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From every Angle - More oil. More reach. more value
Citation preview
2010 AnnuAl RepoRt
From every angle.
More oil.
More reach.
More value.
From every angle, we’re becoming an
intermediate energy producer.
$185 million capital budget in 2010 added highly prospective lands and strategic new facilities – plus funded 30 net horizontal wells.
We tripled proved plus probable reserves year-over-year and drove our reserve-life-index to 12 years. (1)
We added a net 1,000 bbls per day of high-netback light oil by year-end 2010, complementing our liquids-rich natural gas.
13,500 boe/d 2010
exit production
59.7 million boe
proved plus probable reserves (2)
274 net sections
developable land (2)
>800 drilling locations
Selected Highlights ............. 6
Management’s Q & A.......... 8
Exploration and Operations Review .............18
Operations Statistical Review ...............36
Financial Management ........................ 44
Management’s Discussion and Analysis .................................. 46
Management’s Report ..................................... 69
Independent Auditors’ Report ..................................... 70
Consolidated Financial Statements .........71
Notes to the Consolidated Financial Statements ........74
Corporate Information ............................92
(1) Based on 2010 exit production. (2) At December 31, 2010.
Our new value is just beginning.
We’re producing more light oil with a ground-floor opportunity
in the Viking play at Harmattan plus the Cardium across
west-central Alberta – both being developed through horizontal
wells with multi-stage fracturing. And we’re leading industry with
high-liquids, high-rate Mannville gas at Harmattan – a play that has put
Angle atop the energy sector for NGLs richness in our gas stream. Over the
past four years, we’ve front-loaded land, exploration drilling and infrastructure
development – setting the stage for low-risk production and reserve additions this
year and beyond.
It adds up to
one of the most
exciting stories in the Canadian energy sector.
Angle energy inc 2010 ANNuAL RepORt 1
Growth drivers
Asset quality We shine in technical control
Our assets are deep and wide and allow us to
add more oil, while prudently developing our
liquids-rich natural gas.
Our technical team of geoscientists
and engineers is one of the best in the
industry, bringing decades of experience to
understanding the complex reservoirs
we’re developing.
the depth of our in-house talent keeps us
independent and less reliant on partners. It
allows us to use leading-edge technologies
where they apply and gives us a leg-up as
we grow ever larger.
investors have only seen half-cycle benefits. The costs of front-loading land, infrastructure
and exploration were borne in 2009 and 2010.
The expected benefits – low-cost production
growth, low-risk reserve adds, higher netbacks –
will be delivered in 2011 and beyond.Our in-house team is chock full of experienced and visionary oil and gas professionals. Angle
is growing to intermediate size on the strength of its drilling performance. Organic drilling
growth has driven over 75 percent of our current production.
Our projects are advancing from exploration to lower-risk exploitation in the Viking,
Cardium, Mannville, Deep Basin and Wabamun – as we continue to drill across our portfolio
at Harmattan, Ferrier, edson and Lone pine Creek.
We have a deep presence in four key areas, control of or access to
strategically located processing and pipeline infrastructure, and a
finely-honed understanding of our liquids-rich natural gas and light
oil opportunities.
Angle energy inc 2010 ANNuAL RepORt2
Our efficiencies provide high rates of return
through the first half of our full-cycle
exploration program, Angle is maintaining
competitive rates of return and netbacks on
oil and natural gas production.
We anticipate even better efficiencies as we
continue to drill our assets to complete the
full cycle of exploration and expand our
production and reserve volumes.
Value makers
We shine with best-in-class efficiencies. It’s the
only way for a gas-weighted company to thrive.
That includes good finding and development
cost performance and low operating costs,
thanks to high-quality production and our
control of key infrastructure. The liquids
content of our gas generated revenues of over
$45 per bbl in 2010, adding $1.50 to nearly
$5 in revenue to each mcf of natural gas we
produced. Our light oil revenue reached $78
per bbl in the final quarter of 2010. And our
corporate average will only improve as we add
more light oil to our production mix. Recycle
ratios at our best plays top five times.
investors have only seen half-cycle benefits. The costs of front-loading land, infrastructure
and exploration were borne in 2009 and 2010.
The expected benefits – low-cost production
growth, low-risk reserve adds, higher netbacks –
will be delivered in 2011 and beyond.
