Seven Generations Energy Ltd. Annual Report 2015

FY2015 Annual Report · Seven Generations Energy Ltd.
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2015

ANNUAL REPORT

2015 AT  
A GLANCE

Seven Generations Energy Ltd. is 
an independent, publicly-traded 
energy company focused on the 
acquisition, development and value 
optimization of high-quality, tight-
rock, natural gas resource plays. 

Seven Generations differentiates itself 
through its core attributes: the quality of 
its liquids-rich asset, large resource size, 
desirable location and market access, a 
high degree of operational control, proven 
and innovative technical execution and 
unique operating approaches.

We are committed to protecting the 
natural beauty of the environment and 
preserving its capacity for current and 
future generations. While we recognize 
that our activity and operations impact the 
air, water, land and natural life, we believe it 
is vital that we work with all our 
stakeholders to reduce and minimize our 
environmental impacts.

Our strategy

Financial Stability
Profitable growth to achieve positive free 
cash flow

Full-Cycle Profitability
Earning a return on capital employed 
across the entire commodity cycle

Stakeholder Interests
Recognizing that in a competitive world, 
only those who best serve their 
stakeholders can expect to survive in  
the long term

Innovation
Applying innovation and technology to 
remain among North America’s lowest 
supply cost unconventional gas developers

$415 million
26%

$23.72
per boe

FUNDS FROM OPERATIONS

OPERATING NETBACK  
AFTER HEDGING

Seven Generations trades on the Toronto 
Stock Exchange under the symbol VII.

Kakwa River Project 
ON THE COVERS: Kakwa River Project – Lator Plant

1

Table of Contents

2015 At A Glance ......................................................................IFC
CEO’s Message ............................................................................. 2
Code of Conduct ........................................................................15
President’s Message.................................................................16
Highlights Summary .................................................................20
Management’s Discussion and Analysis ..........................22
Independent Auditor’s Report ..............................................52
Consolidated Financial Statements...................................53
Notes to the Consolidated Financial Statements ........ 57
Reader Advisory ........................................................................78
Corporate Information ............................................................79

60,400 boe/d
94%

100 to 110
thousand boe/d

2015 PRODUCTION

2016 PRODUCTION  
FORECAST

Production Split

25%

40%

35%

Condensate
Natural Gas Liquids

Natural Gas

SEVEN GENERATIONS 2015 ANNUAL REPORT2

CEO’S 
MESSAGE

one in the spring through this annual report. With each 
report, I like to focus on business strategy. I like to leave 
reporting on operations and finance, except for the  
high level strategic implications, to my very capable 
colleagues who lead those functions in our leadership 
team – Marty Proctor, President and Chief Operating 
Officer and Chris Law, Chief Financial Officer. Just as  
my views are forged through my communication with 
shareholders, theirs are equally fashioned by their 
interactions with a variety of shareholder audiences. 

In this update I would like to describe the state of our 
evolving thinking on the following issues:

1. 

 Key elements of competition in the over-supplied 
North American gas market

2. 

 Challenges and opportunities to expand the market 
for our products – turning a red ocean blue

3. 

 7G’s resources in the context of the capacity of 
northwest Alberta and northeast British Columbia as 
a market supply region

4. 

 Evolving expectations for social license in our 
operating area

1.   Key elements of competition in  

the over-supplied North American  
gas market

I want to highlight some elements of the competitive 
environment that most profoundly affect our profitability 
and future potential. For those who have been following 
our story, some of this may be repetitive, but I hope to add 
new insights that contribute to an evolving vision for 
Seven Generations. 

North America natural gas – a textbook free market

The North American natural gas market is as close to a 
textbook free market as reality allows. Natural gas is 
largely an undifferentiated commodity. For most buyers, 
one unit of natural gas is the same as the next. The 
lowest price gets the market. There are many buyers and 
many sellers. Competition is efficient.

Pat Carlson,  
Chief Executive Officer

Let me start by thanking our shareholders for 
their continued investment support and for 
meeting with us, providing feedback that helps 
us mould and adapt our business strategy to 
remain competitive in North America’s evolving 
energy market. We feel privileged that our 
meeting schedules at investor conferences are 
generally full, that shareholders call or visit us at 
our offices and that our occasional investor field 
tours are filled with a variety of inquisitive 
guests. Investors’ thoughts, input and challenges 
to our thinking help us evolve our strategy. Their 
ideas and thinking help us serve all of our 
stakeholders in a differentiating way, consistent 
with our Level 1 Policy Statement, our Code of 
Conduct, which is on page 15 of this report.

The way things have evolved as a public company, I get 
about two chances per year to write to all shareholders 
about our strategy – one in the autumn after we 
announce our budget guidance for the coming year and 

SEVEN GENERATIONS 2015 ANNUAL REPORT3

Market access constraints

The ability of producers to get their products to market – 
market access – is defined by the availability of gathering, 
processing and pipeline capacity between the natural gas 
field and the consumer. For producers in northwest 
Alberta and northeast British Columbia, some market 
features have added a layer of complexity to their 
competitiveness. These include:

 Transcontinental pipelines that are in place to deliver 
natural gas from northwest Alberta and northeast 
British Columbia across most of Canada and into the 
U.S. markets along the West Coast and in the U.S. 
Midwest – the Chicago-area market;

 7G is under contract to Alliance Pipeline to ramp up 

delivery from the present 250 million cubic feet per day 
(MMcf/d) of liquids-rich natural gas to 500 MMcf/d of 
liquids-rich natural gas into the Chicago-area market by 
late 2018. We also have 107 MMcf/d of leaner natural gas 
contracted on the TransCanada pipeline system to start 
delivery in 2018. Eastbound pipelines out of northwest 
Alberta and northeast British Columbia have been fully 
contracted in recent months forcing those wishing to 
contribute natural gas supply to pay a premium to use 
space contracted to a third party or accept less-reliable 
transportation service that is interruptible. Liquids 
pipelines out of the region are also full, which means 
that liquids are being shuffled via truck to find available 
space on the regional gathering lines; and

 Some producers have contracted aspects of their 
gathering and processing to midstream service 
providers which may limit their ability to adjust rates or 
optimize costs. I will elaborate on the Canadian 
midstream model later.

New Canadian and Alberta governments – so far,  
so good

The 2015 Alberta and Canadian elections brought 
uncertainty at the provincial and federal levels. Uncertainty 
also exists, in some cases, as to the costs that may arise  
in connection to claims made, or rights asserted, by  
First Nations communities. This added element of risk is 
probably reflected in the cost of capital and the willingness 
of Canadian operators to invest in development. The Alberta 
government’s January announcement defining the basic 
structure of its royalty program provided producers with 
considerable comfort, particularly as a result of the stated 
desire to make returns equivalent in the present and new 
system, which takes effect in 2017. The new royalty formula 
will include a surrogate for well capital cost that more 
closely matches the industry’s actual track record and 
there are provisions to file special applications for 
experimental well designs. This is particularly encouraging 
for 7G because innovation is required to remain competitive 
and we believe we are among the industry leaders in well 
design innovation. 

Find a  
market niche – 
something that  
can be done and that 
most others are  
not focused on.

Get the  
best expertise – 
companies are  
built on ideas  
and know-how. 
People own that.

Diversify  
to increase risk 
tolerance with 
 respect to  
key risks.

Keep control  
of your products  
and your operations 
until you get a  
fungible product  
to an open market.

SEVEN GENERATIONS 2015 ANNUAL REPORT4

Canada’s new government has a strong focus on climate 
change, and Alberta’s government has already announced 
its greenhouse gas emission reduction program. A recent 
gathering of Canada’s prime minister and the nation’s 
premiers provides some comfort that the federal 
government will stand back and let provinces administer 
their own schemes, provided that they do implement a 
mechanism on carbon emissions within a mutually agreed 
upon range. The recent international agreement on climate 
change at the December 2015 conference in Paris gives 
hope to British Columbia and Alberta operators that 
competing developers in other natural gas producing 
jurisdictions will soon also bear a burden for carbon dioxide 
and methane emissions. If revenue-neutral greenhouse gas 
reduction programs are implemented and gradually 
escalated around the world, behavior aimed at emission 
reductions should be encouraged, end users will bear more 
of the real cost associated with the use of fossil fuels, 
projects will be burdened similarly for emissions from their 
production and the industry will be transitioned towards a 
more sustainable outlook. 

I look at it this way. As the energy industry, we are the 
start of a supply chain that provides consumers with 
many of the products that they need and want. Provided 
that climate change burdens are evenly applied, we will 
still be called upon to produce our products. The products 
with the least greenhouse gas emissions, from source to 
consumption, will gain an edge, and the industry will still 
be rewarded with returns for meeting consumer demand. 
Our challenge will be to deliver more valuable products to 
our customers per net tonne of carbon dioxide (CO2) 
equivalent emissions. With our modern production and 
processing facilities, our control over our operations, our 
high production rate and our high resource recovery 
natural gas wells, I believe we are well positioned to be a 
net winner as the global marketplace evolves to comply 
with the Paris agreement.

North America’s plentiful and competitive supply 
will continue to squeeze margins

Innovative competitors with very high quality assets and 
access to the traditional customers served by northwest 
Alberta and northeast British Columbia producers threaten 
to further flood our markets and put downward pressure 
on our profit margins. To help investors compare projects 
and natural gas plays, some energy market analysts 
publish comparisons of supply costs of various plays. 
Their research is calibrated to continental benchmark 
natural gas and oil prices – the price per million British 
thermal units (MMBtu) of natural gas at Henry Hub, 
Louisiana and the price for a barrel for West Texas 
Intermediate crude oil at Cushing, Oklahoma. Prices for 
various qualities of oil and natural gas at distinct locations 
across North America are based on several factors 
relative to the benchmark prices. They include the value of 
the commodity by specification, local supply and demand 
variations, plus the ability and cost to ship supplies 
between market locations. When analysts compare 
projects they often present a chart with bars for the array 
of projects that they analyze, with each play measured on 
a comparable set of criteria. These charts rank projects or 
plays according to the Henry Hub natural gas price that is 
required for the next unit of natural gas to be produced, 
provided that it meets the analyst’s economic threshold, 
such as a 15 percent before tax internal rate of return. 
These plays are often sorted from the lowest cost project 
on the left to the highest cost on the right. The resulting 
profile typically takes the shape of a boot and thus we call 
the presentation a “supply cost boot diagram”. This supply 
cost may also be called the threshold price or the 
breakeven price. This method of ranking projects by their 
competitiveness usually only includes the cost to add 
supply to an established project, not the full-cycle costs, 
which would also take into account processing and market 
access infrastructure, original cost of the resource, land 
costs, and sunk costs that were required for the developer 
to test and commercialize the play. On the next page is a 
typical boot diagram prepared by Credit Suisse in February 
2016, using an oil price of US$40 per barrel (bbl). 

“We recognize that the business environment for natural gas 
resource developers is rapidly evolving. Therefore it only makes sense 
that we adopt the notion that we must be nimble, cognizant of future 
possibilities, preserving of options, yet moving decisively and quickly 
to capture benefits for all of our stakeholders.”

SEVEN GENERATIONS 2015 ANNUAL REPORTNYMEX ($USD/MMBtu) Breakeven* Price by Play – $40/bbl oil price

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* Assumes a 15% IRR, US$40/bbl WTI, WTI less US$5/bbl for Edmonton Par, US$0.50/MMBtu AECO basis and FX of 0.75 (US$/C$). 
Source: Credit Suisse Equity Research – February 1, 2016.

You’ll see that our Nest 2 play in our Kakwa River Project, 
with a projected supply cost of US$1.95 per MMBtu, is 
ranked as having the best economics among 36 natural 
gas projects across North America that this particular 
analyst presented. These projects represent our core 
competitors. This supply cost boot diagram clearly 
illustrates our prime objective: stay at the toe of the boot. 

When oil prices fall significantly, as they have in the past  
22 months, our comparative economic advantage to other 
plays is eroded. For us, condensate is a valuable product 
because it is priced similar to oil and condensate is about  
35 percent of our production by energy equivalence. It 
generates a large proportion of our revenue – more or less 
depending upon oil prices. In this market backdrop, we remain 
ranked as the most competitive, but our lead is diminished.

Credit Suisse also produced a boot diagram in August of 
2015 based on an oil price of US$60/bbl, which is on  
page 6. In the $40 oil chart that is above, the breakeven 
price for the lowest cost projects, including 7G’s Montney 
Nest 2 Condensate Rich Gas, is much higher – US$1.95 per 
MMBtu. The difference in price relative to the next best 
projects is less pronounced, 8 cents compared to  
26 cents when the oil price is $60/bbl. 

In an open market, like the North American natural gas 
market is, the market sets a price at which demand is just 
met at the breakeven price of the most expensive supply 
needed. Because the owners of the lowest cost supplies 
may not be willing or able to supply the entire market 
need, some natural gas projects that have higher than the 
lowest breakeven price will be called upon to supply 
natural gas. To continue to develop in the economic 
environment described in the conditions illustrated in the 
boot diagram, a project needs to be nearer to the toe of 
the boot than the project that barely meets the 
profitability criteria that the analyst has used. 

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NYMEX ($USD/MMBtu) Breakeven* Price by Play – $60/bbl oil price

7G Nest 2

7G Nest 1

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*Assumes a 15% IRR, US$60/bbl WTI, WTI less US$5/bbl for Edmonton Par, US$0.50/MMBtu AECO basis and FX of 0.80 (US$/C$) 
Source: Credit Suisse Equity Research – August 10, 2015.

Our target has always been to possess a project among 
those at the toe of the boot and to have a considerable 
margin on the most threatening alternatives. Some of the 
concerns that are brought to light upon comparative 
examination of these two charts are:

 The reduction in drilling for oil targets due to collapsed 
oil prices. Innovation and efficiency measures, like the 
ones being implemented by 7G, are being applied across 
the natural gas industry. This has resulted in improved 
productivity and recovery per well and lower costs.

 The projects with the lowest breakeven price are mostly 

liquids-rich natural gas projects. The profitability of 
liquids-rich natural gas projects are strongly affected by 
the price of oil because some of the liquids produced are 
priced in the oil market. That is not to say that the oil 
price is the only change in Credit Suisse’s two analyses, 
but the first chart shows five projects with a breakeven 
price of less than US$2.25 per MMBtu while the second 
chart shows seven. I believe that two factors likely 
contribute to this shift in supply cost.

First, the overall cost of natural gas is coming down. We 
attribute this economy, in part, to reduced upstream 
goods and services costs because of a downturn in 
industry activity. Despite modest growth in North 
American natural gas demand over recent years, the very 
recent downturn in activity has resulted from two events:

 The need for fewer natural gas wells to satiate decline 
replacement and the modest growth in demand in the 
natural gas market; and

Second, the extra revenue that the most liquids-rich 
natural gas projects receive does not provide as much 
differential to the breakeven price when oil prices are low. 
In fact, there were times in the summer of 2015 when a 
portion of Alberta propane was selling at a negative price. 
That means some Alberta producers were having to pay 
people to take their propane volumes. While not great, we 
were fortunate. Propane pricing at the Conway, Kansas 
benchmark, which is the price we receive for our volumes 
extracted at Aux Sable in Illinois, continued to trade last 
summer in the range of US$10 to US$15 per bbl. In both 
markets, the natural gas liquids (NGLs) production growth 
has shown that it can outpace North American demand, 
which can result in it becoming a by-product that, at 
times, costs producers money to get to market. 

The Supply Cost Sensitivities diagram on the following 
page shows a graph of two of 7G’s development areas: 

 Nest 2 (yellow line) is very rich in liquids and we are 

undertaking what we believe to be commercial 
development of one of the continent’s lowest supply 
cost natural gas resources. It achieves a 20 percent 
internal rate of return at prices as low as oil at US$30 

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7

per bbl and US$2.20 per MMBtu. Keep in mind that 
supply cost is not the total cost; it is just the cost to 
add wells to maintain production; and

natural gas production is that the producer must find a 
market for all of the resulting products:

 Condensate – the best market currently is the Canadian 

 Deep Southwest (green line) has leaner natural gas that 

we are still testing and have not yet started to 
experiment with well designs and development methods. 
To achieve a 20 percent internal rate of return, by our 
estimate from what we have learned to date, we require 
a natural gas price of US$4.25 per MMBtu when oil is 
priced at US$30 per bbl. We are not drilling and 
completing wells in the Deep Southwest, but if we can 
apply our most recent innovations and efficiencies, we 
would expect to achieve much improved breakeven prices 
and increase the potential for commercial development.

oil sands

 Butane – a finite amount is useful to refiners and 

petrochemical manufacturers

 Propane – limited markets exist for this as a 

petrochemical feedstock and as a portable fuel for use 
in locations that are not served by natural gas

 Ethane – a highly valued petrochemical feedstock that is 
grossly oversupplied such that it is largely used as a 
supplement to methane in natural gas fuel

The slope of the supply cost sensitivities curve for each 
area suggests the high degree of sensitivity of breakeven 
price to liquids content. Of course that sensitivity 
evaporates if the liquids market is so oversupplied that 
NGLs are essentially given away. A fact of liquids-rich 

At the rate we produce these commodities, storage for any 
extended period of time is impractical. We must sell all of 
them in order to sell any of them, and at times the market 
for some products disappears in the wash of oversupply.

Supply Cost Sensitivities: Price required for 20% IRR
(pre-tax, management type curves, half-cycle)

)

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$6.00

$5.50

$5.00

$4.50

$4.00

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$0.00

Deep Southwest* (future development)
* Unchanged from 2014 IPO Prospectus

Nest 2 (current development)

$30

$35

$40

$45

$50

$55

$60

$65

$70

$75

$80

$85

$90

$95

$100

WTI (USD $/bbl)

Assumptions:

Sliding scale for WTI & FX; $30 US/bbl WTI @ 0.70 CAD/USD FX to $100/bbl WTI @ 0.90 CAD/USD FX. NGLs as % of WTI: C3 35%, C4 50%, Alberta C5+ 
93%. Chicago gas discount $0.01 to NYMEX HH. Unit transportation costs: sales gas $1.00/Mcf. Recovered liquids: $5.80/bbl.

Nest 2: Average opex (first 3 years) $3.88, ~$6.8MM natural gas deep drilling credit pool for 2450m lateral. 15% raw gas shrink.

Deep Southwest: Average opex (first 3 years) $6.12/boe, ~$7.7MM natural gas deep drilling credit pool for 2200m lateral. 15% raw gas shrink.

Half-cycle economics: include only the cost to drill, complete, tie & equip a well. No costs for central processing, regional gathering, condensate 
stabilization, other infrastructure, land acquisition, corporate overheard (G&A), financing or corporate taxes are included. Drill, Complete, Tie-in Costs; 
Nest 2: $12.0MM, Deep Southwest: $14.0MM.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
8

Facing continental competition

Probably the most threatening competitive alternative to our 
Kakwa Nest natural gas is Utica and Marcellus natural gas 
because of its close proximity to the Chicago market. In the 
US$60/bbl boot chart, 7G’s Montney Nest 2 has a clear 
supply cost advantage as do a few other Montney areas. 
Collectively, we may be able to satiate the market such that 
there is little motivation for the Utica and Marcellus 
producers to push into and compete in the Chicago market. 
However, the other boot diagram suggests that when the 
price is US$40/bbl, we have only a few cents per MMBtu 
advantage over our closest rivals, including other Canadian 
supplies, and the lowest cost Utica and Marcellus supply. We 
have a very high quality resource base and we believe that 
we are among the leaders in innovation. Therefore, we are 
likely on track to be able to capture, with prudent 
management of experimental investments aimed at 
improving well economics, the most value from our resource. 
As others optimize their development methods, there is a 
strong probability that the bars closest to the toe of the boot 
will become less differentiated. No matter what quality or 
technology advantages we and other northwest Alberta and 
northeast British Columbia developers may possess at low 
prices, the transportation costs related to the long distance 
from the market becomes the largest portion of our cost, and 
enables an advantage for supplies closer to the market.

In the final analysis, as the market sorts through various 
supplies of natural gas, we may find ourselves among a few 
profitable suppliers, but with little margin for superior returns 
unless we can find new ways to add value to our product. 
These observations point to the need to continue to innovate 
and to seek operating efficiencies in order to reduce our 
breakeven price so that we can maintain a superior operating 
margin. They also suggest that, as we consider marketing 
our growth potential, we should look for ways to expand the 
market away from the grossly oversupplied regions that are 
nearer to our competitors in Ohio, Pennsylvania and Texas. 

Midstream processor service models – help or hinder

We support the continued renaissance in Canadian 
midstream service business models. Traditional midstream 
service models may significantly impair the 
competitiveness of Canadian natural gas projects when 
those producers enter into longer-term service 
agreements with midstream natural gas processors and/or 
shippers. Two experiences highlighted to me the need to 
reconsider the midstream service model as it is currently 
presented to Canadian producers. 

First, I spent the better part of a day with an industry 
analyst. She’s really a commodity price expert that I  
hold in very high regard for her insights upon the 
macroeconomic environment for the oil and natural gas 
industry. She indicated to me that market circumstances 
strongly favour vertically integrated companies. This left 
her to speculate that, if the present market prevails for a 
few more months, we should expect to see a wave of 

industry consolidation by the integrated companies – 
which own and operate their assets from the reservoir to 
the commodity markets. Some of the vertically integrated 
companies have better access to capital, the desire to 
own and control large, high-quality assets and have the 
financial and international operating ability to back the 
huge infrastructure investments that would be required to 
open up new markets in power generation, petrochemical 
manufacturing and Liquefied Natural Gas (LNG) exports off 
Canada’s West Coast. 

My second experience has come via a wave of distressed 
businesses. In the past few months, as oil prices have 
collapsed, we have been invited to make proposals to acquire 
some of the smaller liquids-rich natural gas projects, and 
even a few larger ones. In most cases, the assets are offered 
for sale in a distressed economic situation. In most of the 
cases that we have reviewed, the operators have contracted 
aspects of their field gathering and processing to midstream 
service providers. In the highly competitive, over-supplied 
market environment, where just a few cents per MMBtu 
determine whether a project is profitable or unprofitable, 
developable or not developable, able to attract capital or not 
able to attract capital, developers cannot afford some of the 
fees and conditions that we believe often go along with the 
use of midstream service providers. The table on the 
following page illustrates common elements of the Canadian 
midstream service model that can put the upstream operator 
at a disadvantage relative to a vertically integrated company 
that owns its own midstream and transportation assets.

It is important to note that this list does not apply to all 
midstream arrangements. In fact, it is possible that the 
entire list applies to none, but multiple elements of the list 
are common. 7G’s reaction to the observations in the 
following table has been to establish an expert midstream 
group within the Company. We have supplemented the 
upstream and marketing expertise of Senior Vice President 
Marketing, Merle Spence with two former midstream/
petrochemical executives, including, as recently 
announced, Charlotte Raggett, our Vice President 
Midstream Business Development, and a senior marketing 
expert. Our team has developed a proposed midstream 
service model that, if and when it gets take-up by the 
existing midstream business, will combine the strengths of 
credit ratings, balance sheets and access to vast amounts 
of low-cost capital of the healthiest midstreamers with 
highest quality upstream resources.

Many recently announced energy infrastructure 
arrangements are already departing from the traditional 
model, providing a greater ability for the upstream 
developer to adapt to market circumstances and access 
new markets more effectively. The new model provides a 
more sustainable economic balance of the risk/reward and 
value equation, giving all participants more financial 
resilience to endure the increasing competitive forces 
faced by Canada’s natural gas sector, and is a better fit 
with 7G’s integrated development plans.

SEVEN GENERATIONS 2015 ANNUAL REPORT9

The traditional midstream model historically served a very 
valuable purpose. It enabled very small explorers and 
producers to secure midstream expertise and 
infrastructure that their projects were too small or 
geographically dispersed to support. With the shale gas 
revolution, though, many projects are large enough to 
support their own gathering and processing infrastructure. 
Many, on their own, or in cooperation with just a few 
others, can support major transcontinental shipping and 
marketing initiatives. The Alliance Pipeline and Aux Sable 
processing facilities are a previous example of a producer-
driven market expansion project. 

Well financed and very large developers are faced with the 
option of vertically integrating to achieve the advantages 
described in the “vertically integrated” column below.  
A hybrid model might provide essentially all of the 
advantages of being vertically integrated to one or more 

major anchor tenant developers, while a midstream partner 
could provide a share of the capacity to developers 
desirous of small amounts of capacity. Financing of the 
anchor tenant’s share could be through the midstream, or 
on a rent-to-own basis, or through direct financing. 

