchange under the symbol VII.
300, 140 – 8th Avenue SW, Calgary, AB T2P 1B3
T: (403) 718-0700 | E: info@7genergy.com | www.7genergy.com