Our reach is longer. We’re using technologies –
horizontal wells, multi-stage fracturing – that
access vastly greater reservoir area, bringing
millions of additional boe of resource-in-place
within technical and economic reach.
We’re mastering the application of horizontal
wells with multi-stage fracturing in formations
that were previously untested for this
completion technology.
technologies that optimize reservoir development
Angle energy inc 2010 ANNuAL RepORt 3
the pieces are in place for value growth through
production growth, light oil growth, reserves
growth and cash flow growth. Angle intends
to remain a leader in the Viking, the Cardium
and in liquids-rich, high-rate gas pools. We’re
targeting growth of 40-50 percent in cash flow
per share, growth in average production per
share of approximately 25 percent and growth
in our corporate average netback of 20 percent.
this year’s 33 net wells – nearly all horizontals –
will begin to tap our vast inventory of over 800
locations, doubling light oil production year-over-
year and exiting 2011 at greater than 2,000 bbls
of light oil per day. All told, Angle aims to drive
organically to nearly 16,000 boe per day exiting
2011, 40 percent of it light oil and NGLs.
Angle energy inc 2010 ANNuAL RepORt4
We’re excited about 2011 and beyond.
Where we go
from here. . .
the pieces are in place for value growth through
production growth, light oil growth, reserves
growth and cash flow growth. Angle intends
to remain a leader in the Viking, the Cardium
and in liquids-rich, high-rate gas pools. We’re
targeting growth of 40-50 percent in cash flow
per share, growth in average production per
share of approximately 25 percent and growth
in our corporate average netback of 20 percent.
this year’s 33 net wells – nearly all horizontals –
will begin to tap our vast inventory of over 800
locations, doubling light oil production year-over-
year and exiting 2011 at greater than 2,000 bbls
of light oil per day. All told, Angle aims to drive
organically to nearly 16,000 boe per day exiting
2011, 40 percent of it light oil and NGLs.
Angle energy inc 2010 ANNuAL RepORt 5
Selected HighlightsYears ended December 31 2010 2009 % Change
FinAnciAl ($000s, except per share data) Commodity revenues (1) 121,468 79,998 52Funds from operations (2) 62,003 40,154 54 per share – basic 0.98 0.92 7 per share – diluted 0.96 0.90 7Cash flow from operating activities 53,566 27,843 92Net loss (5,098) (3,032) 68 per share – basic (0.08) (0.07) 14 per share – diluted (0.08) (0.07) 14Capital expenditures (3) 355,071 64,575 450total assets 558,969 246,465 127Net debt (working capital) (4) 152,378 (38,255) 498Shareholders’ equity 343,167 212,201 62
cOmmOn ShAre DAtAShares outstanding (000s)
At end of year 71,969 54,481 32 Weighted average – basic 63,224 43,748 45 Weighted average – diluted 64,481 44,533 45
OperAtingSales Natural gas (mcf/d) 34,248 26,334 30 NGLs (bbls/d) 2,892 2,995 (3) Light crude oil (bbls/d) 643 144 347
Combined average (boe/d) 9,243 7,528 23Average wellhead prices (1)
Natural gas ($/mcf) 4.47 4.06 10 NGLs ($/bbl) 45.42 34.46 32 Light crude oil ($/bbl) 75.39 61.74 22
total oil equivalent ($/boe) 36.00 29.11 24Netbacks ($/boe) Operating (5) 22.14 17.03 30 Funds from operations (2) 18.38 14.63 26Reserves (December 31, 2010 evaluation) proved (mboe) 31,900 12,309 159 proved plus probable (mboe) 59,696 20,033 198 total net present value – proved plus probable (10% discount) ($000s) 749,296 276,847 171Gross (net) wells drilled (#) Natural gas 19 (17.2) 9 (7.9) 111 (118) Oil 18 (15.6) – (–) 100 (100) Dry and abandoned 3 (1.7) 4 (4.0) (25) (-58) total 40 (34.5) 13 (11.9) 208 (190)Average working interest (%) 86 92 (6)
(1) Commodity revenues and prices include realized gains or losses from derivative instruments.(2) Funds from operations, funds from operations per share and funds from operations netback are not recognized measures under Canadian generally
accepted accounting principles (GAAp). Refer to the Management’s Discussion and Analysis for further discussion.(3) total capital expenditures, including acquisitions.(4) Current assets less current liabilities and bank debt, excluding derivative instruments and the related tax effect.(5) Operating netback equals total revenue (including realized derivative gains and losses) less royalties, transportation and operating costs calculated
on a per boe basis. Operating netback is not a recognized measure under Canadian GAAp and therefore may not be comparable with the calculations of similar measures presented by other companies.