For resource plays, such as very large tight-gas 
developments, in the final analysis, the value that 
underpins the infrastructure investment is the upstream 
asset – the oil and natural gas reserves. The nature of 
upstream assets has changed. Risks associated with the 
infill development of a very large, delineated resource are 
much lower than the risks associated with the historic oil 
and gas exploration and production business. For large 
projects, there is a compelling argument for a much lower 
cost of capital for financing or infrastructure 
developments that support one, or a few, very large, 
well-advanced projects.

An upstream producer’s view of the Canadian midstream/downstream business model

Developer’s value consideration

Vertically integrated

Canadian midstream model

What is the nominal cost of capital  
to producer?

Varies – but single digit interest rates  
have been achieved by developers  
with strong balance sheets and strong  
value propositions.

>9% interest on actual capital cost.  
Some interest rates may appear lower 
because higher than either actual or market 
capital cost is ascribed

How is risk managed?
Who benefits from capital 
efficiencies that are gained?

Owner optimizes facility engineering and 
construction, taking reasonable risks to 
minimize cost. Upsides from excess capacity 
and debottlenecking are captured for the 
owner’s benefit.

Midstreamer designs conservatively, over- 
estimates and over-pays to ensure plant 
capacity and schedule targets are met. Fees 
on design rate cover midstreamer’s capital plus 
interest. Excess processing capacity goes to 
midstreamer to contract to third parties.

What product specifications are 
used at delivery points?

The specifications are optimized along the 
system to maximize value and minimize cost, 
and can change as suits the owner.

What happens when producer 
desires a change in delivered 
volumes?

System is expeditiously adjusted to maximize 
value. Third party volumes may be processed 
to add revenue where excess capacity is 
available.

Financial security

Balance sheet asset. Third party financial 
institutions have access to all of developer’s 
assets. 

Customer service

Owner is a customer.

Specifications are often set to over-process 
in the field to eliminate any cost/risk to 
midstreamer and/or penalize producer for 
off-specification product. Product quality is 
physically downgraded by mixing during shipping 
requiring reprocessing. Extra or unnecessary 
field processing is at developer’s expense.

Expansions typically take 1 to 4 years. 
Producer often pays take-or-pay penalty on 
reduction of deliveries. Midstreamer deploys 
extra capacity for its own benefit. Producer 
often cannot assign partial contract to a 
third party.

Letter of credit, drag on credit capacity of 
producer, possibly land dedication also.
Third party backers for large projects have 
indirect access to developer’s resources, 
direct access to midstreamer’s assets.

Service marketing and operations 
departments are often silos. Midstreamer 
is advantaged to minimize cost which is 
reflected in service.

Contribution to industry reputation/ 
social license

Fully owned, fully aligned. Part of community 
engagement by developer.

Focus most often on provincial or national 
scale. Regional engagement can be lost.

Ability to capture premium for 
founding sponsorship

Inherently captured.

All to midstreamer.

SEVEN GENERATIONS 2015 ANNUAL REPORT10

2.   Challenges and opportunities to expand 
the market for our products – turning a 
red ocean blue

A management textbook that I have found to be very useful is 
Blue Ocean Strategy, by Renée Mauborgne and W. Chan Kim, 
published by Harvard Business Review in 2005. As the 
authors’ website describes, the behaviour that they define as 
blue ocean strategy is “the simultaneous pursuit of 
differentiation and low cost to open up a new market space 
and create new demand.” They contrast Blue Ocean Strategy 
with the more common Red Ocean Strategy, which involves 
going head-to-head with competitors in the same markets, 
using, more or less, the same strategies to, almost hopelessly, 
seek differentiating margins. The founders of the Alliance 
Pipeline and the Aux Sable fractionation plant in Chicago had 
what I would interpret to be a Blue Ocean strategy – build a 
special pipeline to keep liquids in natural gas that normal 
pipelines would require removing, ship the liquids-rich natural 
gas to a point near the market and separate the natural gas 
into products adjacent to the markets. In the broader sense, 
perhaps an extension of the concept, our use of specially 
designed plants to deliver into the Alliance pipeline is a Blue 
Ocean Strategy. We use Super Pads that have the capacity to 
accommodate a large number of wells, perhaps more than 50, 
which are drilled and added to the Super Pad facility over time. 
The Super Pad reduces several common problems:

 It provides lean natural gas that can be used for gas lift 
to effectively blow the inflowing liquids up the well to 
the surface;

 It enables removal of water that is naturally produced 
with the natural gas so that the tendency for the 
gathering system to become plugged with hydrates –  
a special type of ice formed from methane and water –  
is reduced;

 It prevents liquid slugs and facilitates a more effective 
flow of liquids and gases to central processing plants, 
achieving improved throughput efficiency of the central 
plants and reduced safety and operating capacity 
reduction risks; and

 It enables the control, over a broad range, of the 

downhole producing pressure of natural gas wells, which 
facilitates a process known as “slowback” a restricted 
flow rate that seems to increase condensate recovery.

Driving for innovation and efficiency

There are fundamentally two ways to compete:

 Do the same things as competitors but in a more 

effective and efficient way; and

 Innovate to find and do different things than 
competitors in broadly the same business.

The boundaries between these two types of activity are 
often blurred and stopping to classify is probably not as 
good of a use of time as continuing to drive for both 
efficiency and innovation. I think organizations are most 
effective when they have champions for both methods of 
competing. We compete both ways. We have two 
champions. We recruited our President and Chief Operating 
Officer, Marty Proctor, partly because he is very proficient 
in operational effectiveness, while I naturally focus on 
innovation. Under Marty’s leadership, our costs have 
dropped and our safety incident frequency has dropped. 
Our activity level climbed at first, then subsided as we are 
now getting more done with less wells. Meanwhile, my 
focus has been to encourage the team to try new well and 
facility designs, and their success has contributed to our 
success. Marty has a more balanced ability in both 
functions than I have. But I think, as a team, we are better 
than two of either of us would be.

Pursuing new, blue markets

We are looking to find new markets for our natural gas to 
add to our existing liquids-rich natural gas market in 
Chicago and new markets for our natural gas liquids to add 
to our Edmonton-centred Alberta markets. These are red 
ocean markets, where the aggressive competition by 
competitors with similar strategies brings to mind bloody 
waters of a shark feeding frenzy. We can and we are 
competing in the red oceans of these markets. But Blue 
Ocean Strategy has me convinced that new markets, 
markets where our very large, very high-quality resource is 
essentially required to underpin major investments, can 
offer us growth potential where we can achieve 
differentiated netbacks. Here are some of things that we 
are looking at:

Short- to medium-term possibilities could include:

 Manufacturing petrochemical products from our 

resources, possibly with participation in an Alberta 
Government incentive program;

 Given that the Alberta government is planning to phase 
out coal-fired electricity generation, creating a market 
that is highly efficient and miserly as to greenhouse gas 
emissions through the development of natural gas 
combined cycle electrical power generation; and

 LNG and/or Liquefied Petroleum Gas (LPG) export from 
North America’s West Coast, where the relatively short 
distances to northern Asia and the cooler temperatures 
present the prospect of creating a supply at the toe of 
the supply cost boot for the Asian market, primarily 
China, Japan, Korea, India and Malaysia. This would 
require the development of a liquids-rich natural gas 
pipeline, and fractionation and liquefaction facilities on 
the West Coast.

SEVEN GENERATIONS 2015 ANNUAL REPORT11

Longer term possibilities could include any of the above 
plus providing solvents for the recovery of heavy oil and 
oil sands. I have long been very positive about the 
prospects of solvent-based or solvent-augmented 
recovery of heavy oil. With the greenhouse gas emission 
program that the Alberta Government recently announced, 
I think there is increased motivation for heavier oil 
producers to look at the combined enhanced recovery and 
in-situ de-asphalting potential of NGL solvents directly or 
as an additive to steam. 

How do we think that we can get this market expansion 
initiative done? We have started to assemble industry-
leading expertise internally and we will also entertain very 
synergistic relationships with partners. In either case, we 
will stick to strategies that I have found essential to 
success in the four start-ups that I have founded in my 
career. Before 7G, there was: 

 Passage Energy – heavy oil by cold production  

and waterflood;

 Krang Energy – heavy oil by cold production and 

horizontal well primary production, marginal natural gas 
production including well designs for dewatering, and 
light oil waterflood; and

 North American Oil Sands – oil sands via modularized 

steam-assisted gravity drainage (SAGD).

In each company, success was built on four strategies 
that I stick to:

1.  Find a market niche – something that can be done and 

that most others are not focused on. My three previous 
companies all focused on tackling recovery risk, not 
discovery risk, which was where most oil and natural 
gas companies and most sector investors were focused 
during the lives of those three companies. It is worth 
noting that 7G’s well and facility designs are an 
extension of reducing recovery risk and cost. As we 
started 7G, the prevalent trend was to drill short laterals 
and use central plants for processing. We were among 
the first companies to focus on liquids-rich natural gas 
and we did it at a time when industry pioneers were 
focused on high grading to the highest quality lean 
natural gas resources. 

2. Get the best expertise. Companies are built on ideas and 
know-how. People own that. Companies do not. I was at 
an integrated major oil company in the 1980s when the 
president called a staff meeting and told us that the 
days when an oil company hired a university graduate 
and essentially promised him or her a job for life were 
over. He said companies would focus on employing the 
best available skills that they required at that time. 
Going forward, he said that company intended to hire, 
train and release staff as the corporate need dictated. 
That was a trend among the big companies then, but 
they failed to consider that loyalty is a tide that ebbs 

and flows. Today’s workforce is highly mobile.  
Big companies are excellent training grounds,  
little companies offer an exciting, stimulating work 
environment with an opportunity to share in  
financial success. All of my companies have included 
resumes from among the industry’s leaders in their 
respective fields. 

3. Diversify to increase risk tolerance with respect to key 

risks. At Passage, we had four core properties using two 
recovery technologies, in two provincial jurisdictions. At 
Krang, despite being tiny, we had three business units 
focused on three areas of enhanced recovery: heavy oil 
by cold production and horizontal well primary 
production, marginal natural gas production including 
well designs for dewatering, and light oil waterflood. At 
North American Oil Sands, we had several different 
SAGD development areas. We reduced the risk 
associated with building permanent facilities over 
reservoirs that might prove to be sub-optimal by 
designing the plant to be modular and easily moved. At 
7G, our liquids-rich natural gas simultaneously provides 
condensate, natural gas liquids and natural gas. We have 
multiple lands, multiple reservoir zones and unique 
facility designs to produce all products effectively.

4. Keep control of your products and your operations until 
you get a fungible product to an open market. Most of 
Passage’s heavy oil could be trucked to multiple 
receiving points depending on which receiver was 
offering the best value. At Krang, the heavy oil situation 
was the same, but we also had a couple of dozen 
natural gas wells tied into a variety of gathering 
systems with a preference for midstreamers providing 
services to multiple customers, rather than competitor-
owned gathering and processing. At North American, we 
planned an upgrader that would make a fungible 
synthetic crude product. These companies did not have 
partners, except North American, where eventually the 
partner vended its interest into the company for shares. 

Capturing value throughout the chain, seeking 
vision alignment with potential partners

Our most pressing challenge may be breaking into new 
markets with no tolerance for inflexibility or excessive 
profit taking or any inefficiency by others in the value 
chain. In the case of LNG, we need to win the competition 
with the vertically integrated companies that intend to get 
their own natural gas to the Pacific market. We and our 
value chain partners must be efficient, nimble and aligned 
with a focus on generating superior returns from our 
investments throughout the value chain. We must present 
the Asian market with the lowest cost incremental supply 
of LNG and LPG, which is the refined derivatives of natural 
gas liquids. Partners offer many advantages, such as less 
capital required, access to the partner’s specialized 
expertise and the partner’s market network. In the final 
analysis though, partners need to bring clear value 

SEVEN GENERATIONS 2015 ANNUAL REPORT12

because the list of risks and burdens that they bring is at 
least as long as the list of assets. We are actively looking 
for partners willing to align with us in this kind of a vision. 
Our goal is to create a vertical alliance that has the 
advantages of a vertically integrated company and the 
nimbleness of a highly focused, early stage, sector leader 
through every link of the value chain.

Our very large resource base and the quality of our large 
inventory allows us to take on risks associated with the 
earliest stages of planning for enhanced market projects. 
We don’t want to dedicate all of our resources to a single 
market. Diversification reduces overall risk. On the other 
hand, the more parties contributing to a vision the harder 
it is to accomplish goals in a reasonable time. Further, we 
think that it is unlikely that, when it comes to liquids-rich 
natural gas, we will find a prospective upstream partner 
with anywhere near the asset size and quality 
combination that we have. Thus, bringing in an upstream 
partner at a conceptual planning and feasibility stage is 
likely counter-productive. Even though working quickly 
alone with downstream and midstream partners will be 
our preference, we still want a portfolio of markets. 
Therefore, it is likely that in some cases we will have to 
source natural gas currently owned by others once the 
commercial plan is in place. We can do this through 
mergers and acquisitions or through partnerships, 
whichever serves our shareholders best. One principle is 
clear though, we would need a superior arrangement to 
take the initiative and the up-front risks.

So the foregoing articulates our vision for the 
simultaneous pursuit of differentiation and low cost supply 
that can open up new market space and create new 
demand. As we pursue Blue Oceans, we intend to continue 
to compete to win and to grow in existing markets, just as 
we have done to date.

3.   7G’s resources in the context of the 
capacity of northwest Alberta and 
northeast British Columbia as a  
market supply region

As the break-even price boot diagrams that we have 
presented show, at least part of our resource is very  
high quality. There is also a lot of it. Proved plus Probable 
Reserve estimates are limited by the market that the 
evaluator believes to be reasonably captured over the  
next ten years. The category Best Estimate Contingent 
resources is used to describe, among other contingencies, 
resources that meet all the criteria to be Proved plus 
Probable reserves, but the owner has insufficient  
market access arranged within the forthcoming ten-year 
window. We have Proved plus Probable Reserves that 
reflect our contracted market access for ten years and a 
similar volume of Best Estimate Contingent Resources. 
There is much remaining to do before we have drilled and 
produced enough wells throughout our land base such 
that our evaluators can confidently classify the portions 

of our land base into the Reserves or Contingent 
Resources categories. 

This situation creates a classic chicken-and-egg problem. 
We have to have the market in order to get the 
classification Reserves and we have to have the Reserves 
in order to provide stakeholders with confidence that we 
will be able to support new market access projects that 
often are financed on a lifespan of 15 years, and perhaps as 
long as 25 or 30 years. Our initial public offering prospectus, 
published in October 2014, showed that we have future 
development areas that, if developed today, would have a 
higher break-even price than the Nest area where our 
capital is now focused. If, when we can devote capital to 
their commercialization, we find that they will not 
competitively fill any infrastructure that we plan to develop, 
we will need to arrange for other supplies of natural gas, 
developed through commercial arrangements, to fill that 
infrastructure. In any case, we would expect to greatly 
advance commercialization work on our lands outside of the 
Nest so that we have a better understanding of our own 
resources well in advance of making major commitments on 
market access infrastructure. 

The resource potential in northwest Alberta and northeast 
British Columbia represents decades of supply. Therefore, 
we would expect markets to be over supplied for years to 
come. Canada’s National Energy Board reports that the 
Montney Formation, which underlies a land mass roughly 
the size of Nova Scotia and New Brunswick combined, 
holds about 449 trillion cubic feet (Tcf) of marketable 
natural gas, which represents 140 years of supply at 
Canada’s 2013 consumption rate of 3.2 Tcf per year. The 
Alberta Energy Regulator estimates that Alberta has an 
endowment of 3,424 Tcf of natural gas in its shale and 
siltstone reservoirs. Not all of that is economic, but it is 
evident that Western Canada has sufficient large 
resources to underpin market expansion projects:  
Red Ocean or Blue Ocean. 

4.   Evolving expectations for social license 

in our operating area

A First Nations advisor with a previous company told me a 
story that strongly influenced my business philosophy. 
She said that when Europeans first sailed up the St. 
Lawrence River they encountered the highly organized 
Iroquois society. Although the Iroquois did not have a 
written language, they had passed down for many 
generations a constitution that, among other provisions, 
required that decisions be made to the benefit of seven 
generations into the future. In 1988, the United Nations’ 
Brundtland Commission published Our Common Future. It 
defined the concept of sustainable development, which is 
development that meets the needs of the present 
generation without compromising the ability of future 
generations to meet their own needs. Essentially the 
United Nations came to the same code of human conduct 
with respect to the environment that the Iroquois 
honoured as much as a millennium earlier. I asked my 

SEVEN GENERATIONS 2015 ANNUAL REPORTfriend’s permission to use Seven Generations as the name 
of my next company. Our name is meant to honour that 
concept and the original North Americans who founded it. 

Our Level 1 Policy statement, or Code of Conduct, 
describes our mission: to differentiate in the service of our 
stakeholders and our values, the need to act in a way that 
honours our name and our Level 1 Policy. Together this 
mission and these values figuratively form a sturdy flag 
pole from which the flag of Seven Generations Energy’s 
vision flies. 

We recognize that the business environment for natural 
gas resource developers is rapidly evolving. Therefore it 
only makes sense that we adopt the vision that we must 
be nimble, cognizant of future possibilities, preserving of 
options, yet moving decisively and quickly to capture 
benefits for all of our stakeholders.

13

Our stakeholders expect us to act in harmony with the 
biophysical environment, preserving its capacity to 
recover as various phases of our operations mature and 
wind down. They also trust us with Alberta’s resources. 
They want us to bring opportunity and prosperity to their 
communities, to the First Nations communities with 
traditional rights in the areas where we work, to our 
suppliers, our partners and customers, our contractors, 
our employees and our shareholders. They want us to 
obey laws and regulations. They want us to work with 
government and regulators to find ways to change the 
regulatory environment to make our industry more 
effective in serving stakeholders.

I believe the days of comprehensive regulation and 
attentive regulatory oversight of industry activity are  
near an end. Regulators don’t have and can’t afford the 
staff to write and enforce regulations that anticipate 
every responsible course of action for activity. Instead,  
I believe we will see a trend to higher level regulation,  
with strong license for those who are responsible to  
their stakeholders, largely a list similar to those listed in 
our Level 1 Policy. Others who prove themselves in  
need of direction will face cumbersome and slow 
bureaucratic processes. 

In service to the government, our company loaned my 
services, under appropriate confidentiality obligations, to 
the Royalty Review Panel as a member of the Natural Gas 
Expert Group. Meanwhile our Chief Financial Officer Chris 
Law conducted an extensive information campaign 
providing 7G’s views on royalties to our employees, the 
Grande Prairie community as well as our vendors and 
contractors, encouraging them to participate in the Panel’s 
website set up to encourage public contribution to the 
dialogue. We invite regulators and government officials on 
tours, generally several times a year, so that they can 
learn about tight, deep-basin, over-pressured mixed 
hydrocarbon resource plays. The first-hand knowledge 
they gain will help contribute to the development of policy 
that might lead to our industry better serving the public. 
We have provided engineering and geology courses for 
regulator staff, explaining basic differences between 
conventional reservoirs and unconventional reservoirs, 
such as the Montney.

We work hard to get stakeholder input on our plans and to 
communicate them broadly to our stakeholders. We work 
hard to engage our stakeholders who want to actively 
participate in the Kakwa River Project. We take guidance 
on environmental protection from our name and our Level 1 
Policy and we have undertaken initiatives that far exceed 
applicable regulations, outlined on the following page.

SEVEN GENERATIONS 2015 ANNUAL REPORT14

Fresh water conservation

Seismic activity

We have studied and compared regional water needs for 
hydraulic fracturing and have compared these water 
needs to the carrying capacity of the local surface water 
drainage system. As a result, we have derived general 
guidelines for our own surface water use. Our findings 
have been shared with a public body concerned with 
water resource protection in which we actively 
participate. In addition, we are examining and testing the 
geological column in search of deep aquifers that may 
meet our needs as both a source of water and a safe zone 
to dispose of produced water. We are also examining water 
recycling, from three points of attack: water recycling 
logistics, the impact of various aspects of water quality on 
well performance and water recycling technologies.

Habitat conservation

We are pushing the length or our horizontal laterals and the 
lateral distance of the vertical portion of our wells.  
Our wells are reaching further and further from our Super 
Pads to tap more reservoir and cause less surface land 
disturbance. Pushing both of these limits with our drilling 
and completions designs has enabled us to access about 
2,500 acres of reservoir using a well pad of about 20 acres 
in size, which means our pads cover less than one percent 
of the surface covering the reservoir we harvest. Looking 
ahead, we hope to further extend the drained area relative 
to the size of the disturbed area, as we advance well 
construction technologies. This, we believe, will enable us  
to develop and operate without extirpating key species. 
Wildlife are left to thrive in the undisturbed forest between 
our operations, and to quickly and spontaneously repopulate 
our development areas as we withdraw, first to a relatively 
quiet production operation and then, ultimately, to 
abandonment and reclamation.

Greenhouse gas emissions

We have modern natural gas production facilities that use 
air pressurized pneumatic controls, not methane gas. We 
are working with an environmental compromise, using inert 
nitrogen foam as a fracture fluid, which requires 
preliminary flaring of natural gas from the completed well 
to remove the nitrogen from early flow back natural gas 
from the reservoir. Alternatively, we also can use 
predominantly water as the fracturing fluid, which uses six 
times as much water, but results in little to no flaring. We 
are working to find an improved well completions method 
that provides both benefits, and neither compromise.

We can only produce the Montney formation at commercial 
rates if we hydraulic fracture the rock in the reservoir. 
When we hydraulic fracture we are breaking a small 
interval of the Earth’s crust. In some cases that interval of 
the Earth’s crust is still feeling some of the force that it 
was exposed to more than 50 million years ago when the 
Pacific tectonic plate slowly slid under the North American 
plate causing the rippling and tearing – the natural faulting 
and fracturing – that built and shaped the Rocky 
Mountains. When we break the Montney formation we can 
allow the Earth to release some of that force. When the 
Earth’s crust trembles from breaking the Montney 
formation directly from the hydraulic fracture, or directly 
plus the indirect effects of the relieving natural stress, we 
expect to cause seismic activity. Seismic activity simply 
means shaking of the Earth. Many human activities, such 
as road building, hydro-electric dam and large project 
construction and passing trains, shake the Earth. When 
we discuss this matter with our stakeholders, we find 
they are almost exclusively concerned with seismic 
activity so severe that it leads to damage to property or 
the biophysical environment. We have not experienced, nor 
do we believe that our project will cause, that kind of 
seismic activity. However, to be fully informed on the 
potential impacts, we have voluntarily installed an array of 
geophones that we are monitoring for seismic activity 
from our operations. 

While our list of things to do that differentiate us in the 
eyes of our stakeholders, things above and beyond mere 
compliance, continues to grow, the demands of our Level 1 
Policy Statement are on the minds of all of our employees 
in the decisions that we make. As I close, I thank those 
stakeholders we see most often, our employees, 
contractors, suppliers, partners, our community members 
and shareholders, for all their contributions in completing a 
very successful first year as a public company. The year 
was crowned with additional success by a deep honour 
bestowed on Seven Generations. The Chamber of 
Commerce in Grande Prairie, the home of our operating 
headquarters, honoured us with the title Business Citizen 
of the Year 2016. We are privileged to call Grande Prairie 
home and tag ourselves Grande Prairie’s Energy Company. 

Sincerely,

Pat Carlson, P.Eng. 
CEO

March 2016

SEVEN GENERATIONS 2015 ANNUAL REPORT15

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:

 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;

 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;

 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;

 The need of our business partners and infrastructure 

customers to be treated fairly and attentively;

Environment

Employees

Shareholders

 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;

 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

Communities

Partners

Supply & Service
Providers

Government &
Regulators

 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.

SEVEN GENERATIONS 2015 ANNUAL REPORT16

PRESIDENT’S 
MESSAGE

substantially better than the previous year and 
comparable to the performance achieved by the best  
run companies.

In the fall of 2014, we announced a $1.6 billion 2015 budget 
to deliver 55,000 to 60,000 barrels of oil equivalent per  
day (boe/d) of production. Then in February of 2015 we 
announced that we would reduce the capital investment, 
setting guidance between $1.3 billion and $1.35 billion,  
but we maintained the same production target. Capital 
investment in 2015 was $1.31 billion, which was at the  
low end of our guidance range, and production was  
60,403 boe/d, which was slightly more than the upper end 
of the production guidance range. We understand that 
delivering what we promise, quarter-by-quarter and year-by-
year, is critical to the success of our company.