(6) For a description of the boe conversion ratio, refer to the commentary in the Management’s Discussion and Analysis.
Angle energy inc 2010 ANNuAL RepORt6
5% Light Crude Oil
63%Natural Gas
32% NGLs
7% Light Crude Oil
62% Natural Gas
31% NGLs
proved plus probable reserves mix percentages at year-end 2010
proved plus probable reserves (mmboe at year-end)
production mix percentages at year-end 2010
Average Daily production (boe/d)
LightCrudeOil
NGLs NaturalGas
1,281 3,334 6,586 7,528 9,243
06 07 08 09 10
LightCrudeOil
NGLs NaturalGas
12.4 13.6 15.9 20.0 59.7
06 07 08 09 10
Angle energy inc 2010 ANNuAL RepORt 7
heather christie-Burns President & Chief Operating Officer
What is driving the shift from being a vertical driller to being a horizontal driller?
Christie-Burns: It’s the broad opportunity in the Western Canada
Sedimentary Basin (WCSB). At Angle we pride ourselves on managing
technical risks, approaching reservoir opportunities from a multi-disciplinary
view and doing all of our technical homework. In our first several years
we used vertical drilling to effectively extend historical reservoirs that the
conventional wisdom held were tapped out or no longer existed. We had
repeated successes – at Harmattan, Ferrier and Lone pine Creek.
to get good production and returns from those vertical wells you had to
find the reservoir’s best portions. the next stage of exploitation offers a
much larger reservoir area, but lower in geological quality. Vertical wells are
less likely to be productive and profitable. today’s technology – horizontal
wells completed with multiple hydraulic fractures – is ideally suited to
these reservoirs. And as a result, of our 40 gross wells in 2010, 34 were
drilled horizontally.
And what about the transition from conventional exploration to resource plays?
Fischbuch: Angle has always pursued large resource-in-place plays, and
our technical work is aimed at transforming this resource-in-place into a
proved reserve. But that doesn’t mean you can drill 100 identical wells and
get 100 identical production rates, which is the commonly held view of what
a “resource play” should be. In the real world, all reservoirs are variable.
Angle’s targets lie somewhere between traditional conventional plays and
the idealized “manufacturing” resource play where every well is the same.
the technology shift to multi-stage fractured horizontal wells is increasing
the proportion of resource that can be produced at a profit – that can
become a reserve – in a number of reservoirs where vertical drilling could
D. gregg Fischbuch Chief Executive Officer
Angle’s Strategy and evolution
Management’s Q & AWith Heather Christie-Burns and D. Gregg Fischbuch
Angle energy inc 2010 ANNuAL RepORt8
let
te
r
And lastly the transition from very gas-focused to a combination of light oil and liquids-rich gas?
no longer achieve that. Angle’s approach is to identify large resources using
technical work and vertical exploratory drilling, then transform as much
as possible of those resources into reserves, using horizontal drilling with
multi-stage fracturing. For example, in our Mannville gas/condensate play
at Harmattan, we’re going from about a 15 percent recovery factor using
vertical wells to a potential recovery factor of 60-70 percent using horizontal
multi-stage fractured wells, which would achieve a dramatic increase in
reserves and value to shareholders.
the “unconventional” part is related to the use of technology on these
mid-quality conventional pools. Our view is that the best money will be
made from these “in-between” plays – plays that produced conventionally
since the 60s in some cases, but that can be exploited much more
successfully using the new technologies. We think these plays will generate
higher rates of return in this current commodity environment than the true
technical unconventional plays like shale gas.
Christie-Burns: First, Angle has always had high liquids content in its
vertically drilled gas plays, so no strategic shift there was required.
throughout our years of operation, over half of our revenue has come
from our NGLs production. As for the light oil pursuit, in drilling our
previous targets with vertical wells we’ve found a series of additional
formations that historically yielded light oil. But these finds weren’t very
productive as vertical wells. We were finding resources, not reserves.
the new technology, combined with the huge differential between gas
and oil prices, and Alberta’s royalty drilling incentives, opened a path to
making money drilling these light oil resources. We closely watched the
Cardium light oil play’s evolution in Alberta, and in 2010 advanced our
understanding of that play as it relates to our asset base. Our next oil
play became the Viking, which is present in thick deposits in our original
Harmattan core area. In 2011, we’re unlocking the components of all-in
per well cost, development pace and recovery factors.
Now, we see an opportunity to further strengthen our liquids netback,
with these light oil plays generating a netback of about $65 per boe,
compared to our 2010 operating netback of approximately $22 per boe.
that will lift Angle’s corporate netback, cash flow and overall valuation.
Angle energy inc 2010 ANNuAL RepORt 9
how far along is Angle in these three transitions?
Fischbuch: We’re about two steps into a three-step process. We called
the first phase “being in the lab”, testing and evaluating opportunities for
growth. that was what 2009 was all about, appropriate for a period of lower
commodity prices and capital expenditure. Last year, 2010, became the year
to test these plays with horizontal pilot programs. In this new style of play,
we need to drill at least five to 10 wells to generate a dataset to evaluate a
project’s rate of return and ultimately to gear our larger-scale development
plans.
We’ve established that we have very large oil, natural gas and liquids-in-
place in five separate plays, confirmed by third-party evaluators. We have
significantly reduced technical risks and established the economic and
operational parameters on three of these five plays. We have also diversified
the asset base, making the Company’s development more flexible. We now
have hundreds of well locations in our drilling inventory, far more visibility
of growth, and “optionality” enabling us to design our drilling program
according to commodity pricing and well results. Step three, in 2011, will be
about growing production and cash flow from these plays.
Where does Angle’s cost structure come in?
Christie-Burns: We’re a very low-cost operator, so we can sustain low
commodity prices and still make money on a field netback. Further, our
ability to improve our corporate netback is greater than that of our peers.
the way Angle initially grew, largely using farm-ins, as well as our focus
on natural gas liquids, created a relatively high royalty structure. In this
low gas price environment, the liquids are really working for us in terms of
their selling price and positive effect on F&D expense. Our netbacks are
“defensive” in that they’re not dependent in the long term on temporary
royalty incentives. As we transition to light oil, our netbacks per boe go up
substantially, and as we drill new wells on our Alberta Crown land positions,
our corporate netback also improves. Meanwhile, we intend to remain
highly efficient on the F&D and operating cost sides, sustaining a highly
competitive overall cost structure.
A
Angle energy inc 2010 ANNuAL RepORt10
how are you demonstrating that Angle specifically can make money in this Basin?
Christie-Burns: these new plays will yield a variety of individual well results
but will generate a rate of return over a number of wells on a project basis.
You need to do your geological homework, you need to drill your pilot wells
and find the best areas for development, before you know what will happen.
Our investors understand this careful, phased, project-based approach to
our Cardium and Viking plays. Also, corporate production growth has to
be viewed differently when variable commodities are being produced –
production per share and cash flow per share are not necessarily identical.
So, we are focusing on increasing the value of our barrels by growing our
light oil opportunities in lockstep with the most liquids-rich gas opportunities.
ultimately, a business is about cash flow and sustainable returns.
So what “is” Angle today?
Fischbuch: until 2009 we were seen as a small entity drilling successful
vertical wells with low costs. today we’re bigger, but we’re still a
low-cost operator and we continue to be a very good driller. Of our
13,500 boe per day in production exiting 2010, our drilling specifically
resulted in over 10,000 boe per day. In our 2010 acquisitions that added
3,200 boe per day, we targeted assets with drilling opportunities – we
weren’t “buying production”. today’s Angle is a company that in four
years has grown through the junior stages into the mid-cap and then
intermediate class in a controlled manner using an exploration-based
growth strategy. Angle today has multiple oil and natural gas plays to
drive further organic growth.
Angle energy inc 2010 ANNuAL RepORt 11
Speaking of mid-caps or intermediates, is there an ongoing role for this class of producer in the WcSB?