An important target that we set several years ago was to 
deliver 250 million cubic feet per day (MMcf/d) of liquids-rich 
natural gas by December 1, 2015, which meets our Alliance 
Pipeline firm transportation commitment. We achieved  
this milestone by efficiently executing our 2015 program,  
which included drilling 82 and completing 58 Montney  
wells, expanding our gas processing capacity to at least 
260 MMcf/d and commissioning a 25,000 barrel per day 
(bbl/d) stabilizer to process our condensate production.

In 2015, we drilled 82 wells with lateral sections averaging 
2,713 meters 20 percent faster and 24 percent cheaper 
than in 2014. The cost per meter drilled has improved from 
$2,370 per metre in 2014 to about $1,800 per metre in 
2015 with the fourth quarter of 2015 averaging about 
$1,550 per metre. As a result, the cost to drill a well moved 
from $6.6 million in 2014 to $5.0 million in 2015 and  
$4.1 million in the fourth quarter of 2015. We estimate that 
approximately 70 percent of our drilling cost reductions 
have been achieved through innovation and efficiency, for 
example reducing spud-to-rig-release days from 57 in the 
fourth quarter of 2014 to 36 in the fourth quarter of 2015. 
The remaining 30 percent of the drilling cost savings have 
resulted from suppliers and service providers reducing 
their charge rates, reflecting lower margins in the service 
and supply business and improved efficiencies on the 
service and supply side. We expect that the majority of 
the drilling cost savings that we have realized will be 
preserved as the industry recovers and returns to higher 
activity levels. 

Marty Proctor,  
President & Chief Operating Officer

In our first full calendar year as a public 
company, we nearly doubled production, drilled 
long wells faster, improved well completion 
efficiency, lowered costs and built significant 
natural gas processing facilities. And while we 
grew production and reserves, we maintained 
our balance sheet strength. Despite a  
43 percent year-over-year drop in commodity 
prices, 2015 funds from operations remained 
robust at $415 million, up 26 percent compared 
to 2014.

In 2015, we continued to deliver results that met or 
exceeded the production, operating cost, and capital 
investment targets that we communicated to the market. 
It is significant to note that we delivered the operational 
results while steadfastly adhering to our Level 1 Corporate 
Policy which defines how we deal with all stakeholders. 
Our Level 1 Policy commitment to staff and contractors 
includes providing a safe work environment. Our intense 
focus on creating a gold standard safety culture resulted 
in a Total Recordable Incident Frequency (TRIF) that was 

SEVEN GENERATIONS 2015 ANNUAL REPORTU.S.A.

17

GREENLAND

ICELAND

Seven Generations’  
Kakwa River Project is located  
in northwest Alberta.

BC

Prince Rupert
Kitimat

M

o

n

t

n

e

y

AB

Grande Prairie

SK

7G Lands

Edmonton

CANADA

Calgary

Saskatoon

e r
e r

k   R i v
k   R i v

n
n

a
a

b
b

t
t

u
u

C
C

50 km Grande Prairie

CUTBANK
CUTBANK
PLANT
PLANT

A

L

L

I

A

N

C

E

P

I

P

E

L

I

N

E

S m oky River
S m oky River

LATOR
LATOR
PLANT
PLANT

K a k w a Riv er
K a k w a Riv er

40 km Grande Cache

Churchill

7G Lands 

Rivers

Major Highway

Pipelines
Pembina Peace 

Alliance 

TransCanada 

Vancouver

Seattle

WA

Portland

OR

Regina

MB

Winnipeg

ON

A

L
LIA

Sault Ste. Marie

Helena

MT

N

C

E PIP

ND

E

LIN

E

Bismark

Boise

ID

WY

SD

Pierre

U.S.A.

MN

Saint Paul

Minneapolis

WI

Toronto

MI

Detroit Sarnia

IA

Des Moines

Milwaukee

Chicago

IL

AUX SABLE
NGL PLANT

IN

OH
Columbus

QC

Montreal

Ottawa

Buffalo

PA
Pittsburgh

We completed a total of 58 wells in 2015, with an average 
of 29 stages per well, an average of 4,395 metric tonnes 
of sand per well, at an average cost of $6.8 million per 
well. During the fourth quarter we completed 13 wells with 
an average cost of $6.1 million per well, which, using fourth 
quarter drilling costs, would result in a construction cost 
of $10.2 million per well. Our completions costs were down 
about 26 percent in 2015, while we pumped significantly 
more sand per well than in 2014. However, we are not 
focused on headline well costs alone, instead we are 
committed to maximizing the value of our resource. 

MEXICO

With this in mind, we continue to push the envelope on 
completions. For example, we tested proppant densities on 
three wells ranging from 2 tonnes to 6 tonnes per metre 
during the fourth quarter. We have also started to use 
slickwater for a portion of our completions, which elimi-
nates nitrogen related flaring and reduces our carbon 
footprint. We will continue to compare the results to our 
standard nitrogen foam fracture completions as we work 
to optimize our completions technology. Our innovation and 
optimization focus, which included tests with larger 
hydraulic fractures spaced closer together than our 

BAHAMAS

CUBA

DOM. REP.

JAMAICA

HAITI

BELIZE

GUATEMALA

HONDURAS

EL SALVADOR

NICARAGUA

COSTA RICA

PANAMA

VENEZUELA GUYANA

B R A Z I L

COLOMBIA

SEVEN GENERATIONS 2015 ANNUAL REPORT 
18

previous standard design, along with our deliberate 
restraints on production rates, a technique known as slow-
back, have improved our Kakwa well type curves – the 
core measure of well productivity. The combination of 
lower well costs and improved type curves generates 
better economics, which helps to offset the negative 
effect of low commodity prices.

Our facility engineering team had many significant 
accomplishments in 2015, completing major projects ahead 
of schedule and under budget, and advancing additional 
projects that are required to meet our future processing 
needs as our production continues to grow. Our Lator 2 
natural gas processing plant came online in the fourth 
quarter, approximately six weeks ahead of schedule and  
15 percent under budget, and it is demonstrating operational 
performance consistent with the design capacity. Our 
second nominal 250 MMcf/d gas processing plant, the 
Cutbank plant, is under construction and is on time and 
budget. We expect it to be processing incremental gas 
volumes in the second quarter of 2016. We are also 
constructing a 29 km, 24-inch diameter natural gas sales 
pipeline, including a 2.2 km section of pipe under the 
Cutbank River, which was directionally drilled at a steep 
angle about 80 metres below the riverbed, leaving the 
surface of the river valley untouched. This new pipeline 
connects our nearly complete Cutbank processing plant to 
the Alliance Pipeline for the delivery of liquids-rich natural 
gas to the Chicago area market. Building our own facilities 
means that we can complete these projects on our own 
timeline and budget, and ensures we have control over the 
processing capacity that supports our planned growth.

During the fourth quarter, production facilities were 
installed on 7G’s seventh Super Pad, #6, where production 
began flowing at the end of January. Construction 
continued to progress on schedule and budget for 7G’s 
eighth Super Pad, #4-14, which is expected to be commis-
sioned in the first quarter of 2016. These eight Super Pads 
will bring our total field gathering and processing capacity 
to 400 MMcf/d of natural gas and 80,000 bbls/d of field 
condensate. The field-specific design of Super Pad 
production facilities enables raw gas dehydration and free 

liquid separation from the very rich natural gas produced 
at the wellhead. 7G Super Pads are designed and con-
structed to deliver high-pressure, produced natural gas a 
short distance back to the wells to facilitate artificial lift. 
With the high liquids content of our Montney natural gas, 
the wells tend to load up with liquids as the near-wellbore 
reservoir pressure declines. When our wells are initially 
completed, gas lift components are installed to prepare in 
advance for the time when the bottom-hole pressure is 
insufficient to lift liquids. Gas lift is an efficient artificial lift 
method that enables steady production of the field’s high 
volume of condensate and natural gas liquids.

Full year 2015 production was 60,403 boe/d which was 
slightly above the high end of guidance, and liquids ratios 
have been consistently around 58 percent, with conden-
sate averaging 35 percent of total corporate volumes. 
Fourth quarter production averaged 77,700 boe/d which 
was an approximate 75 percent increase over the fourth 
quarter of 2014. We continue to choke our wells, or use 
the slow-back production method, which helps maintain 
downhole pressures and improves our liquids recoveries 
while creating a shallower decline in our production profile. 
Our decline rate is approximately 30 to 35 percent, which 
is less than typical for resource plays that are produced at 
unconstrained rates. As a result, the number of wells 
required to maintain production is relatively low. Consider-
ing our strong capital efficiencies and moderate decline 
rates, we estimate that we could sustain a flat production 
profile by investing less than the cash flow we expect to 
generate. We are choosing to invest more than our 
anticipated cash flow into infrastructure and wells 
because we believe that the growth program we are 
executing will maximize the value of our Montney acreage 
and accelerate our path towards cash flow sustainability.

Our 2015 year-end reserves report continued to reflect our 
ability to convert resources to reserves to production. 
McDaniel & Associates Consultants Limited (McDaniel)  
has estimated that Seven Generations had 73 million 
barrels of oil equivalent (MMboe) of gross proved 
developed producing reserves at December 31, 2015,  
up 115 percent from 34 MMboe at the end of 2014. This  

“Innovation is a strategic cornerstone at Seven Generations.  
We will continue to experiment with well construction techniques, 
modular facilities, and other innovative and creative methods to 
improve capital efficiencies and leadership as a low-cost supplier of 
liquids-rich natural gas for North American consumers.”

SEVEN GENERATIONS 2015 ANNUAL REPORT19

is significant because it defines our capacity to generate 
cash flow from existing wells. Additionally, we saw  
our proved plus probable reserves increase by about  
10 percent to about 860 MMboe as the independent 
evaluators recognize improved recovery from our lands. 
Within our core producing property called the Nest,  
we estimate, and McDaniel agrees, that there are more 
than 930 potential drilling opportunities in the Upper and 
Middle Montney formation with approximately 54 percent 
of these potential drilling locations having reserves 
attributed to them, and the remaining locations having 
contingent resources attributed to them. These locations 
represent an inventory of 12 to 18 years of drilling within 
the Nest. This longevity is based on our current drilling 
rates of 82 wells in 2015 and our plans to drill about  
50 wells in 2016. We are also encouraged by the fact that 
our focus on technical innovation, operational efficiencies 
and asset quality are being acknowledged by McDaniel 
through a combination of decreased future development 
capital and increased technical reserve revisions. 
Estimated undiscounted future development costs were 
33 percent lower at $4.1 billion for proved reserves and 
down 20 percent to $7.1 billion for proved plus probable 
reserves. A 31.5 MMboe increase in gross proved reserves, 
which was attributable to technical revisions, provides 
external confirmation that our innovation efforts are 
improving capital efficiencies and that the quality of the 
resource is exceeding expectations.

In 2016, the Company has contracted firm transportation 
capacity on Alliance Pipeline that averages approximately 
350 MMcf/d, and that Alliance capacity is scheduled to 
incrementally step up to 500 MMcf/d in late 2018.  
Owning and operating our gathering lines and processing 
facilities increases our operational flexibility. We 
constantly analyze our business plan and can adapt 
quickly as the investment environment changes. Having 
control of our infrastructure, and the excess processing 
capacity that the new Cutbank plant will provide, means 
that when there is a strengthening of commodity prices, 
we could choose to increase our pace of drilling and 
completions to grow more quickly. Conversely, if 
commodity prices deteriorate to a level at which 
developing our Nest 2 locations is no longer prudent, we 
would work with our marketing partner to subcontract our 
capacity on Alliance Pipeline.

In executing our 2016 program we will remain focused  
on safety, protecting the environment and serving  
our stakeholders. Innovation is a strategic cornerstone  
at Seven Generations, which means we will continue  
to experiment with well construction techniques,  
modular facilities, and other innovative and creative 
methods to improve capital efficiencies and leadership  
as a low-cost supplier of liquids-rich natural gas for North 
American consumers.

Outlook

Sincerely,

Marty Proctor 
President & Chief Operating Officer

March 2016

Seven Generations plans a 2016 capital investment 
program of $900 million to $950 million that is focused on 
drilling, well completions and production facilities, 
investments that will help advance 7G towards generating 
positive free cash flow. At current commodity prices, we 
expect to operate five rigs through the remainder of 2016, 
down from the average of 10 rigs that we operated 
through most of 2015. This lower rig count reflects 7G’s 
improved capital efficiencies and reduced capital 
investment in drilling due to lower commodity prices. 2016 
production is expected to average 100,000 to 110,000 
boe/d, representing an approximate 75 percent increase 
over 2015 average production of 60,403 boe/d. In 2016, 
7G’s liquids are expected to range between 55 and  
60 percent of total production.

2016 capital investments are weighted towards the  
early months of 2016 with a focus on completing and 
commissioning the Cutbank plant, which is expected to take 
7G’s processing capacity at Kakwa from 260 MMcf/d to  
510 MMcf/d of liquids-rich natural gas. Our seventh Super 
Pad was completed early this year. As the rest of 2016 
unfolds, we plan to complete and tie-in about 67 wells, finish 
the construction of 7G’s eighth and ninth Super  
Pads and related gathering pipelines and complete 
construction of major production facilities, including  
a second 25,000 bbl/d condensate stabilizer at the  
Karr facility. 

SEVEN GENERATIONS 2015 ANNUAL REPORT20

HIGHLIGHTS 
SUMMARY

FINANCIAL
 Funds from operations reached $415 million, up  

26 percent compared to 2014, despite a 43 percent 
year-over-year drop in commodity prices;

 Capital investment of $1.31 billion was at the low end  

of 7G’s 2015 guidance range of $1.30 billion to  
$1.35 billion; and

 Achieved netback after hedging of $23.72 per barrel of 
oil equivalent, which benefited from a $6.83 per boe 
increase from commodity price hedging.

OPERATIONAL
 Record production of 60,403 barrels of oil equivalent  
per day (boe/d), and up 94 percent from 2014 and 
slightly more than 7G’s 2015 guidance range of 55,000 
to 60,000 boe/d;

 Drilled 82 wells at an average cost of $5 million per well, 

down 24 percent compared to 2014;

 Completed 58 wells and an average cost of $6.8 million 
per well, down 26 percent, while the volume of sand 
proppant pumped into each well increased about  
34 percent;

 A determined focus on innovation and optimization focus 
boosted well productive performance, larger hydraulic 
fractures spaced closer together, along with our 
deliberate restraints on production rates, a technique 
known as slowback, improved Kakwa well type curves –  
the fundamental to for measuring well productivity;

 Completed construction and commissioning six weeks 
early and about 15 percent under budget of Lator 2 
natural gas processing plant, which added 200 million 
cubic feet per day (MMcf/d) of processing capacity. 
Lator complex capacity increased to 260 MMcf/d  
and operational performance demonstrating design 
capacity; and

 Commenced delivery under contract with Alliance 

Pipeline of liquids-rich natural gas to an effective pricing 
point at Chicago.

RESERVES – EVALUATED BY 
MCDANIEL AS AT DECEMBER 31, 2015
 Gross proved developed producing reserves were  
73.3 MMboe, up 115 percent from 34.1 MMboe at 
December 31, 2014;

 Total gross proved reserves were 424 MMboe and  

gross proved plus probable reserves were 859 MMboe, 
representing an increase of 1 percent and 9 percent, 
respectively, when compared to 7G’s December 31, 2014 
total proved and proved plus probable reserves;

 Total undiscounted future development costs were 

estimated to be $4.1 billion for proved reserves, down  
33 percent, and $7.1 billion for proved plus probable 
reserves, down 20 percent, compared to the end  
of 2014. Lower future development costs are the 
product of technical innovation, improving capital and 
operational efficiencies and enhanced productive 
performance from the Company’s high quality Kakwa 
River Project asset; and

 Before tax net present value of future net revenue 
estimates, using a discount rate of 10 percent per 
annum, was $2.9 billion for gross proved reserves and 
$6.5 billion for gross proved plus probable reserves.

STRONG BALANCE SHEET
 Maintained a strong balance sheet despite a 43 percent 

decrease in commodity prices;

 Expanded existing senior secured credit facility, 

provided by a syndicate of ten financial institutions, by 
30 percent, or $200 million, to $850 million;

 Raised US$425 million long term debt – 6.750 percent 

senior notes due 2023; and

 Added to the S&P/TSX Composite Index, the headline 
index for the Canadian equity markets, in June, 2015.

SEVEN GENERATIONS 2015 ANNUAL REPORT2015 FINANCIAL AND  
OPERATING RESULTS 

21

Year ended December 31

OPERATIONAL

Production

Oil and condensate (bbls/d)

NGLs (bbls/d)

Natural gas (MMcf/d)

Oil equivalent (boe/d)

Liquids percent

Realized prices

Oil and condensate ($/bbl)

NGLs ($/bbl)

Natural gas ($/Mcf)

Oil equivalent ($/boe)

Operating netback per boe ($) (1)

Oil and natural gas revenue

Royalties

Operating expenses

Transportation expenses

Netback prior to hedging 

Realized hedging gain (loss)

Netback after hedging

General and administrative expenses per boe

Selected financial information

Oil and natural gas revenue

Funds from operations (1)

Per share – diluted

Operating income (loss) (1)

Per share – diluted

Net income (loss)

Per share – diluted

Weighted average shares – diluted

Total capital investments

Available funding (1)

Net debt (1)

Debt outstanding

2015

2014

% Change

21,204

14,341

149

60,403

59%

50.84

10.34

2.65

26.85

26.85

(2.63)

(4.59)

(2.74)

16.89

6.83

23.72

1.10

591,924

414,609

1.54

52,105

0.21

(187,296)

(0.75)

249,549

1,308,973

1,118,143

1,250,857

1,546,761

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

224,717

1,120,336

1,133,800

158,270

813,880

92

105

89

94

2

(40)

(57)

(41)

(43)

(43)

(42)

(4)

(10)

(51)

nm

(33)

(38)

11

26

5

(56)

(60)

(230)

(217)

11

17

(1)

nm

90

(1) 

 Operating netback, funds from operations, operating income, available funding and net debt are not defined under IFRS. See “Non-IFRS Financial 
Mea sures” in Management’s Discussion and Analysis for the year ended December 31, 2015.

SEVEN GENERATIONS 2015 ANNUAL REPORT22

MANAGEMENT’S  
DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”), dated March 8, 2016, is management’s assessment of the 
historical financial position and results of Seven Generations Energy Ltd. (the “Company” or “Seven Generations”) for the 
year ended December 31, 2015. This MD&A should be read in conjunction with the audited annual consolidated financial 
statements and notes thereto for the years ended December 31, 2015 and 2014 (the “consolidated financial statements”). 
These consolidated financial statements, including the comparative figures, were prepared in accordance with 
International Financial Reporting Standards (“IFRS”). Unless otherwise noted, all financial measures are expressed in 
Canadian dollars and tabular dollar amounts are in thousands. 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”, “available funding” and “net debt”. This MD&A contains forward looking information based on the 
Company’s current expectations and projections. For information on the material factors and assumptions underlying 
such forward looking information, refer to the “Forward Looking Information Advisory” included at the end of this MD&A. 
A number of abbreviated terms used throughout this MD&A are explained on the last page of this MD&A. Additional 
information about Seven Generations is available on the SEDAR website at www.sedar.com, including the Company’s 
Annual Information Form for the year ended December 31, 2015 dated March 8, 2016 (the “AIF”).

ABOUT SEVEN GENERATIONS ENERGY LTD.
Seven Generations is a low supply cost, high-growth Canadian natural gas developer generating long-life value from its 
liquids-rich Kakwa River Project, located about 100 km south of its operations headquarters in Grande Prairie, Alberta. 
Seven Generations’ corporate headquarters are in Calgary and its Class A Common Shares (“Common Shares”) trade on 
the TSX under the symbol VII.

Highlights for The Fourth Quarter and Year Ended December 31, 2015

Financial Performance

Seven Generations achieved record production levels averaging more than 60,000 boe/d and funds from operations of 
more than $400 million in 2015. The higher supply and inventory levels of global oil and natural gas led to significant 
decreases in prices, largely impacting the Company’s net loss position in 2015. Comparing 2015 to 2014, WTI decreased 
by 44 percent and the Canadian dollar lost 14 percent of its value, relative to the US dollar. The Company realized an 
operating netback after hedging of $23.72/boe for the year ended December 31, 2015 compared to $35.52/boe for the 
same period in 2014. In this low commodity price environment, the Company’s focus remains on prudent, disciplined 
investment in long-term value creation. 

Capital Investments

In 2015, Seven Generations invested $1.31 billion, at the low end of the 2015 guidance, which ranged between $1.30 billion 
and $1.35 billion. The Company attributes these savings to improved capital efficiencies in 2015 such as faster drilling 
and the optimization of well completions. The construction of the new Lator 2 natural gas processing facility was 
completed 15 percent under budget and was commissioned six weeks ahead of schedule. The construction of a second  
250 MMcf/d natural gas processing plant, the Cutbank Plant, is underway and is expected to be operational in the 
second quarter of 2016.

Transportation and Marketing

The Company’s lands are close to key infrastructure and take-away capacity, including Alliance Pipeline, TransCanada 
NGTL system and Pembina Peace Pipeline, on which it has contracted firm transportation capacity for natural gas, 
condensate and other natural gas liquids (“NGLs”). These firm service transportation agreements support the Company’s 
ability to deliver on its high growth objectives. On December 1, 2015, the Company began shipments of rich gas to fulfill 
the initial firm commitment of 250 MMcf/d on the Alliance Pipeline. Seven Generations holds transportation capacity that 
grows incrementally over the next three years, reaching approximately 600 MMcf/d in 2018. In the third quarter of 2015, 
the Company accelerated certain gas transportation capacity commitments with Alliance and signed an agreement to 
have a third party marketer manage this excess capacity by flowing third party gas.

SEVEN GENERATIONS 2015 ANNUAL REPORTMANAGEMENT’S  

DISCUSSION AND ANALYSIS

23

Risk Management

Seven Generations continued to execute its consistent risk management program in 2015, hedging oil and natural  
gas prices and exchange rates to partially protect funds from operations against commodity price volatility through a 
three year, rolling hedging program.

Reserves Update

The Company’s independent reserve evaluators, McDaniel & Associates Consultants Ltd. (“McDaniel”), completed 
independent reserve evaluations effective December 31, 2015. Total gross proved reserves (“1P”) were 424.0 MMboe, as 
at December 31, 2015, an increase of 1 percent since the Company’s December 31, 2014 reserve evaluations. Total gross 
proved plus probable reserves (“2P”) were 859.1 MMboe, an increase of 9 percent compared to the December 31, 2014 
estimates. Using a discount rate of 10 percent, the Company’s total gross 2P reserves were estimated to have a before 
tax net present value of $6.5 billion compared to $7.1 billion from the December 31, 2014 reserve report, as reserve 
additions were offset by a lower price deck used by McDaniel.

For important additional information pertaining to the Company’s estimated reserves and the estimated net present 
value of future net revenue that is attributed to the reserves, as evaluated by McDaniel as at December 31, 2015, please 
refer to the AIF on the SEDAR website at www.sedar.com.

As at

PDP + PDNP (1)

Proved Reserves (1P) (2)

Proved Plus Probable Reserves (2P) (2)

December 31, 2015

December 31, 2014

MMboe

79

424

859

$MM (3)

951

2,937

6,507

MMboe

$MM (3)

39

421

789

627

3,145

7,108

(1)   Proved developed producing plus proved developed non-producing reserves.

(2)   Company gross reserve as determined by McDaniel, the Company’s independent reserves evaluator.

(3)   Before tax net present value using a 10% discount rate.

Outlook and 2016 Guidance

The Company is focused on: (i) cash flow self sufficiency; (ii) the development of a large inventory of relatively low supply 
cost, liquids-rich horizontal well drilling opportunities in its core focus area; (iii) building facilities to gather and process 
the produced natural gas, condensate and other NGLs; and (iv) establishing further opportunities to maximize value. 
Although uncertainty with commodity prices and the oversupply of natural gas markets persisted throughout 2015, 
Seven Generations remains focused on innovation, efficiency and value optimization to be among the lowest cost 
suppliers in North America.