Christie-Burns: In the royalty trust era, the conventional wisdom was that
intermediates can’t survive. What we see now is a niche for producers with
more mass and good access to capital through cash flow, debt capacity and
capital markets to effectively develop resource-in-place oil and natural gas
plays. they can profitably exploit projects that lack enough ultimate mass
to sustain a senior producer, but are large enough to drill the multi-well
programs of generally higher-cost wells needed to prove up today’s play
types. this model is hard for a junior to handle at multiple play-type levels.
Following our growth through the junior stages, today’s size allows us to
take measured risks and absorb the early-stage costs of establishing and
proving several large new plays. the role now is to protect what we have,
operate with mass and continue to grow in a risk-managed way with several
paths to adding value.
let’s talk about the past year. First off, how did your results or achievements compare to your goals?
Christie-Burns: We feel good about production for the year, having exited
2010 at 13,500 boe per day, meeting our guidance. Growth in reserves per
share, even on a debt-adjusted basis, sets Angle in the top decile of its
peers – it has been stellar. What we’re excited to show our investors now
is the results of all our work in 2010, with growth in cash flow per share,
particularly on a debt-adjusted basis, and we’re confident that will occur
in 2011. Fully achieving all the goals we set in 2009 will take a couple
of years. the equity raises that diluted the shares in order to acquire
undeveloped land and assets, we are confident they will show the value on
a per share basis that is critical to our investors over the next two years of
our development.
2010 Results
Angle energy inc 2010 ANNuAL RepORt12
What were the operational highlights in 2010?
Fischbuch: One of the big highlights was getting the pipeline in place at
Lone pine Creek. that’s a 13-kilometre, 8” sour line, lying close to Calgary.
the project was completed as per forecast, largely because we did good
local consultation. that’s not as flashy as a huge well, but it’s key to the
play’s success. Another highlight was drilling three stellar Cardium wells,
including the sixth-best Cardium horizontal oil well in the entire province,
according to a CIBC report. And we have the number-one Viking horizontal
oil well in the province, based on publicly available data, also referenced
in that report. these results show we’re doing our technical work and
learning where the resource sweet spots are. that bodes well for
future development.
A company gearing up for multi-year value growth goes through several
steps. the first is creating an equity platform – i.e., using funds to acquire
the lands you need – and that creates short-term dilution because you’re
not adding reserves or production. Second is demonstrating reserves
growth per debt-adjusted share through successful exploration drilling,
which generates net asset value per share – and that happened in 2010.
the next step is to show cash flow and production growth on a
debt-adjusted per share basis. that’s what we’re determined to show on
a quarterly basis in 2011, without additional shares going out of the house.
We have measured and we respect the value of our common equity in
relation to where we see the drilling taking the per share valuations.
Angle energy inc 2010 ANNuAL RepORt 13
how were your financial results, and what do they tell us?
Christie-Burns: Our financial results show that we generated a positive rate
of return in 2010, even in a transitional year, with year-over-year growth
in our recycle ratio. We understand that we’re a business, and we want to
achieve the best rate of return. Our goals in 2010 were to drill across our
asset base, understand the variability, and then learn how to optimize the
drilling, completions, tie-ins and production parameters for larger-scale
development drilling. Our cost structure per well was high in 2010, due
to this phase of research experimentation, and we believe we can bring
it down in 2011. For example, in drilling to get the best reservoir data to
set up future development, a new location can be miles from the nearest
well site and gathering line. When you develop, you lower per-well costs
through measures like drilling multiple wells from common pads, which
is the focus in 2011. We expect to further strengthen our recycle ratio in
2011, by targeting higher netbacks per boe and being more efficient in our
development programs.
What are the strategic and resource benefits of the new edson play area?
Fischbuch: this is a true multi-zone, liquids-rich natural gas area with
large resource-in-place and running room for multiple drilling seasons.
What we call “Old Angle” had only two areas, Harmattan from the start,
and Ferrier since 2007. We needed portfolio diversification, to broaden
our development opportunities, but also on an infrastructure basis, to
become less dependent on a single key gas plant. the Alberta Deep Basin,
of which edson is a part, is an extension of the technical expertise we have
as a team. that positioned us to go in and accelerate an underexploited
area that the company we acquired, Stonefire, had demonstrated offers a
highly favourable cost structure even on a vertical drilling basis. Our initial
horizontal results in the Wilrich and Notikewin formations at edson have
been good.