Seven Generations expects to invest between $900 million and $950 million for capital investments in 2016. In response 
to continued low commodity prices, the capital program was reduced by 18 percent from the first announced budget in 
November. The Company does not expect the deferral of planned 2016 investment to impact 2016 production guidance. 
Production guidance for 2016 is expected to be between 100,000 and 110,000 boe/d, 80 percent higher than  
2015 production.

SEVEN GENERATIONS 2015 ANNUAL REPORT24

OPERATIONAL AND FINANCIAL HIGHLIGHTS
The following table presents selected operational and financial information for the three months and year ended 
December 31, 2015 and 2014:

($ thousands, except per share and volume data)

2015

2014

% Change

2015

2014

% Change

Three months ended December 31

Year ended December 31

Production

Condensate (bbls/d)

NGLs (bbls/d)

Liquids (bbls/d)

Natural gas (MMcf/d)

Total Production (boe/d)

Liquids ratio

Financial

Operating income (loss) (1)

  Per share – diluted

Revenue (2)

Net income (loss) for the period

  Per share – diluted

Funds from operations (1)

  Per share – diluted

Adjusted Working Capital

Weighted average shares – diluted

Total capital investments

Available funding (1)

Net debt (1)

Debt outstanding

(1)  See “Non-IFRS Financial Measures”.

25,572

19,236

44,808

197

77,699

58%

(14,191)

(0.06)

245,914

(28,922)

(0.11)

14,747

10,783

25,530

112

44,178

58%

34,815

0.14

287,141

68,628

0.28

106,031

101,503

0.40

306,143

252,896

301,149

0.41

653,800

248,510

370,320

1,118,143

1,133,800

1,250,857

1,546,761

158,270

813,880

73

78

76

76

76

0

(141)

(143)

15

(142)

(139)

4

(2)

(53)

2

(19)

(1)

nm

90

21,204

14,341

35,545

149

60,403

59%

52,105

0.21

676,709

(187,296)

(0.75)

11,061

6,989

18,050

79

31,136

58%

119,521

0.53

639,432

144,200

0.64

414,609

327,933

1.54

306,143

249,549

1,308,973

1.46

653,800

224,717

1,110,916

1,118,143

1,133,800

1,250,857

1,546,761

158,270

813,880

92

105

97

89

94

2

(56)

(60)

11

(230)

(217)

26

5

(53)

11

18

(1)

nm

90

(2)  Represents the total of liquids and natural gas sales, net of royalties, and includes net gains/losses on risk management contracts and other income.

Production

Seven Generations produced 77,699 boe/d in the fourth quarter of 2015, an increase of 76 percent from the same period 
in 2014. Production for the year was 60,403 boe/d, an increase of 94 percent from 2014. The liquids ratio was 
approximately 58 percent for all periods presented, comprised of approximately 60 percent condensate and 
approximately 40 percent NGLs. 

Operating Income (Loss)

For the fourth quarter of 2015, Seven Generations recorded an operating loss of $14.2 million compared to operating 
income of $34.8 million for the same period in 2014. The difference is mostly due to lower prices, higher gross operating 
and transportation expenses, increased depletion expense related to higher production and depreciable assets and 
higher interest expense.

Operating income for the year ended December 31, 2015 was $52.1 million compared to $119.5 million for the same period 
in 2014. The decrease of $67.4 million was mostly due to lower realized prices as a result of lower benchmark prices, 
higher depletion expense due to the increases in production and higher interest expense related to the senior notes.  
On a year over year comparison, WTI decreased by 44 percent and AECO declined by 43 percent.

Net Income (Loss)

For the fourth quarter of 2015, the Company recognized an operating loss of $28.9 million compared to net income of  
$68.6 million for the same period in 2014. In addition to the items impacting operating income (loss) noted above, the 
decrease is due to higher unrealized foreign exchange losses on the senior notes and future income tax expense of  
$61.9 million. The annual loss was also due to higher unrealized foreign exchange losses and future income tax expense of 
$61.8 million. For the year ended December 31, 2015, the Company recorded a net loss of $187.3 million compared to net 
income of $144.2 million for the same period in 2014.

SEVEN GENERATIONS 2015 ANNUAL REPORT25

Funds from Operations

Funds from operations increased by $4.5 million in the fourth quarter of 2015 to $106.0 million due to higher production 
being offset by lower prices. Higher interest expense on the senior notes also decreased funds from operations due to 
additional debt raised in April 2015 and the weakening Canadian dollar. 

For the year ended December 31, 2015, funds from operations increased by $86.7 million, to $414.6 million, due to higher 
production, higher realized hedging gains which positively contributed $140.8 million offset by higher interest expense. 
Realized hedging gains increase when commodity prices decrease.

Funds from Operations for the Year Ended December 31, 2015
$000s

2014

Realized prices

Production

Realized hedges

Netback expenses (1)

Interest expense

Other expenses

2015

327,933

229,061

286,183

140,843

77,991

37,435

4,137

414,609

$

0

500

100

150

200

250

300

350

400

450

500

(1)  Netback expenses include royalties, operating expenses and transportation.

Capital Investments

For the year ended December 31, 2015, Seven Generations invested $1.31 billion in the development of its core focus 
area. The Lator 2 natural gas plant was commissioned six weeks earlier than scheduled and came in 15 percent lower 
than estimated cost. The capacity of the Lator complex is approximately 260 MMcf/d and it marks the first step towards 
supplying the natural gas volumes to fulfill the Company’s firm commitments on the Alliance Pipeline. On December 1, 
2015, the Company began flowing natural gas on the Alliance Pipeline, selling into the US Midwest market, where it 
receives Chicago Citygate prices. A second natural gas processing plant, with a planned capacity of 250 MMcf/d, at 
Cutbank, was approximately 75 percent complete at the end of the year. The Cutbank natural gas plant is expected to be 
commissioned and operational in the second quarter of 2016, along with the Cutbank sales pipeline.

In 2015, the Company drilled 83 net wells and completed 57.5 net wells further expanding development of the Kakwa 
River Project. The Company benefited from drilling and completions efficiencies in 2015 including cost savings due to 
shorter drilling days and continued optimization of well design by testing and evaluating hydraulic fractionation 
expansion. 61 net well tie-ins were completed in 2015 and at December 31, 2015, the Company had an inventory of  
63 wells at various stages of construction.

The Company commissioned a new Super Pad in the third quarter of 2015, which will support growing production levels. 
The Company developed the Super Pad, which is equivalent to a small gas plant, to facilitate raw gas dehydration and 
free liquid separation from the rich gas produced at the wellhead. By concentrating horizontal drilling from a single pad, 
the Super Pads allow Seven Generations to maximize resource recovery with longer wells drilled while minimizing surface 
impact. At the end of 2015, two new Super Pads were under construction and expected to be operational in the first half 
of 2016. The Company plans to construct and commission an additional Super Pad in the second half of 2016. At 
December 31, 2015, six Super Pads were in operation.

SEVEN GENERATIONS 2015 ANNUAL REPORT26

Available Funding

The Company had available funding of $1.1 billion at December 31, 2015. Available funding is comprised of $306.1 million of 
adjusted working capital and $812 million of credit capacity. Subsequent to year end, the Company closed a bought deal 
private placement for gross proceeds of $300 million. The Company expects that the proceeds from this placement 
coupled with funds from operations and available funding will support the ongoing capital investment program in 2016.

Operating Netback

Sales

Realized hedging

Royalties

Operating expenses

Transportation

Operating netback per boe (1)

(1)   See “Non-IFRS Financial Measures”.

Three months ended December 31

Year ended December 31

2015

24.97

3.21

(1.70)

(4.11)

(3.36)

19.01

2014

38.23

5.45

(3.97)

(4.67)

(3.26)

31.78

% Change

(35)

(41)

(57)

(12)

3

(40)

2015

26.85

6.83

(2.63)

(4.59)

(2.74)

23.72

2014

47.06

0.86

(4.57)

(4.77)

(3.06)

35.52

% Change

(43)

nm

(42)

(4)

(10)

(33)

Operating netback for the fourth quarter of 2015 was $19.01/boe, lower by $12.77/boe, compared to $31.78/boe in the 
same period in 2014, resulting from low commodity prices offset by lower royalties and operating expenses. Realized 
hedging gains were also lower on a per boe basis due to higher production volumes. Royalties and operating expenses  
on a per boe basis were lower than the same period in 2014 by 57 percent and 12 percent, respectively, due to lower 
prices. Transportation was higher by 3 percent due to the Alliance Pipeline tariffs being reflected in transportation 
starting in December 2015.

For the year ended December 31, 2015, operating netback fell by $11.80/boe, mostly due to decreases in realized  
prices, which fell by $20.27/boe and were partially offset by realized hedging gains of $5.97/boe. Lower operating and 
transportation expenses due to higher production all helped to offset the realized price declines. Royalties, in absolute 
dollars, were lower due to new wells eligible for incentive programs. On a per boe basis, royalties decreased by $1.94/boe 
year over year, in line with the decrease in commodity prices. On a per boe basis, operating and transportation expenses 
decreased by $0.18/boe and $0.32/boe, respectively, year over year, with higher volumes and more condensate sold  
via pipeline.

Operating Netback for the Year Ended December 31, 2015
$/bbl

2014

Production revenue 
(before hedging)

Realized 
hedging gain

Royalties

Operating expenses

Transportation 

2015

$35.52

$(20.21)

$5.97

$1.94

$0.18

$0.32

$23.72

$

0

5

10

15

20

25

30

35

40

SEVEN GENERATIONS 2015 ANNUAL REPORT27

Selected Annual Financial Information

($ thousands, except per share and volume data)

Revenue (1)

Net income (loss) and comprehensive income (loss)

  Per share – diluted

Total capital investments

Total assets

Total long-term debt

2015

676,709

(187,296)

(0.75)

1,308,973

3,758,982

1,546,761

2014

639,432

144,200

0.64

1,110,916

3,114,797

813,880

2013

105,207

(14,158)

(0.08)

574,328

1,408,213

414,525

(1)  Represents the total of liquids and natural gas sales, net of royalties, and includes net gains/losses on risk management contracts and other income.

Since 2013, Seven Generations’ revenues increased by $571.5 million due to an increase of 675 percent in production. 
Production has grown from 7,786 boe/d in 2013, to more than 60,000 boe/d in 2015. The higher production is due to  
the number of wells brought on stream: 61 gross (61.0 net) wells in 2015 and 34 gross (33.7 net) wells in 2014.

In 2015, the Company recorded a net loss of $187.3 million, largely impacted by a low commodity price environment and 
unrealized foreign exchange losses on US dollar denominated debt. Also impacting the net loss was an increase in 
depletion and depreciation expense mostly related to higher production volumes.

Seven Generations invests capital in a single focus area, the Kakwa River Project, which is a large-scale, tight, liquids-rich 
natural gas property located in northwest Alberta. As at December 31, 2015, investments for the development of the 
Kakwa River Project were $2.9 billion. The upper and middle intervals of the Triassic Montney formation in the Kakwa 
River 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 an 
acceptable rate of return.

Daily Production

Condensate (bbls/d)

NGLs (bbls/d)

Natural gas (MMcf/d)

Total (boe/d)

Liquids ratio

Three months ended December 31

Year ended December 31

2015

25,572

19,236

197

77,699

58%

2014

% Change

14,747

10,783

112

44,178

58%

73

78

76

76

-

2015

21,204

14,341

149

60,403

59%

2014

11,061

6,989

79

31,136

58%

% Change

92

105

89

94

2

The Company achieved record production in the fourth quarter of 2015 of 77,699 boe/d, an increase of 76 percent from 
the same period in 2014, due to a higher number of producing wells and the commissioning of the Lator 2 natural gas 
plant. Production volumes were higher than the third quarter of 2015 by 28 percent, which averaged 60,600 boe/d. 

Seven Generations production exceeded the high end of its 2015 guidance of 55,000 to 60,000 boe/d, producing 60,403 boe/d 
for the year ended December 31, 2015. The Company achieved this despite the six day Alliance Pipeline shutdown during 
the third quarter of 2015. Higher production volumes were due entirely to organic growth through drilling and completions.

Well Information

Number of wells

Drilled – gross (net)

Completed – gross (net)

Brought on production – gross (net)

Three months ended December 31

Year ended December 31

2015

2014

% Change

2015

2014

% Change

22 (22.0)

13

11

(13.0)

(11.0)

14

11

9

(14.0)

(11.0)

(9.0)

57

18

22

84 (83.0)

49 (49.0)

58 (57.5)

38 (38.0)

61

(61.0)

34

(33.7)

71

53

79

The well counts include only horizontal Montney wells. Drill counts are based on the rig release date and brought on 
production counts are based on the first production date after the well is tied in. At December 31, 2015, Seven Generations 
had an inventory of 63 wells at various stages of construction between drilling, completions and tie in and 106 Montney 
horizontal wells producing within the Kakwa River Project (2014 – 47 wells under construction and 45 wells producing).

SEVEN GENERATIONS 2015 ANNUAL REPORT28

Commodity Pricing

Average Benchmark Prices

Oil – WTI (US$/bbl)

Oil – Edmonton Par ($/bbl)

Natural gas – NYMEX (US$/MMbtu)

Natural gas – AECO NGX 5A ($/Mcf)

Average exchange rate – C$ to US$

Three months ended December 31

Year ended December 31

2015

42.18

52.93

2.24

2.57

0.749

2014

73.15

74.37

3.85

3.58

0.881

% Change

(42)

(29)

(42)

(28)

(15)

2015

48.80

57.2

2.63

2.71

0.782

2014

86.50

93.94

4.30

4.78

0.914

% Change

(44)

(39)

(39)

(43)

(14)

Oil and natural gas prices fell in the fourth quarter of 2015 with WTI decreasing by 42 percent and AECO falling by  
28 percent compared to the same period in 2014. The Canadian dollar weakened by 15 percent relative to the US dollar in 
the fourth quarter of 2015 partially in response to lower oil prices. 

For the year ended December 31, 2015, WTI and AECO decreased by 44 percent and 43 percent, respectively. Strong 
global production, including significant US production growth from shale and tight plays, combined with weaker global 
demand growth resulted in the oversupply of markets and deteriorating prices. The average Canadian dollar exchange 
rate was down by 14 percent compared to the US dollar in 2015. Subsequent to year end, global supply and inventories 
continue to remain high, further deteriorating commodity prices. 

The Company realized the following commodity prices (before hedging):

Condensate and oil ($/bbl)

NGLs ($/bbl)

Natural gas ($/Mcf)

Total ($/boe)

Three months ended December 31

Year ended December 31

2015

46.72

12.35

2.57

24.97

2014

69.93

21.50

3.81

38.23

% Change

(33)

(43)

(33)

(35)

2015

50.84

10.34

2.65

26.85

2014

85.34

24.10

4.50

47.06

% Change

(40)

(57)

(41)

(43)

The Company’s average realized pricing for condensate decreased in the fourth quarter of 2015 to $46.72/boe, a  
decrease of 35 percent, due to lower WTI which fell by 42 percent. Oil price is the main driver of the Company’s realized 
condensate prices.

For the year ended December 31, 2015, the Company’s average realized prices for condensate decreased by $34.50/bbl, 
coming in at $50.84/bbl compared to $85.34/bbl in the same period of 2014. The difference mostly relates to the decrease 
of WTI by US$37.70/bbl. 

NGL prices also saw declines in the fourth quarter of 2015. Approximately 85 percent of the Company’s NGLs are 
ultimately sold in the US Midwest market and 15 percent in the Alberta market. The average realized prices for NGLs 
reflect a combination of prices including ethane, propane, butane and pentanes plus. The product mix of NGLs is 
approximately 1/3 ethane, 1/3 propane, 1/5 butane and the remaining 14 percent is pentanes plus. The Company’s average  
realized prices for the NGL product stream decreased by 43 percent in the fourth quarter of 2015 to $12.35/bbl, due to 
lower benchmark prices. 

For the year ended December 31, 2015, the average realized prices for NGLs were $10.34/bbl compared to $24.10/bbl for 
the same period in 2014, a decrease of 57 percent, mostly related to the low commodity price environment. 

For the fourth quarter of 2015, the Company’s average realized natural gas price was $2.57/Mcf, a decrease of 33 percent 
compared to the same period in 2014, due to the decrease in benchmark prices. Warmer weather and higher inventories 
drove natural gas prices to 16 year lows.

For the year ended December 31, 2015, the Company received an average realized natural gas price of $2.65/Mcf, a 
decrease of 41 percent. Prior to December 2015, Seven Generations’ realized natural gas price was based on AECO prices 
which continued to soften due to oversupplied natural gas markets and low demand in North America. 

Effective December 1, 2015, Seven Generations began delivering natural gas into the US Midwest market in conjunction 
with its commitment on the Alliance Pipeline. The firm commitment of 250 MMcf/d of liquids-rich natural gas increases to 
500 MMcf/d by 2018. The terms of the agreement will allow Seven Generations to transport volumes out of an 
oversupplied market and to realize US Midwest market prices on a significant portion of overall production.

SEVEN GENERATIONS 2015 ANNUAL REPORTLiquids and Natural Gas Sales

Three months ended December 31

Year ended December 31

29

($ thousands, except per boe data)

Condensate and oil

NGLs

Natural gas

2015

110,150

20,532

47,796

94,873

21,329

39,181

Total liquids and natural gas sales (1)

178,478

155,383

Per boe

24.97

38.23

(1)  Excluding realized gains or losses on risk management contracts.

2014

% Change

2014

% Change

2015

393,725

52,781

145,418

344,512

61,470

128,851

591,924

534,833

26.85

47.06

16

(4)

22

15

(35)

14

(14)

13

11

(43)

Revenues for the fourth quarter of 2015 were $178.5 million compared to $155.4 million for the same period in 2014. 
Higher production volumes increased revenues by $77.0 million offset by $53.9 million of reduced commodity prices.  
For the year ended December 31, 2015, there was an increase in revenues of 11 percent to $591.9 million, attributable to  
$286.8 million of higher production volumes offset by $229.7 million due to lower prices.

Risk Management Contracts

The Company’s risk management program resulted in the following:

($ thousands, except per boe data)

Realized gain (1)

Unrealized gain (loss) (2)

Total gain

Realized gain per boe

Three months ended December 31

Year ended December 31

2015

22,980

53,713

76,693

3.21

2014

% Change

2015

22,163

123,772

145,935

5.45

4

(57)

(47)

(41)

150,580

(15,911)

134,669

6.83

2014

9,737

141,765

151,502

0.86

% Change

nm

(111)

(11)

nm

(1)  Represents actual cash settlements or receipts under the respective contracts.

(2)  Represents the change in fair value of the contracts during the period.

The Company utilizes financial hedges to partially protect funds from operations against commodity price volatility. 
Certain guidelines for the risk management program are approved by the Board of Directors of Seven Generations. These 
guidelines allow for hedge targets of up to 65 percent of forecasted production volumes (net of royalties) for the 
upcoming four quarters, up to 30 percent of forecasted volumes for the subsequent four quarters and up to 15 percent 
for the four quarters following. Price targets are established at levels that are expected to provide a threshold rate of 
return on capital investment based on a combination of benchmark oil and natural gas prices, projected well performance 
and capital efficiencies.

Realized gains of $23.0 million, a slight increase of 4 percent, reflect positive cash settlements on hedge contracts 
settled each month. For the year ended December 31, 2015, realized gains were $150.6 million compared to $9.7 million 
for the same period in 2014. Higher realized gains are the result of decreases in commodity benchmark prices. For a 
complete listing and terms of Seven Generations’ hedging contracts at December 31, 2015, see Note 19 “Financial 
Instruments and Market Risk Management” in the consolidated financial statements and “Financial Instruments and Risk 
Management Contracts” below.

The fair value of unsettled derivatives is recorded as an asset or liability with the change in the mark-to-market  
position of contracts recorded as an unrealized gain or loss in the statements of income and comprehensive income.  
As at December 31, 2015, the fair value of the risk management contracts was a net asset position of $123.2 million  
(2014 – net asset of $139.1 million). The unrealized gain of $53.7 million in the fourth quarter of 2015 represents the lower 
Canadian WTI prices on crude oil contracts in the forward price curve, decreased Chicago Citygate prices on natural gas 
contracts and unrealized losses on foreign exchange contracts. For the year ended December 31, 2015, the unrealized loss 
of $15.9 million reflects the change in value of hedge contracts offset by the reversal of prior year realized hedge gains. 

SEVEN GENERATIONS 2015 ANNUAL REPORT30

The Company had the following risk management contracts in place at December 31, 2015:

Liquids hedging

  WTI hedged (bbl/d)

  Average floor (C$/bbl)

  Average ceiling (C$/bbl)

Natural gas hedging

  Natural gas hedged (MMbtu/d)

  Average Chicago Citygate swap (US$/MMbtu)

  Average swap (C$/MMbtu) (1)

FX hedging

  US$ notional hedged (Millions)

  Average rate

2016

13,250

70.04

80.48

122,500

3.19

4.01

143.10

1.26

2017

8,250

68.94

78.88

105,000

3.10

4.00

118.82

1.29

2018

3,250

67.93

74.89

47,500

2.80

3.83

48.46

1.37

(1)  Chicago Citygate converted to C$/MMbtu at average C$/US$ hedge rate.

Royalty Expense

($ thousands, except per boe data)

Royalties

Royalties per boe

Effective royalty rate

Three months ended December 31

Year ended December 31

2015

12,127

1.70

7%

2014

% Change

16,145

3.97

10%

(25)

(57)

(30)

2015

57,898

2.63

10%

2014

% Change

51,890

4.57

10%

12

(42)

0

For the fourth quarter of 2015, royalties were $12.1 million, a decrease of 25 percent primarily due to low commodity 
prices and incentive programs for new wells. The average royalty rate as a percentage of revenues was 7 percent. For 
the year ended December 31, 2015, royalties were $57.9 million, an increase of 12 percent, attributable to higher 
revenues. The Company’s annual royalty rate was 10 percent, consistent with 2014.

In September 2015, the Alberta government initiated a royalty review. On January 29, 2016, the recommendations of the 
Royalty Review Advisory Panel were finalized and are expected to create a simpler, more transparent and efficient 
system. The provincial government of Alberta has not yet released all of the details of the Modernized Royalty 
Framework. The Company will continue to evaluate the impact of the new framework on the results of operations and 
cash flows as more details are released.

Other Income

($ thousands, except per boe data)

Marketing revenue

Interest and other income

Processing and third party income

Total

Per boe

Three months ended December 31

Year ended December 31

2015

1,300

879

691

2,870

0.40

2014

% Change

-

1,264

704

1,968

0.21

nm

(30)

(2)

46

90

2015

1,300

4,877

1,837

8,014

0.36

2014

% Change

-

3,184

1,803

4,987

0.44

nm

53

2

61

(18)

Marketing revenue was $1.3 million for the fourth quarter and year ended December 31, 2015. The Company earns a 
margin from optimizing its capacity on the Alliance Pipeline. 

For the fourth quarter of 2015, interest and other income was $0.9 million, a decrease of 30 percent due to lower 
average cash balances and lower interest rates. In 2015, the Company drew down funds from an initial public offering 
(“IPO”) financing, which closed in November 2014. For the year ended December 31, 2015, interest and other income was 
$4.9 million, an increase of 53 percent, due to higher average cash balances attributable to the issuance of $550.1 million 
of senior notes in April 2015.

Third party processing fees and volumes during the year have been consistent from 2014 to 2015.

SEVEN GENERATIONS 2015 ANNUAL REPORT31

Operating Expenses

($ thousands, except per boe data)

Equipment rental, maintenance and other

Trucking and disposal

Chemicals and fuel

Staff and contractor costs

Other

Operating expenses

Operating expenses per boe

Three months ended December 31

Year ended December 31

2015

8,468

8,993

5,253

4,965

1,699

29,378

4.11

2014

% Change

5,667

6,033

1,360

3,791

2,115

18,966

4.67

49

49

286

31

(20)

55

(12)

2015

31,413

30,510

15,008

15,981

8,276

101,188

4.59

2014

% Change

20,584

15,339

3,438

9,474

5,426

54,261

4.77

53

99

337

69

53

86

(4)

For the fourth quarter of 2015, operating expenses were $29.4 million, an increase of $10.4 million due to higher field 
activity and the operation of the new Lator 2 natural gas plant. In October, the Lator 2 natural gas plant came on stream 
six weeks ahead of schedule. Lator 2 delivers liquids-rich natural gas on the Alliance Pipeline to sell into the US Midwest 
market. For the year ended December 31, 2015, operating expenses were $101.2 million compared to $54.3 million for the 
comparative period in 2014. The difference was due to higher production and field activity, with 61.0 net new wells on 
production in 2015 compared to 33.7 net wells for the same period of 2014. Operating expenses, on a per boe basis, are 
decreasing due to increased volumes and operating efficiencies.