Angle energy inc 2010 ANNuAL RepORt14
how comfortable are you with your current balance sheet? Are your capital constraints holding you back?
Christie-Burns: We are comfortable with our current balance sheet, as we
see debt as being in a direct relationship with corporate risk. Currently,
we carry lower risk due to our methods of resource exploitation, which is
amenable to a higher debt structure. We financially geared the Company
in 2010 to allow us to achieve our development goals, and don’t feel we are
capital-constrained.
the $60 million debenture issue in mid-December was the best method
to provide the needed financial flexibility without undue dilution to our
shareholders. It was a superior option to selling assets, because we
reviewed all our assets and determined they are stronger for remaining in
Angle than being sold. the debenture comes with a very good interest rate,
securing our access to capital with a locked-in rate at a time when interest
rates appear likely to rise.
the balance sheet is important, but so is when and how you use it. We had
almost no debt until 2009, to offset our high technical risks as an
exploration-oriented vertical driller. then we had the opportunity to buy
Stonefire, a fantastic Deep Basin asset. We followed this with an asset
purchase in the Deep Basin from Compton petroleum, complementing
our initial position. Also, Angle purchased a significant Alberta Crown
land position to extend its Viking light oil play in Harmattan. this was the
“collection” phase. Right now, it’s time to develop and drill our assets,
to establish an appropriate share value before beginning the next cycle
of “collection”.
We exited 2010 having achieved a very strong production rate of
13,500 boe per day, demonstrating significant volume growth. Our 2011
budget, announced in January, meets our exploratory and natural
gas-related commitments while doubling the well count for our Viking
oil play and allocating capital for each of our growth plays.
Outlook and 2011 plans
Angle energy inc 2010 ANNuAL RepORt 15
What are your main goals for 2011?
Christie-Burns: the biggest is demonstrating growth in production and
cash flow per debt-adjusted share. We want to show the investors who
gave us money that there were good reasons for doing so. In addition, we
want to continue showing reserves growth per share. By exploiting oil, we
can increase the value of our barrels of reserves. We see exposure of up to
12 million oil barrels that we could add to our book, by showing that our oil
plays are valid, repeatable and moving into development. In addition, we
intend to reduce per-well costs by moving from the experimental/testing
phase into the development phase, which will help to improve metrics
across the board. In 2011 we should corporately be able to generate a
netback of about $25 per boe combined with top quartile F&D costs.
We’re looking at increasing the netback due to light oil and liquids content
while bringing down the F&D costs by exploiting all our previous work.
Fischbuch: prices appear set to remain weak for the first half of 2011, but
very little of Angle’s 2011 program hinges on the gas price. If natural gas
averages only $3.50 per mcf in this first half, our budget would only change
by about two wells. Our Mannville gas/condensate pool at Harmattan has
190 bbls of liquids per mmcf and our lowest corporate operating costs,
making it profitable at a very low price. It also meshes operationally with
our Viking oil play, as we can drill wells into two completely different plays
from common drilling pads. Our short-term activities have optionality. It’s all
about making the best uses of limited dollars.
is there anything investors should be concerned about pertaining to the conversion to international Financial reporting Standards?
Fischbuch: We don’t see anything overly negative in the conversion results.
the oil and natural gas exploration and production business is primarily a
cash flow business, and the switch to IFRS largely affects earnings. We don’t
see anything major changing in the way we depreciate assets. there was
talk of carrying and depreciating producing assets in much smaller units,
Are Angle’s plans seriously exposed to a drop in natural gas prices? Are there things that offset or limit the price risks?
Angle energy inc 2010 ANNuAL RepORt16
We’ve talked about “Old Angle” and “today’s Angle”. What about “Future Angle”? What will come out of all the transitions that we’ve talked about?
Christie-Burns: there is enormous upside in our assets, including a huge
drilling inventory that becomes lower-risk each year. We can see a path
on the assets that we own to double our net asset value, without further
acquisitions, based only on identified well opportunities. that would be
achievable within two to three years. We see this medium term as being
about demonstrating the valuation that we believe we should have, based
on the plays that we have initiated, that we now intend to drill at a higher
rate of wells per year.