Transportation Expenses

($ thousands, except per boe data)

Transportation expense

Transportation expense per boe

Three months ended December 31

Year ended December 31

2015

23,984

3.36

2014

% Change

13,237

3.26

81

3

2015

60,336

2.74

2014

% Change

34,833

3.06

73

(10)

Transportation expenses were $24.0 million for the fourth quarter of 2015, an increase of $10.8 million. On December 1, 
2015, the Company began shipping liquids-rich natural gas directly to the Chicago Citygate market. Transportation 
expenses include condensate and NGL pipeline tariffs and trucking as well as natural gas pipeline tariffs charged prior to 
the custody transfer point. For the year ended December 31, 2015, transportation expenses were $60.3 million, an 
increase of $25.5 million, primarily due to higher volumes. Condensate volumes are shipped via firm and interruptible 
pipeline capacity. Additionally, a portion of the produced volumes are trucked to various terminals.

General and Administrative Expenses

Three months ended December 31

Year ended December 31

2014

% Change

($ thousands, except per boe data)

Personnel

Professional fees

Rent

Information technology costs

Other office costs and travel

IPO expenses

Gross expenses

Capitalized salaries and benefits

Operating overhead recoveries

General and administrative expenses

Per boe – net

2015

4,575

317

388

935

1,544

-

7,759

(221)

(410)

7,128

1.00

2014

3,571

386

390

325

1,143

2,506

8,321

(523)

(405)

7,393

1.82

% Change

28

(18)

(1)

188

35

(100)

(7)

(58)

1

(4)

(45)

2015

18,844

1,780

1,584

2,347

5,161

-

29,716

(3,619)

(1,754)

12,912

2,636

1,210

1,310

3,403

2,506

23,977

(2,661)

(1,058)

24,343

20,258

1.10

1.78

46

(32)

31

79

52

(100)

24

36

66

20

(38)

Gross general and administrative expenses were $7.8 million for the fourth quarter of 2015. The decrease of $0.6 million 
compared to 2014 was due to $2.5 million of savings of one-time IPO expenses offset by higher personnel costs related 
to higher employee head count and the Company’s expanding activities. On a unit of production basis, net general and 
administration expenses were $1.00/boe, a decrease of 45 percent, due to higher production levels.

For the year ended December 31, 2015, gross general and administrative expenses were $29.7 million, an increase of  
$5.7 million, attributable to the Company’s growth, higher staff costs and more office space. The Company’s head count 
increased by 39 percent from 75 personnel at the end of 2014 to 104 at December 31, 2015.

SEVEN GENERATIONS 2015 ANNUAL REPORT32

For the three months and year ended December 31, 2015, capitalized staff costs were $0.2 million and $3.6 million 
compared to $0.5 million and $2.7 million, respectively for the same periods in 2014. Capitalized staff costs are 
attributable to head office personnel involved with the capital and infrastructure development of the Project. 

Overhead recoveries were $0.4 million and $1.8 million compared to $0.4 million and $1.1 million for the three months and 
year ended December 31, 2015 and 2014, respectively. Overhead recoveries relate to spending incurred on properties 
with minority partners. 

Depletion, Depreciation and Amortization

($ thousands, except per boe data)

Depletion, depreciation & amortization

Per boe

2015

80,337

11.24

2014

% Change

56,923

14.01

41

(20)

2015

283,535

12.86

2014

% Change

159,447

14.03

78

(8)

Three months ended December 31

Year ended December 31

For the fourth quarter of 2015, depletion, depreciation and amortization expense was $80.3 million compared to $56.9 million 
for the same period in 2014. The difference is mostly due to higher production volumes and higher depreciable costs. For 
the year ended December 31, 2015, depreciation and amortization expense was $283.5 million compared to $159.4 million 
in 2014. The increase is consistent with the higher production volumes. Depletion per barrel decreased due to decreases 
in estimated future development costs. 

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

2015

4,589

(1,377)

3,212

2014

6,060

(2,163)

3,897

% Change

(24)

(36)

(18)

2015

20,014

(6,027)

13,987

2014

% Change

18,012

(6,062)

11,950

11

(1)

17

Stock based compensation is a non-cash expense. The fair value of stock based compensation is calculated using the 
Black-Scholes pricing model using estimates including the expected life of the instruments, stock price volatility and 
interest rates. 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.

For the fourth quarter of 2015, gross stock based compensation was $4.6 million, a decrease of $1.5 million, due to more 
stock option grants in 2014 and a higher value per award in 2014. For the year ended December 31, 2015, gross stock 
based compensation expense was $20.0 million, an increase of 11 percent, due to awards granted to new employees in 
2015 and 2014. 

For the three months and year ended December 31, 2015, capitalized stock based compensation was $1.4 million and 
$6.0 million, compared to $2.2 million and $6.1 million, respectively for the same periods in 2014. Capitalized stock based 
compensation is attributable to personnel involved with the capital and infrastructure development of the Project. 

Finance Expense

($ thousands)

Interest on senior notes

Revolving credit facility fees and other

Amortization of premium and debt  

issue costs

Accretion

Total finance costs

Capitalized borrowing costs

Finance expense

Three months ended December 31

Year ended December 31

2015

29,232

1,798

181

495

31,706

(2,167)

29,539

2014

% Change

16,543

857

(114)

272

17,558

(500)

17,058

77

110

(259)

82

81

100

73

2015

98,887

5,512

356

1,662

106,417

(4,406)

102,011

2014

% Change

61,303

2,142

(466)

1,162

64,141

(500)

63,641

61

157

(176)

43

66

100

60

In April 2015, the Company issued US$425.0 million of additional senior notes bearing interest at 6.75 percent with a 
2023 maturity. Net proceeds from the financing were $504.4 million. In May 2013 and February 2014, the Company 
issued senior unsecured notes of US$400.0 million and US$300.0 million (US$321.0 million with premium), respectively. 
The notes bear interest at 8.25 percent per annum (calculated using a 360-day year).

SEVEN GENERATIONS 2015 ANNUAL REPORT 
33

Interest expense on senior notes for the fourth quarter of 2015 was $29.2 million (US$21.6 million) compared to $16.5 million 
(US$14.4 million) for the same period in 2014. Interest expense is recorded in Canadian dollars using average monthly 
exchange rates and as such, the weakening Canadian dollar increased interest expense from the US denominated senior 
notes. The standby fees and other charges associated with the Company’s revolving credit facility increased to $1.8 million 
for the three months ended December 31, 2015 compared to $0.9 million in the same period of 2014.

For the year ended December 31, 2015, the Company recorded interest expense of $98.9 million (US$55.1 million) 
compared to $61.3 million (US$46.4 million) in 2014. Interest expense was higher due to the increase in the average debt 
balance outstanding and the weaker Canadian dollar in 2015. The revolving credit facility and other fees were $5.5 million, 
an increase of $3.4 million, due to standby fees being calculated on a larger borrowing base. The borrowing capacity on 
the available credit facility increased from $150.0 million in 2013 to $480.0 million in September 2014, to $650.0 million in 
April 2015 and to $850.0 million in November 2015.

For the fourth quarter and year ended December 31, 2015, the Company capitalized interest and financing costs of  
$2.2 million and $4.4 million, respectively, related to the Cutbank natural gas plant.

Foreign Exchange Loss (Gain)

($ thousands, except per exchange rates)

2015

2014

% Change

2015

2014

% Change

Three months ended December 31

Year ended December 31

Unrealized foreign exchange loss on  
  senior notes

Unrealized foreign exchange loss (gain) on  
  cash held in foreign currencies

Realized foreign exchange loss (gain)

Net foreign exchange loss

Average exchange rate – C$ to US$

53,941

27,562

96

228,863

53,406

5,111

(3,553)

55,499

0.749

(7,336)

5,334

25,560

0.881

(170)

(167)

117

(15)

(1,094)

(8,468)

219,301

0.729

(3,095)

(2,638)

47,673

0.914

329

(65)

221

360

(14)

For the three months ended December 31, 2015, the unrealized foreign exchange losses were $53.9 million, an increase 
of $26.3 million, due to the weaker Canadian dollar, which decreased by 15 percent quarter over quarter. The Company’s 
exposure to foreign exchange gains and losses is primarily related to the US dollar senior unsecured notes, as well as  
US dollar cash balances.

The average exchange rate for Canadian dollars to the US dollar equivalent for the year ended December 31, 2015 fell to 
0.749 This 14 percent decline impacted total unrealized foreign exchange losses which were $228.9 million for 2015. The 
unrealized foreign exchange losses largely relate to the senior notes. The senior notes mature in 2020 (US$700.0 million) 
and 2023 (US$425.0 million), respectively. 

Realized foreign exchange gains and losses relate to the actual conversion of US dollars to Canadian dollars and the 
settlement of normal revenues and invoices denominated in US dollars. Total realized foreign exchange gains were  
$8.5 million for the year ended December 31, 2015.

Gain on Disposition of Assets

($ thousands)

Gain on disposition of assets

2015

-

2014

% Change

-

nm

2015

2,602

2014

4,286

% Change

(39)

Three months ended December 31

Year ended December 31

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. For the year ended December 31, 2015, the Company recorded a gain of $2.6 million 
compared to $4.3 million in the same period of 2014.

Income Tax Expense

($ thousands)

Current income tax expense

Deferred income tax expense

Three months ended December 31

Year ended December 31

2015

104

45,655

45,759

2014

% Change

_

39,532

39,532

nm

15

16

2015

104

61,802

61,906

2014

% Change

-

71,508

71,508

nm

(14)

(13)

SEVEN GENERATIONS 2015 ANNUAL REPORT34

For the three months ended December 31, 2015, the Company recorded income tax expense of $45.8 million. Of this 
amount, $45.7 million was recorded as deferred income tax expense mostly related to the derecognition of approximately 
$22.6 million of tax pools and unrecognized deferred tax asset related to unrealized capital losses. During the year ended 
December 31, 2015, the Canada Revenue Agency (“CRA”) challenged tax losses utilized by the Company which were 
derived from the Company’s predecessor entity, IceFyre Semiconductor Corporation. As a result of the ongoing CRA 
audit, the Company has applied a provision of $22.6 million against the tax pools. 

Permanent differences such as unrealized foreign exchange losses of $8.0 million, change in unrecognized deferred tax 
asset of $8.2 million on unrealized capital losses and stock based compensation of $0.8 million also impacted the 
deferred income tax provision.

For the year ended December 31, 2015, the Company recognized an income tax expense of $61.8 million, a decrease of  
14 percent, due to the permanent differences and an increase in the tax rate to 26 percent from 25 percent, to reflect 
the recent change to provincial tax rates. Permanent differences included stock based compensation, a non-deductible 
expense, and foreign exchange gains or losses relating to the senior notes, which are one-half taxable or deductible. 
These impacted the deferred income tax provision by $3.6 million and $29.2 million, respectively. The change in tax rate 
increased deferred income taxes by $6.9 million. Also impacting the deferred income tax expense for the year ended 
December 31, 2015 was an unrecognized deferred tax asset on capital losses of $31.6 million.

The Company recorded $0.1 million of current income tax expense for estimated taxes payable in the US and state of 
Illinois, where Seven Generations (US) Corp. commenced selling natural gas to third parties in December 2015.

The Company has no current income tax expense in Canada given its total tax pools of $2.7 billion at December 31, 2015. 
Of this amount, $0.7 billion is available in 2015 for deduction in computing taxable income.

Capital Investments

($ thousands)

Land acquisitions

Drilling and completions

Facilities and equipment

Other (1)

Total capital investments

Property dispositions

Three months ended December 31

Year ended December 31

2015

2,169

181,108

114,153

3,719

2014

8,200

225,150

134,177

2,793

301,149

370,320

-

-

% Change

(74)

(20)

(15)

33

(19)

-

2015

5,138

810,185

477,958

15,692

48,952

737,704

324,602

9,078

1,308,973

1,120,336

-

(9,420)

2014

% Change

(90)

10

47

73

17

(100)

18

Capital investments, net of dispositions

301,149

370,320

(19)

1,308,973

1,110,916

(1)  Other includes capitalized salaries and benefits, capitalized interest and office investments.

For the fourth quarter of 2015, the Company invested $301.1 million in the core focus area at Kakwa. Of this amount, 
$181.1 million was invested for drilling and completions. The Company drilled 22.0 net wells and completed 13.0 net wells. 
The average lateral length of wells completed was approximately 2,712 metres and an average proppant density of 
approximately 1.8 tonnes per meter was used in the completion of the wells. Drilling and completion costs for the fourth 
quarter of 2015 averaged $12.5 million per well. The Company also brought 11.0 net wells on production, contributing to 
the record production levels in the last quarter of 2015. Investments for facilities, infrastructure and equipment for the 
fourth quarter of 2015 were $114.2 million. The Company completed the construction and commissioning of the Lator 2 
plant six weeks early. The Lator plant complex, with a processing capacity of approximately 260 MMcf/d, came on-line 
and liquids-rich natural gas was transported under the Company’s firm service agreements with Alliance beginning on 
December 1, 2015. The construction of the Cutbank gas plant, with a planned capacity of 250 MMcf/d, was 75 percent 
complete as at December 31, 2015 and is expected to be operational in the second quarter of 2016. The Cutbank sales 
pipeline, connecting the Cutbank plant with the Alliance Pipeline, is a 29 km, 24” pipeline currently being constructed and 
expected to be completed at the same time as the plant.

In November 2014, the Board approved a 2015 capital investment program of $1.6 billion to $1.65 billion. In February 2015, 
the Company updated its business plan in response to persisting low commodity prices and announced a revised 
investment plan of $1.30 billion to $1.35 billion. For the year ended December 31, 2015, Seven Generations invested  
$1.31 billion of capital, which was at the low end of the Company’s guidance primarily due to the Company’s ongoing 
focus on innovation and differentiation which resulted in improved operational efficiencies and cost savings.

Of the total capital investments made for the year, $810.2 million was invested in drilling and completions. The Company 
drilled 83.0 net wells and completed 57.5 net new wells in 2015. Drilling cost per well was approximately $5.0 million. The 
number of days between spud to rig release time was reduced to an average of 44 days resulting in significant cost 
savings. Improving completions efficiencies resulted in an average per well cost of $6.8 million as the Company focused 
on optimizing fracture stage spacing, expanding the use of hydraulic fracturing and testing higher proppant density on 

SEVEN GENERATIONS 2015 ANNUAL REPORTwells. Investments of $478.0 million for facilities included both the expansion of existing and the construction of new 
processing and gathering facilities and Super Pads. Since 2013, the Company has drilled multiple wells from single pads 
and then added onsite separation to create Super Pads. To date, the Company has constructed and commissioned six 
Super Pads, with more Super Pads under construction that are expected to be commissioned in 2016. Two natural gas 
plants were under construction in 2015, with Lator completed in October 2015 and Cutbank scheduled for operation in 
the second quarter of 2016.

Seven Generations controls approximately 416,000 net acres of Montney land (over 431,000 net acres of lands overall) 
with an average working interest of 98 percent. At December 31, 2015, McDaniel estimated the Company’s Montney land 
to support approximately 693 net wells (83 percent undrilled), which have gross 2P reserves of 859 MMboe.

35

Liquidity and Capital Resources

The capital structure of the Company is as follows:

($ thousands)

Net debt (1)

Market capitalization (2)

Total capitalization

(1)  See “Non-IFRS Financial Measures”.

As at December 31

2015

1,250,857

3,429,540

4,680,397

2014

158,270

4,291,692

4,449,962

(2)   Market capitalization is calculated using the total common shares outstanding at December 31, 2015 multiplied by the closing share price of $13.48 

at December 31, 2015 (closing share price of $17.50 at December 31, 2014).

The Company’s objective for managing capital continues to be a focus on a strong balance sheet, the drive toward free 
cash flow and optimizing its capital base to provide financial flexibility for continued 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.

At December 31, 2015, the Company had cash and cash equivalents of approximately $405.0 million and adjusted 
working capital of $306.1 million. In April, the Company completed a private placement offering of US$425.0 million of 
senior notes, bearing interest at 6.75 percent, which mature in 2023. Net proceeds from this debt financing were  
$545.7 million. The Company also has US$700 million of senior notes outstanding, bearing interest at 8.25 percent, 
which mature in 2020. All of the senior notes the Company has issued are denominated in US dollars. The decline of the 
Canadian dollar increases the amount of senior notes outstanding recognized at December 31, 2015. 

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; transfer assets; and engage in 
amalgamations, mergers or consolidations. At December 31, 2015 and 2014, the Company was in compliance with the 
covenants on the senior notes. 

The Company and its lending syndicate agreed to an amendment to the senior secured revolving credit arrangement 
that increased the borrowing capacity from $480.0 million at December 31, 2014 to $650.0 million in May 2015 and 
$850.0 million in November 2015. 

In February 2016, the Company completed a private placement of 21,428,600 Common Shares at a price of $14.00 per 
share for gross proceeds of $300 million.

At December 31, 2015, the Company had available funding of $1.1 billion. The Company’s capital investments for 2016 are 
expected to be between $900 million and $950 million. The 2016 capital investment program will continue to focus 
development of the Nest. Seven Generations plans to fund capital investments in 2016 from cash on hand, funds from 
operations and prudent draws from its revolving credit facility.

Subsequent Event

On February 24, 2016, the Company completed a private placement of 21,428,600 Common Shares at a price of $14.00 per 
share for gross proceeds of approximately $300 million. Net proceeds after commissions and expenses were approximately 
$285 million.

SEVEN GENERATIONS 2015 ANNUAL REPORT36

Financial Instruments and Risk Management Contracts

Financial Instrument Classification and Measurement

The Company’s financial instruments include cash and cash equivalents, 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 and risk management contracts. 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 are classified as Level 1 measurements. Risk management contracts 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, 2015 and 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

  Risk management contracts

Other Financial Liabilities

2015

2014

Carrying value

Fair value

Carrying value

Fair value

405,046

151,566

76,439

8,933

405,046

151,566

76,439

8,933

848,136

139,119

64,417

5,034

848,136

139,119

64,417

5,034

28,359

28,359

-

-

  Accounts payable and accrued liabilities

  Senior notes

187,760

1,546,761

187,760

1,353,953

268,108

813,880

268,108

782,000

SEVEN GENERATIONS 2015 ANNUAL REPORTFinancial 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:

37

As at December 31, 2015

Risk management contracts

  Current asset

  Long-term asset

  Current liability

  Long-term liability

Net position

As at December 31, 2014

Risk management contracts

  Current asset

  Long-term asset

Net position

Credit 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

102,343

62,939

(22,093)

(19,982)

123,207

(3,773)

(9,943)

3,773

9,943

-

98,570

52,996

(18,320)

(10,039)

123,207

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

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 mitigates 
concentration risk by limiting the sales of its production to customers, and reviews sales regularly. Production is sold to 
marketers and customers 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, 2015, 
the Company’s most significant marketer accounted for $20.2 million (2014 – $21.1 million) of total receivables and  
47 percent of total revenues (2014 – 50 percent). 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, 2015, receivables outstanding for more than 90 days totalled less than 
$0.5 million (2014 – $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 government owned financial 
institutions 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 these financial institutions to be 
remote. As at December 31, 2015, 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. 

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38

Market Risk

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.

Risk Management Contracts

The following is a summary of the carrying value of risk management contracts in place by contract type:

As at December 31

  Natural gas

  Oil

  Foreign exchange

Net position

2015

58,087

93,478

(28,358)

123,207

2014

29,548

109,571

-

139,119

During the year ended December 31, 2015, the Company’s risk management contracts resulted in realized gains of  
$150.6 million (year ended December 31, 2014 – realized gains of $9.7 million) and unrealized losses of $15.9 million  
(year ended December 31, 2014 – unrealized gains of $141.8 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, 2015:

10% increase in US$ Chicago Citygate/MMbtu

10% decrease in US$ Chicago Citygate/MMbtu

10% increase in US$ WTI/bbl

10% decrease in US$ WTI/bbl

(b)  Interest Rate Risk

Gain (Loss)

(33,620)

33,620

(68,583)

80,485

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 the year ended December 31, 2015, 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 liquids and natural gas sales.

The Company manages foreign currency exchange risk by entering into a variety of risk management contracts (see Risk 
management contracts section above). The Company enters into US dollar swaps to crystallize the Canadian dollar value 
of the oil or natural gas price risk management contract entered into.

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 and cash equivalent balances held in US dollars. Foreign currency risk associated with 
interest payments is partially offset by marketing arrangements for the sale of the Company’s natural gas and natural 
gas liquids, excluding condensate, which are denominated in US dollars.

SEVEN GENERATIONS 2015 ANNUAL REPORT39

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 (including the foreign exchange risk management contract) 
December 31, 2015:

10% increase in US$ to C$

10% decrease in US$ to C$

Gain (Loss)

181,617

(212,491)

The carrying amount of the Company’s US dollar denominated monetary assets and liabilities as at December 31 was  
as follows:

As at December 31

Assets

Liabilities

Liquidity Risk

2015

35,545

1,563,829

2014

78,042

822,573

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, 
2015, the Company had $405.0 million of cash and cash equivalents plus available credit facility of $812.0 million. 
Management believes it has sufficient funding to meet foreseeable liquidity requirements. The Company prepares  
capital expenditure budgets which are regularly monitored and updated. As well, the Company utilizes authorizations for 
investments on both operated and non-operated projects to manage capital investments. See Note 24 Subsequent Event.

The following are the contractual maturities of financial liabilities at December 31, 2015:

Less than 1 year

2-3 years

4-5 years

Thereafter

Accounts payable and accrued liabilities

Senior notes (1)

Interest on senior notes (1)

Total

187,760

-

119,630

307,390

-

-

358,890

358,890

-

968,800

109,380

1,078,180

Total

187,760

-

588,200

1,557,000

52,939

641,139

640,839

2,385,599

(1)  Balances denominated in US dollars have been translated at the December 31, 2015, Canadian dollar to US dollar exchange rate of 0.723.

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, 2015:

($ thousands)

Senior notes (1)

Interest on senior notes

Firm transportation and  
  processing agreements (2)

Operating leases (3)

Deferred obligation and retention (4)

Less than  

1 year

1-3 years

4-5 years

Thereafter

Total

1,557,000

640,839

-

-

119,630

358,890

1,993,633

220,331

780,243

12,800

2,748

2,380

2,748

5,319

0

968,800

109,380

556,055

2,583

-

588,200

52,939

437,004

2,518

-

Estimated contractual obligations

4,207,020

345,089

1,144,452

1,636,818

1,080,661

(1)  Balance represents US$1.1 billion 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.

(4)   In November 2014, the Board of Directors approved a retention bonus plan for management and employees in aggregate of $6.0 million, payable over 

the two-year period starting November 5, 2014. Of this amount, $2.7 million is payable in 2016.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
40

Off-balance Sheet Arrangements

The Company has certain fixed lease arrangements which were entered into in the normal course of operations. All 
material leases are classified as 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 consolidated 
financial statements of the Company. No asset or liability has been recorded for these leases on the balance sheet at 
years ended December 31, 2015 and 2014.

The Company did not have any physical delivery contracts outstanding at December 31, 2015 and 2014.

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 at March 8, 2016, Seven Generations had 
275,913,180 Class A Common Voting Shares, Nil Class B Common Non-Voting Shares, 12,019,250 stock options,  
18,417,414 performance warrants, 154,698 PSUs, 271,848 RSUs and 55,176 DSUs outstanding. 

The vesting of PSUs are conditional on the satisfaction of certain performance criteria as determined by the Company’s 
Board of Directors. If the Company satisfies the performance criteria, PSUs become eligible to vest and a pre-determined 
multiplier is applied to eligible PSUs. The Company has used an adjustment factor of 1.0, which assumes that the 
Company will be within the 50 percent percentile of its relative peer group, based on total shareholder return at the 
respective vesting dates.

Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of Disclosure in 
Issuers’ Annual and Interim Filings, are designed to provide reasonable assurance that information required to be 
disclosed in the Company’s annual filings, interim filings or other reports filed or submitted by the Company under 
securities legislation is recorded, processed, summarized and reported within the time periods specified under securities 
legislation and include controls and procedures designed to ensure that information required to be so disclosed is 
accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as 
appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and the Chief Financial 
Officer of Seven Generations evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on 
that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that Seven Generations’ DC&P were 
effective as at December 31, 2015.

Internal Control over Financial Reporting

Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those policies and 
procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect 
transactions and dispositions of assets of Seven Generations; (ii) are designed to provide reasonable assurance that 
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally 
accepted accounting principles and that receipts and expenditures of Seven Generations are being made in accordance 
with authorizations of management and Directors of Seven Generations; and (iii) are designed to provide reasonable 
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s 
assets that could have a material effect on the financial statements.

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for 
Seven Generations. For the year ended December 31, 2015, they have designed ICFR, or caused it to be designed under 
their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of 
financial statements for external purposes in accordance with IFRS. The control framework used to design the 
Company’s ICFR is the framework in Internal Control – Integrated Framework (2013) issued by the Committee of 
Sponsoring Organizations of the Treadway Commission.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Seven Generations conducted an 
evaluation of the effectiveness of the Company’s ICFR as at December 31, 2015. Based on this evaluation, the officers 
concluded that as of December 31, 2015, Seven Generations maintained effective ICFR. It should be noted that while 
Seven Generations’ officers believe that the Company’s controls provide a reasonable level of assurance with regard to 
their effectiveness, 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.

There were no changes during the period beginning on October 1, 2015 and ended on December 31, 2015 that have 
materially affected, or are reasonably likely to materially affect, Seven Generations’ ICFR.

SEVEN GENERATIONS 2015 ANNUAL REPORT41

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 consolidated 
financial statements for the year ended December 31, 2015. The preparation of consolidated 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 
consolidated financial statements, refer to Note 5 “Significant Accounting Judgments, Estimates and Assumptions” in 
the audited consolidated financial statements for the year ended December 31, 2015.

Risk Assessment

The acquisition, exploration and development of oil and natural gas properties and the production, transportation and 
marketing of oil and natural gas involves 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 risks include, but are not limited to the following:

 Volatility in market prices and demand for oil, NGLs 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;

 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 rescission, or amendment to the conditions of, groundwater licenses of the Company; 

 Management of the Company’s growth; 

 The ability to successfully identify and make attractive acquisitions, joint ventures or investments, or successfully 

integrate future acquisitions or businesses; 

 The availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel;

 Adoption or modification of climate change legislation by governments; 

SEVEN GENERATIONS 2015 ANNUAL REPORT42

 The absence or loss of key employees; 

 Uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources 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;

 The ability to satisfy obligations under the Company’s firm commitment transportation arrangements;

 The uncertainties related to the Company’s identified drilling locations; 

 The high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; 

 Operating hazards and uninsured risks; 

 The possibility that the Company’s drilling activities may encounter sour gas;

 Execution of the Company’s business plan;

 Failure to acquire or develop replacement reserves;

 The concentration of the Company’s assets in the Kakwa River Project area;

 Unforeseen title defects;

 Aboriginal claims;

 Failure to accurately estimate abandonment and reclamation costs; 

 Development and exploratory drilling efforts and well operations may not be profitable or achieve the targeted return; 

 Horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves  

or production; 

 Limited intellectual property protection for operating practices and dependence on employees and contractors;

 Third-party claims regarding the Company’s right to use technology and equipment; 

 Expiry of certain leases for the undeveloped leasehold acreage in the near future; 

 Failure to realize the anticipated benefits of acquisitions or dispositions; 

 Failure of properties acquired now or in the future to produce as projected and inability to determine reserve and resource 
potential, identify liabilities associated with acquired properties or obtain protection from sellers against such liabilities; 

 Governmental regulations; 

 Changes in the interpretation and enforcement of applicable laws and regulations; 

 Environmental, health and safety requirements;

 Restrictions on drilling intended to protect certain species of wildlife; 

 Potential conflicts of interests; 

 Actual results differing materially from management estimates and assumptions; 

 Seasonality of the Company’s activities and the Canadian oil and gas industry; 

 Weather related risks, fires and natural disasters;

 Alternatives to and changing demand for petroleum products; 

 Extensive competition in the Company’s industry;

 Changes in the Company’s credit ratings;

 Third-party credit risk;

SEVEN GENERATIONS 2015 ANNUAL REPORT43

 Dependence upon a limited number of customers;

 Lower oil, NGLs and natural gas prices and higher costs; 

 Terrorist attacks or armed conflict; 

 Loss of information and computer systems; 

 Inability to dispose of non-strategic assets on attractive terms; 

 Security deposits may be required under provincial liability management programs; 

 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 of litigation; 

 Variation in future calculations of non-IFRS measures; 

 Sufficiency of internal controls; 

 Third-party breach of agreements; 

 Impact of expansion into new activities on risk exposure; 

 Inability of the Company to respond quickly to competitive pressures; and

 Risks related to the common shares that are publicly traded and the senior notes and other indebtedness. 

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

There were no material new or amended accounting standards adopted during the year ended December 31, 2015.

Future Accounting Policy Changes

In February 2014, the International Accounting Standards Board (“IASB”) issued IFRS 9 “Financial Instruments”, which 
replaces IAS 39, “Financial Instruments: Recognition and Measurement” for annual periods beginning on or after January 1, 
2018, with earlier adoption permitted. IFRS 9 includes a principle-based approach for classification and measurement of 
financial assets, a single ‘expected loss’ impairment model and a substantially-reformed approach to hedge accounting. 
The impact of the standard on the Company’s financial statements is currently being evaluated.

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. In July 2015, the IASB issued an amendment to IFRS 15, deferring 
the effective date by one year. IFRS 15 provides clarification for recognizing revenue from contracts with customers  
and establishes a single revenue recognition and measurement framework. The standard is required to be adopted  
either retrospectively or using a modified transition approach for annual periods beginning on or after January 1, 2018, 
with earlier adoption permitted. The Company is currently evaluating the impact of the standard on the consolidated 
financial statements.

In January 2016, the IASB issued IFRS 16 “Leases” which replaces IAS 17 “Leases” for annual periods beginning on or 
after January 1, 2019, with earlier application permitted if IFRS 15 “Revenue from Contracts with Customers” is also 
applied. Under IFRS 16, lessees are required to recognize a lease liability reflecting future lease payments and a ‘right-of-
use asset’ for virtually all lease contracts. The Company is currently evaluating the impact of the standard on the 
consolidated financial statements.

SEVEN GENERATIONS 2015 ANNUAL REPORT44

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”, “available funding” and 
“net debt”. 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 consolidated financial statements and the accompanying notes.

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. 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 expense

Changes in non-cash working capital

Funds from operations

Operating Income (Loss)

Three months ended December 31

Year ended December 31

2015

53,929

-

-

52,102

106,031

2014

% Change

2015

2014

% Change

80,667

-

35,947

(15,111)

101,503

(33)

(33)

-

(445)

4

380,117

301,909

-

-

34,492

414,609

206

35,947

(10,129)

327,933

26

(100)

(100)

(441)

26

“Operating income (loss)” 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 (loss) is 
defined as net income (loss), excluding realized foreign exchange gains and losses, unrealized gains and losses on risk 
management contracts and the respective income tax impact of these adjustments.

The following table reconciles the net income to operating income (loss):

($ thousands)

2015

2014

% Change

2015

2014

% Change

Net income (loss) for the period

(28,922)

68,628

(142)

(187,296)

144,200

(230)

Three months ended December 31

Year ended December 31

Unrealized loss – risk management  
  contracts (1)

(53,713)

(123,772)

Unrealized foreign exchange loss (gain) (2)

53,941

27,562

Gain on disposition of assets (3)

Liquidity expense

Deferred tax (recovery) expense relating  

to these adjustments

Operating income (loss)

-

-

14,503

(14,191)

-

35,947

26,450

34,815

(57)

96

-

(100)

(45)

(141)

15,911

228,863

(2,602)

-

(2,771)

52,105

(141,765)

53,406

(4,286)

35,947

32,019

119,521

(111)

329

(39)

(100)

(109)

(56)

(1)  Unrealized gains and losses on risk management contracts result from the fair market valuation of the hedge contracts as at December 31.

(2)   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. 

(3)  Non-recurring gain resulting from disposition of assets.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
45

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.

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:

As at December 31 ($ thousands)

Current assets

Current liabilities

Working capital

Adjusted for:

Current asset – risk management contracts

Current liability – risk management contracts

Current portion of deferred credits

Adjusted working capital

Credit facility capacity (1)

Available funding

2015

592,473

(206,203)

386,270

(98,570)

18,320

123

306,143

812,000

1,118,143

2014

1,060,030

(268,231)

791,799

(138,122)

-

123

653,800

480,000

1,133,800

(1)  Available credit facility capacity of $850.0 million less outstanding letters of credit of $38 million.

Net Debt

“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:

As at December 31 ($ thousands)

Senior notes at amortized cost

Less unamortized premium and debt issue costs

Senior notes principal

Adjusted for:

Adjusted working capital

Net debt

2015

1,546,761

10,239

1,557,000

(306,143)

1,250,857

2014

813,880

(1,810)

812,070

(653,800)

158,270

SEVEN GENERATIONS 2015 ANNUAL REPORT46

SELECTED QUARTERLY INFORMATION

($ thousands, except per share amounts,  
production rates and unit)

FINANCIAL

Total revenues

Realized hedging gain

Midstream revenue

Processing and third party income

Interest and other income

Royalties

Operating expenses

Transportation expenses

General and administrative

Interest expense

Foreign exchange loss

Other

Funds from operations (1)

Per share – diluted

Operating income (1)

Per share – diluted

Net loss

Per share – diluted

Capital investments:

  Land

  Drilling and completions

  Facilities and equipment

  Other

Total capital investments (before dispositions)

Total assets

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

  Oil and condensate ($/bbl)

  NGLs ($/bbl)

  Natural gas ($/Mcf)

OPERATING NETBACK (1)

Liquids and natural gas revenues

Realized hedging gain

Royalties

Operating expenses

Transportation expenses

Operating netback after hedging

(1) 

 See “Non-IFRS Financial Measures”.

Q4 2015

Q3 2015

Q2 2015

Q1 2015

YTD 2015

178,478

22,980

1,300

691

879

(12,127)

(29,378)

(23,984)

(7,128)

(29,105)

3,456

(31)

106,031

0.40

(14,191)

(0.06)

(28,922)

(0.11)

2,169

181,108

114,153

3,719

301,149

3,758,982

1,118,143

1,250,857

1,546,761

25,572

19,236

197

77,699

46.72

12.35

2.57

24.97

3.21

(1.70)

(4.11)

(3.36)

19.01

149,723

35,262

-

467

1,248

(17,704)

(26,819)

(13,493)

(5,450)

(28,211)

(98)

(31)

94,894

0.35

13,813

(0.21)

(53,726)

(0.21)

1,930

145,626

134,494

3,064

285,114

3,707,714

1,141,232

989,843

1,491,184

22,606

14,094

143

60,600

49.18

7.99

2.81

26.86

6.32

(3.18)

(4.81)

(2.42)

22.77

155,183

41,683

-

294

1,450

(12,886)

(23,537)

(9,893)

(5,136)

(24,946)

4,614

(31)

126,795

0.47

28,485

0.11

(21,950)

(0.09)

259

222,164

128,588

3,299

354,310

3,559,768

1,325,954

710,200

1,395,485

20,702

11,914

130

54,219

60.29

9.78

2.63

31.45

8.45

(2.61)

(4.77)

(2.00)

30.52

108,540

50,655

-

385

1,300

(15,181)

(21,454)

(12,966)

(6,629)

(17,973)

242

(30)

86,889

0.32

23,998

0.09

(82,698)

(0.34)

780

264,879

100,723

2,018

368,400

3,170,401

861,385

505,234

888,356

15,810

12,042

125

48,768

47.59

10.41

2.62

24.73

11.54

(3.46)

(4.89)

(2.95)

24.97

591,924

150,580

1,300

1,837

4,877

(57,898)

(101,188)

(60,336)

(24,343)

(100,235)

8,214

(123)

414,609

1.54

52,105

(0.07)

(187,296)

(0.75)

5,138

813,777

477,958

12,100

1,308,973

3,758,982

1,118,143

1,250,857

1,546,761

21,204

14,341

149

60,403

50.84

10.34

2.65

26.85

6.83

(2.63)

(4.59)

(2.74)

23.72

SEVEN GENERATIONS 2015 ANNUAL REPORTSELECTED QUARTERLY  
INFORMATION CONTINUED

47

($ thousands, except per share amounts,  
production rates and unit)

FINANCIAL

Total revenues

Realized hedging gain

Processing and third party income

Interest and other income

Royalties

Operating expenses

Transportation expenses

General and administrative

Interest expense

Foreign exchange (gain) loss

Other

Funds from operations (1)

Per share – diluted

Operating income (1)

Per share – diluted

Net income

Per share – diluted

Capital investments:

  Land

  Drilling and completions

  Facilities and equipment

  Other

Total capital investments (before dispositions)

Total assets

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

  Oil and condensate ($/bbl)

  NGLs ($/bbl)

  Natural gas ($/Mcf)

OPERATING NETBACK (1)

Liquids and natural gas revenues

Realized hedging gain

Royalties

Operating expenses

Transportation expenses

Operating netback after hedging

(1) 

 See “Non-IFRS Financial Measures”.

Q4 2014

Q3 2014

Q2 2014

Q1 2014

YE 2014

155,383

22,163

704

1,264

(16,145)

(18,966)

(13,237)

(7,393)

(16,905)

(5,334)

(31)

101,503

0.41

34,815

0.14

68,628

0.28

8,200

227,562

132,610

1,948

370,320

3,114,797

1,133,800

158,270

813,880

14,747

10,783

112

44,178

69.93

21.50

3.81

38.23

5.45

(3.97)

(4.67)

(3.26)

31.78

159,964

(148)

571

512

(20,925)

(14,245)

(7,277)

(4,457)

(16,037)

8,367

(31)

106,294

0.48

41,972

0.19

30,482

0.14

1,408

234,879

90,447

1,689

328,423

2,019,134

547,700

716,300

785,830

12,580

8,289

90

35,820

90.41

25.46

4.35

48.54

(0.04)

(6.35)

(4.32)

(2.21)

35.62

120,749

(6,873)

243

782

(9,434)

(9,659)

(7,693)

(5,233)

(16,262)

(618)

(30)

65,972

0.31

18,253

0.09

43,926

0.20

30,057

155,284

34,172

1,531

221,044

1,844,172

427,222

469,678

748,596

9,264

4,741

60

23,999

97.32

24.15

5.18

55.29

(3.15)

(4.32)

(4.42)

(3.52)

39.88

98,737

(5,405)

285

626

(5,386)

(11,391)

(6,626)

(3,175)

(13,746)

223

22

54,164

0.25

24,481

0.11

1,164

0.01

9,019

124,294

65,806

1,430

200,549

1,818,627

574,581

349,269

775,809

7,554

4,054

52

20,231

92.61

28.25

5.47

54.23

(2.97)

(2.96)

(6.26)

(3.64)

38.40

534,833

9,737

1,803

3,184

(51,890)

(54,261)

(34,833)

(20,258)

(62,950)

2,638

(70)

327,933

1.46

119,521

0.53

144,200

0.64

48,684

742,019

323,035

6,598

1,120,336

3,114,797

1,133,800

158,270

813,880

11,061

6,989

79

31,136

85.34

24.10

4.50

47.06

0.86

(4.57)

(4.77)

(3.06)

35.52

SEVEN GENERATIONS 2015 ANNUAL REPORT48

SELECTED QUARTERLY  
INFORMATION CONTINUED

($ thousands, except per share amounts,  
production rates and unit)

FINANCIAL

Total revenues

Realized hedging gain

Processing and third party income

Interest and other income

Royalties

Operating expenses

Transportation expenses

General and administrative

Interest expense

Foreign exchange (gain) loss

Other

Funds from operations (1)

Per share – diluted

Operating income (loss) (1)

Per share – diluted

Net income (loss)

Per share – diluted

Capital investments:

  Land

  Drilling and completions

  Facilities and equipment

  Other

Total capital investments (before dispositions)

Total assets

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

  Oil and condensate ($/bbl)

  NGLs ($/bbl)

  Natural gas ($/Mcf)

OPERATING NETBACK (1)

Liquids and natural gas revenues

Realized hedging gain

Royalties

Operating expenses

Transportation expenses

Operating netback after hedging

(1) 

 See “Non-IFRS Financial Measures”.

Q4 2013

Q3 2013

Q2 2013

Q1 2013

YE 2013

48,484

22,168

21,581

20,951

49

356

272

(3,188)

(8,425)

(3,286)

(2,052)

(8,970)

(133)

7

23,114

0.12

7,127

0.04

(5,625)

(0.03)

2,925

129,231

44,717

1,365

178,238

1,408,213

364,877

210,563

414,525

4,480

2,291

29

11,585

80.63

24.54

3.79

37.30

0.28

(3.78)

(6.27)

(1.58)

25.95

17

501

506

(2,227)

(4,502)

(962)

(2,006)

(8,691)

(24)

-

4,780

0.03

(8,053)

(0.05)

(955)

(0.01)

8,991

102,314

29,707

1,173

142,185

1,134,257

189,586

282,534

404,208

1,614

1,639

23

7,084

96.63

18.77

2.36

38.36

0.10

(0.56)

(7.41)

(2.35)

28.14

53

347

274

(318)

(4,168)

(1,326)

(2,175)

(5,051)

6

-

9,223

0.05

5,246

0.03

(8,454)

(0.05)

35,875

44,697

39,806

1,058

121,436

1,103,583

328,137

152,583

412,293

1,681

1,313

19

6,182

88.67

11.89

3.79

34.01

0.03

(3.42)

(6.91)

(1.48)

22.23

160

407

233

(2,120)

(3,520)

(887)

(1,884)

(194)

10

-

13,156

0.08

1,474

0.01

876

0.01

13,507

45,568

72,464

930

132,469

698,450

16,441

23,559

-

1,760

1,749

16

6,240

84.62

16.22

3.38

45.49

0.05

(2.99)

(7.90)

(3.09)

31.56

113,184

279

1,611

1,285

(7,853)

(20,615)

(6,461)

(8,117)

(22,906)

(141)

7

50,273

0.27

5,794

0.03

(14,158)

(0.08)

61,298

321,810

186,694

4,526

574,328

1,408,213

364,877

210,563

414,525

2,390

1,749

22

7,786

85.49

18.76

3.34

39.83

0.10

(2.76)

(7.25)

(2.28)

27.64

SEVEN GENERATIONS 2015 ANNUAL REPORT49

Forward-looking Information Advisory

This document contains certain forward-looking information and statements that involve 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: the level of growth that is expected; the Company’s ability to deliver on its growth objectives and meet the 
commitments in its marketing and transportation agreements; the Company’s hedging targets; the expectation that the 
Kakwa River Project will have low supply and break even costs relative to competing projects; the ability to generate 
long-life value from the Kakwa River Project; the continued focus on prudent, disciplined investment in long-term value 
creation; estimates of net present value of future net revenue from reserves; future wells or future drilling locations; the 
ability to achieve cash-flow self-sufficiency; the availability of relatively low-cost development opportunities and further 
opportunities that will maximize value for the Company’s stakeholders; expected capital investment in 2016; the 
expectation that the previously announced deferral of capital spending will not significantly impact 2016 production 
guidance; the expectation that funds from operations and available funding will support the Company’s ongoing capital 
investment program in 2016; anticipated production; the anticipated timing of the commissioning of the Cutbank plant; 
future price differentials; future processing and transportation capacity; anticipated rates of return; the impact that the 
Modernized Royalty Framework will have on the Company; the timing of the construction and commissioning of additional 
Super Pads; increased operational efficiency and maximization of recovery; expectations regarding the balancing of debt 
and equity in the Company’s capital structure; and the Company’s estimates of its future obligations under the heading 
“Contractual Obligations”. 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, NGLs and natural gas prices, including all adjustments for the quality of the Company’s 
production at the point of sale; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient 
manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the 
Company conducts its business and any other jurisdictions in which the Company may conduct its business in the 
future; 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 recovery and production of the Company’s 
reserves and resources; the recoverability of the Company’s reserves and resources; future capital investments to be 
made 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 and 
resources; the geography of the areas in which the Company is conducting exploration and development activities, and 
the access, economic, regulatory 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, NGLs 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; 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 rescission, or amendment to the conditions of, 
groundwater licenses of the Company; management of the Company’s growth; the ability to successfully identify and 
make attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions or businesses; 
the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; adoption or 
modification of climate change legislation by governments; the absence or loss of key employees; uncertainty associated 
with estimates of oil, NGLs and natural gas reserves and resources 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; the ability to satisfy obligations under the Company’s firm commitment transportation 
arrangements; the uncertainties related to the Company’s identified drilling locations; the high-risk nature of successfully 
stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured 
risks; the possibility that Company’s drilling activities may encounter sour gas; execution of the Company’s business 
plan; failure to acquire or develop replacement reserves; the concentration of the Company’s assets in the Kakwa River 
Project area; unforeseen title defects; Aboriginal claims; failure to accurately estimate abandonment and reclamation 
costs; development and exploratory drilling efforts and well operations may not be profitable or achieve the targeted 
return; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves 
or production; limited intellectual property protection for operating practices and dependence on employees and 

SEVEN GENERATIONS 2015 ANNUAL REPORT50

contractors; third-party claims regarding the Company’s right to use technology and equipment; expiry of certain leases 
for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or 
dispositions; failure of properties acquired now or in the future to produce as projected and inability to determine reserve 
and resource potential, identify liabilities associated with acquired properties or obtain protection from sellers against 
such liabilities; governmental regulations; changes in the interpretation and enforcement of applicable laws and 
regulations; environmental, health and safety requirements; restrictions on drilling intended to protect certain species of 
wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; 
seasonality of the Company’s activities and the Canadian oil and gas industry; weather related risks, fires and natural 
disasters; alternatives to and changing demand for petroleum products; extensive competition in the Company’s 
industry; changes in the Company’s credit ratings; third party credit risk; dependence upon a limited number of 
customers; lower oil, NGLs and natural gas prices and higher costs; terrorist attacks or armed conflict; loss of 
information and computer systems; inability to dispose of non-strategic assets on attractive terms; security deposits 
may be required under provincial liability management programs; 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; litigation; variation in future calculations of non-IFRS measures; sufficiency of internal 
controls; third-party breach of agreements; impact of expansion into new activities on risk exposure; inability of the 
Company to respond quickly to competitive pressures; risks related to the senior unsecured notes and other 
indebtedness, including potential inability to comply with the covenants in the credit agreement related to the 
Company’s credit facilities and/or the covenants in the indentures in respect of the senior secured notes.

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 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 as at December 31, 2015, are based upon the report that was prepared by McDaniel, evaluating the Company’s 
oil, natural gas and NGL reserves, dated March 7, 2016. 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 evaluation that was conducted by McDaniel, please refer to the AIF, 
which is available on the SEDAR website at www.sedar.com.

Oil and Gas Definitions

Terms that are used in this MD&A that are not otherwise defined herein are provided below:

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.

developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if 
facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a 
well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

SEVEN GENERATIONS 2015 ANNUAL REPORT51

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 the Company has an interest; and 

 In relation to properties, the total area of properties in which the 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.

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

bbl 

bbls 

barrel

barrels

boe (1)   

barrels of oil equivalent

CRA 

Canada Revenue Agency

C$ 

d 

km 

m 

Mcf 

Canadian dollars

day

kilometres

metres

thousand cubic feet

MMboe 

MMBtu 

MMcf   

Nest   

millions of barrels of oil equivalent

million British thermal units

million cubic feet

 means the primary development  
block of the Kakwa River Project

NGLs   

natural gas liquids

NGX 

nm 

NYMEX 

Opex   

US$ 

WTI 

$MM 

Natural Gas Exchange Inc.

not meaningful

New York Mercantile Exchange

operating expense

United States dollars

  West Texas Intermediate

millions of dollars

(1) 

 Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting natural gas to boes. Condensate and other NGLs are converted to boes 
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.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
52

INDEPENDENT AUDITOR’S REPORT

March 8, 2016
TO THE SHAREHOLDERS OF SEVEN GENERATIONS ENERGY LTD.
We have audited the accompanying consolidated financial statements of Seven Generation Energy Ltd. and its subsidiary, 
which comprise the consolidated balance sheet as at December 31, 2015 and the consolidated statement of income (loss) 
and comprehensive income (loss), statement of changes in equity and statement of cash flows for the year then ended, 
and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in 
accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, 
and for such internal control as management determines is necessary to enable the preparation of consolidated 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 consolidated 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 
consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated 
financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks 
of material misstatement of the consolidated 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 
consolidated 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 consolidated financial statements.

We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a basis for our 
audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of  
Seven Generations Energy Ltd. and its subsidiary as at December 31, 2015 and their financial performance and their cash 
flows for the year then ended in accordance with International Financial Reporting Standards as issued by the 
International Accounting Standards Board.

Other Matters

The financial statements of Seven Generations Energy Ltd. for the year ended December 31, 2014, were audited by 
another auditor who expressed an unmodified opinion on those statements on March 10, 2015.

Chartered Professional Accountants 
Calgary, Alberta

SEVEN GENERATIONS 2015 ANNUAL REPORTCONSOLIDATED BALANCE SHEETS

53

(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

  Accounts payable and accrued liabilities

  Risk management contracts

Risk management contracts

Senior notes

Deferred credits

Decommissioning liabilities

Deferred income taxes

Equity

Share capital

Contributed surplus

Retained earnings (Deficit)

Notes

2015

2014

6

19

19

7

9

19

19

10

11

12

13

405,046

76,439

98,570

12,418

592,473

52,996

3,109,503

4,010

3,758,982

187,883

18,320

206,203

10,039

1,546,761

850

79,109

129,370

1,972,332

1,775,673

61,810

(50,833)

1,786,650

3,758,982

848,136

64,417

138,122

9,355

1,060,030

997

2,049,760

4,010

3,114,797

268,231

-

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

Commitments and contingencies (Note 22) 

Subsequent event (Note 24)

See accompanying notes to the consolidated financial statements.

Approved by the Board of Directors

Dale Hohm 

Kent Jespersen

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
54

CONSOLIDATED STATEMENTS  
OF INCOME (LOSS) AND  
COMPREHENSIVE INCOME (LOSS)

(thousands of Canadian dollars, except per share amounts)

Year ended December 31

Revenues

  Liquids and natural gas sales

  Royalties

Risk management contracts

  Realized gain

  Unrealized gain (loss)

Other 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

  Current income tax expense

  Deferred income tax expense

Net income (loss) and comprehensive income (loss)

Net income (loss) per share

  Basic

  Diluted

See accompanying notes to the consolidated financial statements.

Notes

2015

2014

19

19

16

17

7

14

18

23

7

12

12

15

591,924

(57,898)

534,026

150,580

(15,911)

8,014

676,709

101,188

60,336

24,343

283,535

13,987

102,011

219,301

-

(2,602)

802,099

(125,390)

104

61,802

61,906

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

71,508

(187,296)

144,200

(0.75)

(0.75)

0.73

0.64

SEVEN GENERATIONS 2015 ANNUAL REPORTCONSOLIDATED STATEMENTS  
OF CHANGES IN EQUITY

55

(thousands of Canadian dollars)

Balance at December 31, 2013

Net income for the period

Issue of common shares

Share issue costs (net of deferred tax)

Stock based compensation

Exercise of stock options and  
  performance warrants

Balance at December 31, 2014

Net loss for the period

Tax rate change on share issue costs

Stock based compensation

Exercise of stock options and  
  performance warrants

Balance at December 31, 2015

Notes

13

13

14

13, 14

13

14

13, 14

Share
capital

790,064

-

931,500

(36,637)

Contributed
surplus

45,626

-

-

-

-

18,012

34,852

1,719,779

-

1,056

-

54,838

1,775,673

(8,954)

54,684

-

-

20,014

(12,888)

61,810

Retained
earnings  
(deficit)

(7,737)

144,200

-

-

-

-

Total

827,953

144,200

931,500

(36,637)

18,012

25,898

136,463

1,910,926

(187,296)

(187,296)

-

-

-

1,056

20,014

41,950

(50,833)

1,786,650

See accompanying notes to the consolidated financial statements.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
56

CONSOLIDATED STATEMENTS  
OF CASH FLOWS

(thousands of Canadian dollars)

Year ended December 31

Operating activities

  Net income (loss) for the period

Items not affecting cash:

  Deferred income tax expense

  Depletion, depreciation and amortization

  Unrealized (gain) loss on risk management contracts

  Stock based compensation

  Non-cash finance expenses

  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 shares for cash

Issue of shares on option exercises

  Share issue costs

Issue of debt

  Debt issue costs

  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

Unrealized foreign exchange gain on cash held in  

foreign currencies

Increase (decrease) in cash and cash equivalents

Cash and cash equivalents, beginning of year

Cash and cash equivalents, end of year

Supplementary disclosure of cash flow information (Note 21) 

See accompanying notes to the consolidated financial statements.

Notes

2015

2014

(187,296)

144,200

12

7

19

14

18

7

11

21

13

13

13

10

10

7

7

21

61,802

283,535

15,911

13,987

1,626

(2,602)

227,769

-

(123)

(34,492)

380,117

-

41,950

-

515,052

(11,329)

545,673

71,508

159,447

(141,765)

11,950

691

(4,286)

50,311

(206)

(70)

10,129

301,909

931,500

25,898

(48,849)

356,342

(9,840)

1,255,051

(1,308,973)

(1,120,336)

-

(61,001)

(1,369,974)

9,420

91,512

(1,019,404)

1,094

3,095

(443,090)

848,136

405,046

540,651

307,485

848,136

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
NOTES TO THE CONSOLIDATED  
FINANCIAL STATEMENTS

AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014 

(all tabular amounts in thousands of Canadian dollars, except share, per share and price information)

Financial Statement Note

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

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

Accounts payable and accrued liabilities

Senior notes

Decommissioning liabilities

Income taxes

Share capital

Stock based compensation

Per share amounts

16 Operating expenses

17

18

19

General and administrative expenses

Finance expense

Financial instruments and risk management contracts

20 Capital management

21

Supplemental cash flow information

22 Commitments and contingencies

23 Related party transactions

24 Subsequent event

57

Page

57

57

58

61

62

63

63

64

64

64

65

66

67

68

70

71

71

71

71

76

76

77

77

77

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’s Class A 
common shares are publicly traded on the Toronto Stock Exchange under the symbol “VII”.

2.  BASIS OF PREPARATION
These consolidated financial statements have been prepared in accordance with International Financial Reporting 
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

These consolidated financial statements have been prepared on a historical cost basis, except for certain financial 
instruments which are measured at fair value as explained in Note 18. The consolidated financial statements are 
presented in Canadian dollars, which is Seven Generations’ functional currency.

These consolidated financial statements include the accounts of Seven Generations and its wholly-owned subsidiary, 
Seven Generations (US) Corp. (“Seven Generations US”). All inter-entity transactions have been eliminated.

SEVEN GENERATIONS 2015 ANNUAL REPORT58

The preparation of the consolidated financial statements requires Management to use judgments, estimates and 
assumptions that affect the reported amounts of assets, liabilities and the disclosure of contingencies at the date of  
the financial statements, and revenues and expenses during the reporting period. Accordingly, actual results could differ 
from those estimated. Significant estimates and judgments used in the preparation of the financial statements are 
detailed in Note 5.

The consolidated financial statements were approved and authorized for issue by the Board of Directors (the “Board”) on 
March 8, 2016.

Certain comparative figures from prior periods have been reclassified to conform to the current year’s presentation. The 
current portion of deferred credits has been disclosed with Accounts Payable and Accrued Liabilities in Note 9.

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 proved and probable reserves and excludes the cost of assets not yet 
available for use. Tangible oil and natural gas assets, including natural gas plants, are depreciated on a straight-line basis 
over their estimated useful lives.

(b)  Exploration and Evaluation Assets

Exploration and evaluation (“E&E”) assets are those investments 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.

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 percent to 100 percent.

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.

SEVEN GENERATIONS 2015 ANNUAL REPORT59

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 or when indicators of impairment exist. 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.

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.

An impairment loss in respect of goodwill is not reversed. In respect of oil and natural gas assets, 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.

SEVEN GENERATIONS 2015 ANNUAL REPORT60

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.

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

Compensation cost attributable to stock options, performance warrants, deferred share units (“DSUs”) and performance 
and restricted share units (“PRSUs”) 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. Fair value is determined using the Black-Scholes option pricing model. A forfeiture rate is estimated on the grant 
date and is adjusted to reflect the actual number of stock options, performance warrants and PRSUs that vest, whereas 
DSUs vest immediately. The performance share units (“PSUs”) are granted with certain market conditions, specified at 
the grant date as determined by the Company’s Board of Directors. If the Company satisfies the market conditions, a 
pre-determined adjustment factor is applied to PSUs eligible to vest at the end of the performance period, based upon 
the relative share price performance of the Company compared to a peer group over the performance period. The 
expense recognized over the vesting period of PSUs is the fair value of the PSUs with an estimated adjustment factor. If 
the actual final adjustment factor is higher than estimated at grant, additional expense is recognized on vesting for the 
incremental fair value. 

Upon the exercise of the stock options, performance warrants, DSUs, PSUs and RSUs, consideration paid together with 
the amount previously recognized in contributed surplus is recorded as an increase to share capital. The Company’s DSU 
and PRSU plans allow the holder of an DSU or PRSU to receive a cash payment or its equivalent in fully-paid common 
shares, at the Company’s discretion, equal to the fair market value of the Company’s Class A common shares calculated 
at the date of such payment. The Company does not intend to make cash payments under the DSU or PRSU plans and, 
as such, the PRSUs are accounted for within equity.

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 

SEVEN GENERATIONS 2015 ANNUAL REPORT61

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, with a maturity of 90 days or less.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when risk and rewards of ownership are transferred 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. A qualifying asset is an asset that requires a period 
of one year or greater to complete or prepare for its intended use. 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 consolidated 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 Policies

There were no material new or amended accounting standards adopted during the year ended December 31, 2015.

Future Accounting Policy Changes

In February 2014, the IASB International Accounting Standards Board (“IASB”) issued IFRS 9 “Financial Instruments”, 
which replaces IAS 39, “Financial Instruments: Recognition and Measurement” for annual periods beginning on or after 
January 1, 2018, with earlier adoption permitted. IFRS 9 includes a principle-based approach for classification and 
measurement of financial assets, a single ‘expected loss’ impairment model and a substantially-reformed approach to 
hedge accounting. The impact of the standard on the Company’s financial statements is currently being evaluated.

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. In July 2015, the IASB issued an amendment to IFRS 15, deferring 
the effective date by one year. IFRS 15 provides clarification for recognizing revenue from contracts with customers  
and establishes a single revenue recognition and measurement framework. The standard is required to be adopted  
either retrospectively or using a modified transition approach for annual periods beginning on or after January 1, 2018, 
with earlier adoption permitted. The Company is currently evaluating the impact of the standard on the consolidated 
financial statements.

SEVEN GENERATIONS 2015 ANNUAL REPORT62

In January 2016, the IASB issued IFRS 16 “Leases” which replaces IAS 17 “Leases” for annual periods beginning on or 
after January 1, 2019, with earlier application permitted if IFRS 15 “Revenue from Contracts with Customers” is also 
applied. Under IFRS 16, lessees are required to recognize a lease liability reflecting future lease payments and a ‘right-of-
use asset’ for virtually all lease contracts. The Company is currently evaluating the impact of the standard on the 
consolidated financial statements.

5.  SIGNIFICANT ACCOUNTING JUDGEMENTS, ESTIMATES  

AND ASSUMPTIONS

(a) Judgments

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.

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 applies judgment in determining the transfer of risks and rewards of ownership from the Company to its 
customers. Oil and natural gas revenues are recognized in accordance with this transfer, which typically occurs upon 
title of asset transfer, at which point cash consideration is receivable, or as products are taken in kind as consideration 
and the Company has no continuing involvement with the goods or services provided.

The Company assesses revenue agreements using specific criteria to determine whether it is acting as an agent or 
principal. The Company recognizes revenue on a gross basis when the Company is acting in a principal capacity and on a 
net basis when the Company is acting in an agent capacity. The Company has concluded it acts in an agent capacity for 
all revenue transactions whereby third party oil and natural gas volumes are purchased and sold, whereby the Company 
recognizes the net revenues and net losses in other income separately from oil and natural gas revenues.

The determination of the Company’s income tax and royalty liabilities requires interpretation of complex laws and 
regulations. As such, income taxes and royalties 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.

(b) Estimates and Assumptions

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 assets 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.

The Company’s provisions for decommissioning liabilities are based on judgments 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.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
63

2014

1,448

846,688

848,136

Total

1,161,719

1,120,336

(5,134)

33,618

2,310,539

1,308,973

(3,398)

37,703

6.  CASH AND CASH EQUIVALENTS

As at December 31

Cash

Short term investments, bearing interest at a weighted  
  average rate of 0.7% (December 31, 2014 – 0.8%) (1)

2015

77,142

327,904

405,046

(1) 

Includes $Nil US term deposit balance as at December 31, 2015 (2014 – US$66.0 million ($76.6 million)).

7.  OIL AND NATURAL GAS ASSETS

Cost

Balance at December 31, 2013

Additions

Dispositions

Non-cash capitalized costs (1)

Balance at December 31, 2014

Additions

Dispositions and transfers

Non-cash capitalized costs (1)

Balance at December 31, 2015

  Exploration and  

  Developed and  

evaluation

producing

140,342

74,119

-

-

214,461

13,474

(5,407)

-

1,017,254

1,043,944

(5,134)

33,618

2,089,682

1,293,589

2,009

37,703

Other

4,123

2,273

-

-

6,396

1,910

-

-

222,528

3,422,983

8,306

3,653,817

Accumulated depletion, depreciation and amortization

Balance at December 31, 2013

Depletion, depreciation and amortization expense

Balance at December 31, 2014

Depletion, depreciation and amortization expense

Balance at December 31, 2015

Net book value

Balance at December 31, 2014

Balance at December 31, 2015

-

-

-

-

-

100,600

158,387

258,987

282,022

541,009

214,461

222,528

1,830,695

2,881,974

732

1,060

1,792

1,513

3,305

4,604

5,001

101,332

159,447

260,779

283,535

544,314

2,049,760

3,109,503

(1) 

 Non-cash capitalized costs include $25.3 million (2014 – $27.6 million) of decommissioning obligation assets, land swap additions and $0.4 million 
non-cash interest and financing (2014 – $Nil) (Note 18).

As at December 31, 2015, the calculation for depletion included an estimated $6.4 billion (2014 – $8.9 billion) for future 
development capital associated with undeveloped estimated recoverable proved plus probable reserves and excluded 
$148.8 million (2014 – $144.7 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, 2015, the Company capitalized $15.8 million (2014 – $9.8 million) of general and 
administrative expenses based on actual direct salaries and benefits paid to development personnel specifically related 
to capital activities, including $6.0 million (2014 – $6.1 million) related to stock based compensation.

During the year ended December 31, 2015, the Company capitalized $4.4 million (2014 – $0.5 million) of borrowing costs. 

In 2015, 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 $2.6 million for the year ended  
December 31, 2015 (2014 – $4.3 million). 

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. At December 31, 2015 and 2014, the 
Company determined that based on fair value less cost to dispose, both its oil and natural gas assets and goodwill were 
not impaired. The Company used a discount rate of 10 percent on cash flows from proved plus probable reserves. The 
estimated cash flows were consistent with the estimates of the Company’s independent reserves evaluator. 

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
64

The impairment review was carried out at December 31, 2015 using the following commodity prices estimated by the 
independent reserves evaluator: 

2016

2017

2018

2019

2020

2021–2025

  WTI Crude Oil 
(US$/bbl)

  US Henry Hub  
 Natural Gas Price  
(US$/MMBtu)

Edmonton  
Natural Gasolines  
C5+ (C$/bbl)

Foreign 
exchange 
(US$/C$)

45.00

53.60

62.40

69.00

73.10

84.52

2.50

2.95

3.40

3.70

3.90

4.52

60.60

70.50

77.00

85.10

87.50

101.30

0.73

0.75

0.80

0.80

0.83

0.83

8.  BANK DEBT
At December 31, 2015, the Company had available an $850.0 million revolving credit facility (2014 – $480.0 million) with a 
syndicate of banks (the “credit facility”), expiring in May 2018. 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. At December 31, 2015 and 2014, no amount was drawn on the credit facility.

As of December 31, 2015, the Company had $38.2 million in letters of credit (2014 – $Nil), of which $16.6 million  
(US$12.0 million) was issued in US dollars.

9.  ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31

Trade

Accrued liabilities

Deferred credits

10.  SENIOR NOTES

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)

2015

37,206

150,554

123

187,883

2015

813,880

515,052

(11,329)

228,802

356

1,546,761

2014

18,849

249,259

123

268,231

2014

414,525

356,342

(9,840)

53,319

(466)

813,880

(1) 

 Balance of principal less debt issue costs at December 31, 2015 is US$1,116.7 million ($1,547.9 million) (December 31, 2014 – US$701.1 million  
($814.3 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 percent 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 percent, 2017 at 104.125 percent, 2018 at  
102.063 percent and 2019 at 100 percent. 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 percent 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 percent of the aggregate principal 
amount plus an applicable premium that will be the greater of: (a) 1.0 percent 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 percent) plus all accrued interest due through May 15, 2016 over the principal amount of the notes. 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.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
65

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 percent 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.

On April 30, 2015, the Company issued US$425.0 million of additional senior unsecured notes that bear interest at  
6.75 percent per annum (calculated using a 360-day year) payable on October 31 and April 30 of each year, commencing 
on October 31, 2015. The notes will mature on May 1, 2023. On or after May 1, 2018, 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): 2018 at 105.063 percent, 2019 at 103.375 percent, 2020 at 101.688 percent and 2021 and 
thereafter at 100 percent. In addition, at any time prior to May 1, 2018, the Company may redeem all or a part of the 
notes at a redemption price equal to 100 percent of the aggregate principal amount plus an applicable premium that will 
be the greater of: (a) 1.0 percent 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 1, 2018 (105.063 percent) plus all accrued interest due through May 
1, 2018 over the principal amount of the note. 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.

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. At December 31, 2015 and 2014, the Company was in compliance with the 
covenants on the senior notes. 

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 7.0 percent, 7.3 percent and  
8.6 percent for each respective 2015, 2014 and 2013 issuances. Canadian dollar to US dollar exchange rates at the time 
of the 2015 issuance of US$425.0 million, 2014 issuance of US$300.0 million and the 2013 issuance of $400.0 million 
were 0.825, 0.901 and 0.940, respectively.

11.  DECOMMISSIONING LIABILITIES

Balance, beginning of year

Liabilities incurred

Changes in estimates

Changes in estimated discount rates

Decommissioning expenditures

Accretion

Balance, end of year

2015

52,163

25,263

(1,089)

1,110

-

1,662

79,109

2014

23,656

20,873

2,367

4,311

(206)

1,162

52,163

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, 2015 is approximately $139.1 million (2014 – $90.9 million) which is expected 
to be incurred over the next 35 years with the majority of costs incurred between 2040 and 2050. At December 31, 
2015, a risk free rate of 2.0 percent (2014 – 2.3 percent) and an inflation rate of 2.2 percent (2014 – 2.0 percent) were 
used to calculate the provision for decommissioning liabilities.

SEVEN GENERATIONS 2015 ANNUAL REPORT66

12.  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-taxable portion of foreign exchange capital losses

  Provision for uncertain tax position – IceFyre

  Unrecognized deferred tax asset

  Change in tax rates and other

Income tax expense

2015

(125,390)

26%

(32,601)

3,637

29,192

22,579

31,629

7,470

61,906

2014

215,708

25%

53,927

2,987

6,308

-

8,210

76

71,508

During the year ended December 31, 2015, the Canada Revenue Agency (“CRA”) challenged tax losses utilized by the 
Company which were derived from the Company’s predecessor entity, IceFyre Semiconductor Corporation. As a result of 
the ongoing CRA audit, the Company has applied a provision of $22.6 million against the tax pools. 

The Company also recorded a tax recovery of $1.1 million for the rate change effect on share issue costs, presented in 
Class A Common Shares (Note 13 (b)). 

For the year ended December 31, 2015, $0.1 million of current income tax expense was recorded for estimated Illinois 
state and US federal taxes payable by Seven Generations US. There were no current income taxes for Seven 
Generations in Canada given its total tax pools of $2.7 billion (2014 – $1.7 billion). Of this amount, $0.7 billion is available 
for deduction against taxable income for the current fiscal year. Non-capital losses begin expiring in 2034.

Changes in the components of the deferred tax liability are as follows:

January 1, 2015

Movement

December 31, 2015

Property, plant and equipment

Mark-to-market financial instruments

Investment tax credits

Non-capital losses

Decommissioning liabilities

Financing costs

Unrealized foreign exchange capital losses

Other

Unrecognized deferred tax asset

79,147

34,780

(9,127)

(4,668)

(13,041)

(12,453)

(8,895)

(5,329)

60,414

8,210

68,624

113,843

(1,514)

9,127

(58,441)

(8,318)

1,559

(31,148)

4,009

29,117

31,629

60,746

192,990

33,266

-

(63,109)

(21,359)

(10,894)

(40,043)

(1,320)

89,531

39,839

129,370

The gross temporary difference for the unrealized foreign exchange capital losses not being recognized was $147.8 million 
(2014 – $32.8 million).

January 1, 2014

Movement

December 31, 2014

Property, plant and equipment

Mark-to-market financial instruments

Investment tax credits

Non-capital losses

Decommissioning liabilities

Financing costs

Unrealized foreign exchange losses

Other

Unrecognized deferred tax asset

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

SEVEN GENERATIONS 2015 ANNUAL REPORTThe changes in the deferred tax liability were allocated to:

Year ended December 31

Income statement

Share capital

67

2015

61,802

(1,056)

60,746

2014

71,508

(12,212)

59,296

13.  SHARE CAPITAL
The Company’s authorized share capital consists of an unlimited number of Class A Common Voting Shares, Class B 
Common Non-voting Shares, Preferred A, B, C and D Shares and Special Voting Shares. At December 31, 2015, there are 
no Preferred Shares or Special Voting Shares issued and outstanding.

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 on a retroactive basis for the Class A Common Voting Shares, 
stock options, performance warrants and per share information.

The following table summarizes changes to the Company’s common share capital:

Year ended December 31

Class A Common Voting Shares

Balance, beginning of year

Issued on IPO (a)

Share issue costs, net of deferred tax (b)

Issued on exercise of stock options and  
  performance warrants

Transfer from contributed surplus on exercise of  
  stock options

Conversion of Class B Common Non-voting Shares (1)

Balance, end of year

2015

2014

Number (000s)

Amount ($)

Number (000s)

Amount ($)

244,716

1,716,050

-

-

8,656

-

1,042

254,414

-

1,056

41,950

12,888

3,715

1,775,659

185,420

51,750

-

110

-

7,436

244,716

783,514

931,500

(36,637)

275

130

37,268

1,716,050

(1) 

 On conversion of Class B Non-voting Shares into Class A Common Voting Shares, holders receive two Class A Common Voting Shares for each  
Class B Non-voting Share converted. 

(a)   On November 5, 2014, the Company closed an initial public offering (“IPO”) for gross proceeds of $931.5 million through 
the issuance of 51.8 million Class A Common Voting Shares. Share issue costs related to the IPO and equity financing 
were $51.4 million, including the underwriters’ commission for 5 percent of the gross proceeds . 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 (Note 12). 

(b)   For the year ended December 31, 2015, the Company recorded a deferred tax recovery of $1.1 million for the rate 

change effect on share issue costs related to changes in tax rates (Note 12).

SEVEN GENERATIONS 2015 ANNUAL REPORT68

Year ended December 31

Number (000s)

Amount ($)

Number (000s)

Amount ($)

2015

2014

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

523

3,729

-

-

-

(521)

2

-

-

-

(3,715)

14

966

1,770

1,505

-

(3,718)

523

6,550

9,765

15,858

8,824

(37,268)

3,729

(1) 

 On conversion of Class B Non-voting Shares into Class A Common Voting Shares, holders receive two Class A Common Voting Shares for each  
Class B Non-voting Share converted.

14.  STOCK BASED COMPENSATION
Stock Options

The Company’s stock option plan was amended and restated on August 27, 2014 (the “New Plan”). The stock options 
under the New Plan are exercisable for Class A Common 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 percent 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.

Prior to the Company’s IPO closing on November 5, 2014, Seven Generations had 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. The Pre-IPO stock options are 
exercisable for Class A Common Voting Shares. After the November 5, 2014 closing of the IPO, no additional Pre-IPO stock 
options may be granted.

The following table sets forth a reconciliation of stock options exercisable into Class A Common Voting Shares:

Year ended December 31

Balance, beginning of year

Granted

Exercised

Forfeited

Balance, end of year

2015

2014

Number (000s) Exercise Price ($)

Number (000s)

Exercise Price ($)

12,385

2,340

(2,428)

(327)

11,970

6.71

13.19

3.74

12.58

8.43

13,426

2,927

(3,650)

(318)

12,385

3.49

17.11

2.75

5.81

6.71

A summary of stock options outstanding and exercisable into Class A Common Voting Shares at December 31, 2015 is  
as follows:

Exercise price ($)

2.50 – 5.49

5.50 – 12.49

12.50 – 17.49

17.50 – 20.20

Options outstanding

Options exercisable

Number of
options
(000s)

 Weighted average  
remaining life  
(years)

Number of
options
(000s)

Weighted average  
remaining life  
(years)

4,257

4,485

747

2,481

11,970

1.9

6.3

7.1

5.8

4.7

4,257

2,122

153

762

7,294

1.9

4.0

5.2

5.5

3.0

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
The fair value of stock options granted was estimated using the Black-Scholes pricing model with the following weighted 
average assumptions:

69

Year ended December 31

Fair value of options granted ($/option)

Risk-free interest rate (%)

Expected life (years)

Expected forfeiture rate (%)

Expected volatility (%)

Expected dividend yield (%)

Performance Warrants

2015

6.67

0.79

5.0

4.0

60.0

-

2014

7.81

1.40

3.9

3.0

60.0

-

Prior to the Company’s IPO closing on November 5, 2014, Seven Generations had 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. The performance 
warrants are exercisable for Class A Common Voting Shares. Except for the performance warrants that were granted in 
2008 and 2009, the terms of which were extended to 2017, 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:

Year ended December 31

Balance, beginning of year

Granted

Exercised

Forfeited

Balance, end of year

2015

2014

Number (000s) Exercise price ($)

Number (000s)

Exercise price ($)

25,968

-

(6,228)

(1,247)

18,493

5.99

-

5.27

7.30

6.14

28,825

1,350

(3,011)

(1,196)

25,968

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, 
2015 is as follows:

Weighted average exercise price ($)

3.75 – 5.25

5.26 – 5.85

5.86 – 12.50

12.50 – 17.50

Warrants outstanding

Warrants exercisable

Number of
warrants
(000s)

 Weighted average  

remaining life 
(years)

Number of
warrants
(000s)

Weighted average  
remaining life  
(years)

7,907

2,139

7,410

1,037

18,493

1.9

4.0

2.4

5.4

2.5

6,988

1,001

5,969

216

14,174

1.8

3.9

2.1

5.4

2.1

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 (%)

Expected dividend yield (%)

2015

-

-

-

-

-

-

2014

8.87

1.40

4.9

3.0

60.0

-

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
70

Share Units

On August 27, 2014, the Board adopted a Performance and Restricted Share Unit (“PRSU”) Plan and a Deferred Share 
Unit Plan (“DSU”).

The PRSU Plan allows for granting of Restricted Share Units (“RSUs”) and Performance Share Units (“PSUs”), to officers 
and employees of the Company. RSUs and PSUs represent the right for the holder to receive Class A Common Voting 
Shares or, at the election of the holder and the Company, a cash payment equal to the fair market value of the 
Company’s common shares calculated at the date of such payment. The vesting of PSUs are conditional on the 
satisfaction of certain performance criteria as determined by the Company’s Board of Directors. If the Company satisfies 
the performance criteria, PSUs become eligible to vest and a pre-determined multiplier is applied to eligible PSUs. RSUs 
and PSUs granted to date under the PRSU Plan generally vest annually over a three year period.

The following table sets forth a reconciliation of PRSUs exercisable into Class A Common Voting Shares:

Year ended December 31

Balance, beginning of year

Granted

Exercised

Forfeited

Balance, end of year

2015

-

426,546

-

-

426,546

2014

-

-

-

-

-

Of the 426,546 units outstanding on December 31, 2015 under the PRSU Plan, 154,698 are PSUs and 271,848 are RSUs. 
The fair value of RSUs for the year ended December 31, 2015 was $12.11 per unit using a forfeiture rate of 5 percent.

The DSU Plan allows for granting of Deferred Share Units (“DSUs”) to directors of the Company. DSUs represent the right 
for the holder to receive Class A Common Voting Shares or, at the election of the holder and the Company, a cash 
payment equal to the fair market value of the Company’s common shares calculated at the date of such payment. DSUs 
granted under the DSU plan generally vest immediately upon grant.

The following table sets forth a reconciliation of DSUs exercisable into Class A Common Voting Shares:

Year ended December 31

Balance, beginning of year

Granted

Exercised

Forfeited

Balance, end of year

The fair value of DSUs for the year ended December 31, 2015 was $13.63 per unit.

15.  PER SHARE AMOUNTS
Basic and diluted per share amounts have been calculated based on the following:

Year ended December 31

(000s)

Weighted average number of common shares – basic

Effect of outstanding stock options and performance warrants (1)

Weighted average number of common shares – diluted

2015

-

55,176

-

-

55,176

2015

249,549

-

249,549

2014

-

-

-

-

-

2014

198,742

25,975

224,717

(1) 

 For the year ended December 31, 2015, 6.7 million stock options and 13.9 million performance warrants have been excluded from the diluted earnings 
per share calculation since these are anti-dilutive as the Company is in a net loss position. Additional potentially dilutive instruments would include 
0.1 million DSUs (2014 – 2.4 million anti-dilutive stock options and 1.2 million anti-dilutive performance warrants).

SEVEN GENERATIONS 2015 ANNUAL REPORT16.  OPERATING EXPENSES

Year ended December 31

Equipment rental, maintenance and other

Trucking and disposal

Chemicals and fuel

Staff and contractor costs

Other

Operating expenses

17.  GENERAL AND ADMINISTRATIVE EXPENSES

Year ended December 31

Personnel

Professional fees

Rent

Information technology costs

Other office costs and travel

IPO expenses

Gross expenses

Capitalized salaries and benefits

Operating overhead recoveries

General and administrative expenses

18.  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 (1)

Finance expense

(1)  Non-cash interest was $0.4 million (2014 – $Nil) (Note 7).

2015

31,413

30,510

15,008

15,981

8,276

101,188

2015

18,844

1,780

1,584

2,347

5,161

-

29,716

(3,619)

(1,754)

24,343

2015

98,887

5,512

356

1,662

106,417

(4,406)

102,011

71

2014

20,584

15,339

3,438

9,474

5,426

54,261

2014

12,912

2,636

1,210

1,310

3,403

2,506

23,977

(2,661)

(1,058)

20,258

2014

61,303

2,142

(466)

1,162

64,141

(500)

63,641

19.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT CONTRACTS
Financial Instrument Classification and Measurement

The Company’s financial instruments include cash and cash equivalents, 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 and risk management contracts. 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.

SEVEN GENERATIONS 2015 ANNUAL REPORT72

Cash and cash equivalents are classified as Level 1 measurements. Risk management contracts 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, 2015 and 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

  Risk management contracts

Other Financial Liabilities

2015

2014

Carrying value

Fair value

Carrying value

Fair value

405,046

151,566

76,439

8,933

405,046

151,566

76,439

8,933

848,136

139,119

64,417

5,034

848,136

139,119

64,417

5,034

28,359

28,359

-

-

  Accounts payable and accrued liabilities

  Senior notes

187,760

1,546,761

187,760

1,353,953

268,108

813,880

268,108

782,000

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, 2015

Risk management contracts

  Current asset

  Long-term asset

  Current liability

  Long-term liability

Net position

As at December 31, 2014

Risk management contracts

  Current asset

  Long-term asset

Net position

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

102,343

62,939

(22,093)

(19,982)

123,207

(3,773)

(9,943)

3,773

9,943

-

98,570

52,996

(18,320)

(10,039)

123,207

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

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73

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 mitigates 
concentration risk by limiting the sales of its production to customers, and reviews sales regularly. Production is sold to 
marketers and customers 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, 2015, 
the Company’s most significant marketer accounted for $20.2 million (2014 – $21.1 million) of total receivables and  
47 percent of total revenues (2014 – 50 percent). 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 investments. 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, 2015, receivables outstanding for more than 90 days totalled less than $0.5 million  
(2014 – $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 government owned financial 
institutions 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 these financial institutions to be 
remote. As at December 31, 2015, 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. 

Market Risk

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.

SEVEN GENERATIONS 2015 ANNUAL REPORT74

Risk Management Contracts

The Company had the following risk management contracts in place at December 31, 2015: 

Commodity

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Natural gas (2)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Oil (3)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Foreign exchange swap (4)

Period

Q1 2016

Q2 2016

Q3 2016

Q4 2016

Q1 2017

Q2 2017

Q3 2017

Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q4 2018

Q1 2016

Q2 2016

Q3 2016

Q4 2016

Q1 2017

Q2 2017

Q3 2017

Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q1 2016

Q2 2016

Q3 2016

Q4 2016

Q1 2017

Q2 2017

Q3 2017

Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q4 2018

Notional

Average Price/Unit (1)

120,000 MMBtu/d

120,000 MMBtu/d

120,000 MMBtu/d

130,000 MMBtu/d

140,000 MMBtu/d

100,000 MMBtu/d

90,000 MMBtu/d

90,000 MMBtu/d

60,000 MMBtu/d

50,000 MMBtu/d

40,000 MMBtu/d

40,000 MMBtu/d

US$3.20

US$3.20

US$3.20

US$3.18

US$3.20

US$3.17

US$2.99

US$2.99

US$2.85

US$2.81

US$2.76

US$2.76

12,000 bbls/d

C$70.00 - $80.89

13,000 bbls/d

C$70.00 - $80.83

14,000 bbls/d

C$70.07 - $80.13

14,000 bbls/d

C$70.07 - $80.13

12,000 bbls/d

C$69.67 - $82.01

7,000 bbls/d

C$68.71 - $80.14

7,000 bbls/d

C$68.44 - $75.56

7,000 bbls/d

C$68.44 - $75.56

6,000 bbls/d

C$68.18 - $74.80

6,000 bbls/d

C$68.18 - $74.80

1,000 bbls/d

C$65.00 - $76.00

US$34.9 million

US$34.9 million

US$35.3 million

US$38.0 million

US$40.5 million

US$28.9 million

US$24.7 million

US$24.7 million

US$15.4 million

US$12.8 million

US$10.2 million

US$10.2 million

(1)  For swap contracts, the average put and call price has been calculated for the above table.

(2)  Chicago Citygate gas price.

(3)  West Texas Intermediate oil price.

(4)  US Dollar sales.

The following is a summary of the carrying value of risk management contracts in place by contract type:

As at December 31

Risk management contracts

  Natural gas

  Oil

  Foreign exchange swap

Net position

2015

58,087

93,478

(28,358)

123,207

C$1.2550

C$1.2550

C$1.2550

C$1.2597

C$1.2572

C$1.2730

C$1.3215

C$1.3215

C$1.3586

C$1.3661

C$1.3786

C$1.3786

2014

29,548

109,571

-

139,119

SEVEN GENERATIONS 2015 ANNUAL REPORTDuring the year ended December 31, 2015, the Company’s risk management contracts resulted in realized gains of  
$150.6 million (year ended December 31, 2014 – realized gains of $9.7 million) and unrealized losses of $15.9 million  
(year ended December 31, 2014 – unrealized gains of $141.8 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, 2015:

75

10% increase in US$ Chicago Citygate/MMbtu

10% decrease in US$ Chicago Citygate/MMbtu

10% increase in US$ WTI/bbl

10% decrease in US$ WTI/bbl

(b)  Interest Rate Risk

Gain (Loss)

(33,620)

33,620

(68,583)

80,485

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 the year ended December 31, 2015, 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 liquids and natural gas sales.

The Company manages foreign currency exchange risk by entering into a variety of risk management contracts (see Risk 
management contracts section above). The Company enters into US dollar swaps to crystallize the Canadian dollar value 
of the liquids or natural gas price risk management contract entered into.

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 and cash equivalent balances held in US dollars. Foreign currency risk associated with 
interest payments is partially offset by marketing arrangements for the sale of the Company’s natural gas and natural 
gas liquids, excluding condensate, which are 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 (including the foreign exchange risk management contracts) at December 31, 2015:

10% increase in US$ to C$

10% decrease in US$ to C$

Gain (Loss)

181,617

(212,491)

The carrying amount of the Company’s US dollar denominated monetary assets and liabilities as at December 31 was  
as follows:

As at December 31

Assets

Liabilities

Liquidity Risk

2015

35,545

1,563,829

2014

78,042

822,573

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, 
2015, the Company had $405.0 million of cash and cash equivalents, plus available credit facility of $812.0 million. 
Management believes it has sufficient funding to meet foreseeable liquidity requirements. The Company prepares capital 
expenditure budgets which are regularly monitored and updated. As well, the Company utilizes authorizations for 
investments on both operated and non-operated projects to manage capital investments. See Note 24 Subsequent Event.

SEVEN GENERATIONS 2015 ANNUAL REPORT76

The following are the contractual maturities of financial liabilities at December 31, 2015:

Less than 1 year

2-3 years

4-5 years

Thereafter

Accounts payable and accrued liabilities

Senior notes (1)

Interest on senior notes (1)

Total

187,760

-

119,630

307,390

-

-

358,890

358,890

-

968,800

109,380

1,078,180

Total

187,760

-

588,200

1,557,000

52,939

641,139

640,839

2,385,599

(1)  Balances denominated in US dollars have been translated at the December 31, 2015, US dollar to Canadian dollar exchange rate of 0.723.

20.  CAPITAL MANAGEMENT
The capital structure of the Company is as follows:

As at December 31

Total debt (1)

Total equity (2)

Total capital

(1)  Senior unsecured notes.

2015

1,546,761

1,786,650

3,333,411

2014

813,880

1,910,926

2,724,806

(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 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 10). The 
Company endeavors 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.

The Company had adjusted working capital of $306.1 million (current assets less current liabilities excluding current 
portion of risk management contracts and deferred credits) plus $812.0 million of credit facility capacity creating 
available funding of $1.1 billion at December 31, 2015. The Company plans to use these funds, along with funds from 
operations, and the funds raised in February 2016 (Note 24) for the execution of its 2016 capital program. 

Refer to Note 10 for non-financial covenants on the senior unsecured notes.

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

  Financing activities

Investing activities

Other Cash Flow Information

Year ended December 31

Cash interest paid

Cash taxes paid

2015

(13,222)

(3,064)

(79,207)

(95,493)

(34,492)

-

(61,001)

2015

94,050

-

2014

(33,917)

(6,776)

142,334

101,641

10,129

-

91,512

2014

57,271

-

SEVEN GENERATIONS 2015 ANNUAL REPORT 
22.  COMMITMENTS AND CONTINGENCIES
The following table lists the Company’s estimated material contractual commitments at December 31, 2015:

77

Senior notes (1)

Interest on senior notes

Firm transportation and  
  processing agreements (2)

Operating leases (3)

Deferred obligation and retention (4)

Less than  

1 year

1-3 years

4-5 years

Thereafter

Total

1,557,000

640,839

-

-

119,630

358,890

1,993,633

220,331

780,243

12,800

2,748

2,380

2,748

5,319

-

968,800

109,380

556,055

2,583

-

588,200

52,939

437,004

2,518

-

Estimated contractual obligations

4,207,020

345,089

1,144,452

1,636,818

1,080,661

(1)  Balance represents US$1.1 billion 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.

(4)   In November 2014, the Board of Directors approved a retention bonus plan for management and employees in aggregate of $6.0 million, payable over 

the two-year period starting November 5, 2014. Of this amount, $2.7 million is payable in 2016.

23.  RELATED PARTY TRANSACTIONS
Key management personnel are comprised of all directors and officers of the Company.

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 $6.0 million, payable over the two-year period starting November 5, 2014. Amounts 
paid to directors and officers are disclosed in the table below.

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 and was paid in cash in 
2015. Amounts paid to directors and officers are disclosed in the table below.

The amounts recognized in the consolidated 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

Retention expense

Liquidity event expense (1)

2015

8,785

8,884

1,368

-

19,037

2014

6,276

9,538

-

20,090

35,904

(1)  Amount expensed in 2014 on closing of the IPO. The allocation of payments to key management personnel was determined in 2015.

24.  SUBSEQUENT EVENT
On February 24, 2016, the Company completed a private placement of 21,428,600 common shares at a price of $14.00 per 
share for gross proceeds of $300 million. Net proceeds after commissions and expenses were approximately $285 million.

SEVEN GENERATIONS 2015 ANNUAL REPORT 
 
78

READER ADVISORY

FORWARD-LOOKING INFORMATION 
ADVISORY

This document contains certain forward-looking information and statements that 
involve 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: the Company’s objectives, strategies, vision and competitive 
strengths; expected transportation capacity and future deliveries; the 
Company’s ability to deliver on its growth objectives and meet the commitments 
in its marketing and transportation agreements; changes to be implemented 
under the new Alberta royalty framework and their impact on the Company; 
changes to laws and regulations and their impact on the oil and gas industry 
and the Company; the Company’s future competitive position; forecast 
break-even prices required to achieve specified internal rates of return; the 
impact of commodity price fluctuations on 7G and its competitors; impact of 
innovation and efficiency measures; forecast supply-cost sensitivities; projected 
internal rates of return; potential for commercial development of 7G’s Deep 
Southwest assets; ability to derive optimal value from the Company’s resources; 
market predictions; ability to maintain a superior operating margin; opportunities 
to underpin major investments and access new markets and achieve 
differentiated netbacks; exploitable resources and production potential; forecast 
production, production guidance, production declines and production profiles; 
expectation that seismic activity from the Company’s activities will not result in 
damage to property or the biophysical environment; ability to achieve positive 
free cash flow and full-cycle returns; expectation that the Cutbank plant will be 
processing incremental gas volumes in the second quarter of 2016; total field 
gathering, transportation and processing capacity; planned capital investment; 
sources and uses of funds; the number of rigs to be utilized; planned number of 
wells to be drilled, completed and tied-in; the planned construction of additional 
super pads and a second condensate stabilizer at the Karr facility and the 
anticipated timing thereof; the number of future drilling opportunities; ability to 
subcontract capacity on the Alliance Pipeline; potential benefits of vertical 
integration or a hybrid midstream business model; and opportunities to acquire 
new reserves and resources.

For a description of the material factors and assumptions that were used to 
develop the forward looking information that is contained herein, please refer to 
the “Forward Looking Information Advisory” that is included in the Management’s 
Discussion and Analysis, dated March 8, 2016, for the year ended December 31, 
2015 (the “MD&A”) that is provided herein. Actual results could differ materially 
from those anticipated in the forward-looking information as a result of the  
risks and risk factors that are set forth in the Annual Information Form, dated 
March 8, 2016, for the year ended December 31, 2015 (the “AIF”), which is 
available on the SEDAR website at www.sedar.com. For additional information 
about these risk factors, please consult the AIF and the “Forward Looking 
Information Advisory” that appears in the MD&A. For additional information 
pertaining to financial outlooks and future-oriented financial information, please 
refer to the “Forward Looking Information Advisory” in the MD&A. For additional 
information pertaining Non-IFRS measures, including “Funds from Operations” and 
“Operating Netback” please refer to “Non-IFRS Financial Measures” in the MD&A.

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.

Advisory Regarding the Presentation of 
Reserves and Resources
Estimates of the Company’s reserves are based upon the reports prepared by 
McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independent 
qualified reserves evaluator, as at December 31, 2015. 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 differences 
may be material. Estimates of net present value of future net revenue 
attributable to the Company’s reserves do not represent fair market value and 
there is uncertainty that the net present value of future net revenue will be 
realized. 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 

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 7G’s sales points. 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.

The reserves and resources information contained in this document should be 
reviewed in conjunction with the AIF, which contains important additional 
information regarding the independent reserves and resources evaluations that 
were conducted by McDaniel and a description of, and important information 
about, the reserves and resources terms used in this document. The AIF is 
available on the SEDAR website at www.sedar.com.

Definitions 
Below are definitions for certain terms and abbreviations that are not already 
defined under “Oil and Gas Definitions” and “Abbreviations” in the MD&A that is 
included herein:

“best estimate” is a classification of estimated resources described in the 
COGE Handbook, which is considered to be the best estimate of the quantity 
that will actually be recovered. It is equally likely that the actual quantities 
recovered will be greater or less than the best estimate. Resources in the best 
estimate case have a 50 percent probability that the actual quantities recovered 
will equal or exceed the estimate.

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook 
maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), 
as amended from time to time. 

“contingent resources” are the quantities of petroleum estimated, as of a given 
date, to be potentially recoverable from known accumulations using established 
technology or technology under development, but which are not currently 
considered to be commercially recoverable due to one or more contingencies. 
Contingencies are conditions that must be satisfied for a portion of contingent 
resources to be classified as reserves that are: (a) specific to the project being 
evaluated; and (b) expected to be resolved within a reasonable timeframe. 
Contingencies may include factors such as economic, legal, environmental, 
political and regulatory matters or a lack of markets. It is also appropriate to 
classify as contingent resources the estimated discovered recoverable 
quantities associated with a project in the early evaluation stage.

“IPO Prospectus” means the supplemented PREP Prospectus dated October 29, 
2014 that was prepared in connection with the Company’s initial public offering 
and is available on the SEDAR website at www.sedar.com.

“liquids” refers to oil, condensate and other NGLs.

“Nest” means the primary development block of the Company’s Kakwa  
River Project.

“Nest 1” means the portion of the Nest that falls outside of the Nest 2 area.

“Nest 2” means the Company’s higher return prospects that are contained 
within the Nest. 

“Seven Generations” or “7G” or the “Company” means Seven Generations 
Energy Ltd. 

Abbreviations 
Canadian dollars
CAD 

C3 

C4 

propane

butane

C5+ 

pentanes plus 

FX 

HH 

IRR 

LPG 

MM 

foreign exchange rate

Henry Hub

internal rate of return

liquefied petroleum gas

millions

MMbbl  millions of barrels

tcf 

trillion cubic feet

USD 

United States dollars

SEVEN GENERATIONS 2015 ANNUAL REPORTCORPORATE INFORMATION

79

MANAGEMENT
Pat Carlson 
CEO

Marty Proctor 
President & COO

Christopher Law 
CFO

Steve Haysom 
Senior Vice President

Merlyn Spence 
Senior Vice President, Marketing

Barry Hucik 
Vice President, Drilling

Susan Targett 
Vice President, Land

Glen Nevokshonoff 
Vice President, Development

Randall Hnatuik 
Vice President, Business Development

Kevin Johnston 
Vice President, Accounting & Controller

Charlotte Raggett 
Vice President, Midstream Business Development

DIRECTORS
Kent Jespersen 
Chairman

Pat Carlson 
CEO

Michael Kanovsky

Kevin Brown

Jeff van Steenbergen

Avik Dey

Kaush Rakhit

Dale Hohm

Bill McAdam

CORPORATE OFFICE
300, 140 – 8th Avenue S.W.

Calgary, AB  T2P 1B3

Telephone: (403) 718-0700

Fax: (403) 532-8020

TRUSTEE AND TRANSFER AGENT
Computershare Trust Company Of Canada

600, 530 – 8th Avenue S.W.

Calgary, AB  T2P 3S8

BANKS
Royal Bank of Canada

Credit Suisse AG, Toronto Branch

Bank of Montreal

Canadian Imperial Bank of Commerce

National Bank of Canada

The Bank of Nova Scotia

The Toronto-Dominion Bank

Alberta Treasury Branches

Caisse Centrale Desjardins

Canadian Western Bank

AUDITORS
PricewaterhouseCoopers LLP

LEGAL COUNSEL
Stikeman Elliott LLP

INDEPENDENT EVALUATORS
McDaniel & Associates Consultants Ltd.

STOCK SYMBOL
VII 
Toronto Stock Exchange

SEVEN GENERATIONS 2015 ANNUAL REPORT300, 140 – 8th Avenue SW,  
Calgary, AB  T2P 1B3 

T: (403) 718-0700 
E: info@7genergy.com

WWW.7GENERGY.COM

Seven Generations shares are 
traded on the Toronto Stock 
Exchange under the symbol VII.