Along the way, we continually ask ourselves about the management of each
asset: is it more valuable if we continue to operate it, or is it more valuable
if we sell it? Right now we’re comfortable that we should be the owner
and exploitation manager of our plays, because they remain at a relatively
early stage and we see them containing significant further value through
development. In the future, we might sell an asset that is more valuable to
the Company through disposition than further development drilling.
there are also times when we recognize our valuation in the market as a
tool to ”collect” new assets or project areas for the Company to enhance its
plans. Moving beyond the 20,000 boe per day level will likely involve such a
collection phase. However, when we acquire, it’s to increase the value of the
acquired asset – to drill on it. We don’t see any future for us where Angle
is an acquisition machine. the source of growth for our company is drilling,
and always will be drilling.
Heather Christie-Burns Gregg Fischbuch,
president & Chief Operating Officer Chief executive Officer
March 14, 2011
possibly right down to separate field compressors, but in our case
we were able to organize this based on core areas, which is more
logical. the IFRS conversion itself is somewhat confusing to people.
everyone has to issue two sets of books for 2010, so the main thing
is people coming to grips with the differences in terminology,
presentation and discussion.
Angle energy inc 2010 ANNuAL RepORt 17
CALGARY
EDMONTON
EdsonDeep Basin liquids-rich gas
FerrierCardium light oil
Lone Pine CreekWabamun gas
HarmattanViking light oilMannville liquids-rich gas
Angle Core Area
Edmonton
Calgary
Alberta
exploration and Operations ReviewA Full-Cycle Value Approach
After five years of steady, drillbit-driven growth as a junior
exploration and production company, Angle entered 2010 with a
transformative agenda:
• Growing to a mid-cap and then an intermediate producer by
achieving volumes substantially greater than 10,000 boe per day;
• Establishing a new core area in the liquids-rich Deep Basin
around edson;
• Benefiting from higher oil prices by adding light oil to its
production stream and driving up the overall corporate netback;
• Taking a dramatic turn in its drilling focus, from vertical to
horizontal wells; and
• Proving up, delineating and de-risking several key new plays.
Horizontal drilling was key to the
2010 program. the greater reservoir
contact area created by a horizontal
wellbore that is hydraulically fractured
in multiple stages enables profitable
development of a wider range of
reservoir quality. As well as opening
up previously undrained reservoirs,
this technology also greatly increases
the recovery of known resources that
may already be partially developed
with low-recovery-factor vertical
wells. It is far less restrictive than
vertical drilling, which must focus
on the best parts of a reservoir. this
technology shift thereby transforms
much more resource-in-place into
producing reserves.
Angle delivered success across the
board. production exiting 2010 was
13,500 boe per day, delivering growth
of 80 percent over year-end 2009.
thirty of 34.5 net wells drilled in
2010 were horizontal and included
stellar results in the Cardium, Viking,
Mannville and Wabamun, with
individual wells coming on-stream
at up to 1,900 boe per day. the
Cardium and Viking light oil programs
established high-value “sweet spots”,
positioning Angle to drive profitable
growth in light oil volumes. proved
and proved plus probable reserves
tripled year-over-year, lengthening
the Company’s reserve-life-index to
12.1 years based on exit production.
Angle energy inc 2010 ANNuAL RepORt18
Op
er
At
iOn
S
Increasing productionIncreasing cash flow
Exploitation drillingOptimizing all aspects
Production growthIncreasing well inventory
Land/seismic acquisitionAppraisal drilling
Understanding the reservoirInfrastructure
Value buildbegins
Reapingrewards
Project Life
Building full-cycle corporate value
Moving the needle
05 06 07 08 09 10
600
500
400
300
200
100
0
Shareholders’ equity ($mm) Total assets ($mm)
Angle energy inc 2010 ANNuAL RepORt 19
Land – a Key exploration Driver
An oil or natural gas lease is traditionally
considered “developed” when a section
(640 acres) of land has reserves assigned to it
from one successful well. Historically, producers
were seen as requiring vast undeveloped land
areas to sustain their growth. today’s approach
of developing successive play types in stacked
reservoirs underlying a common land area
renders this traditional view largely irrelevant.
It matters far less how much “undeveloped”
land a producer has, than how much land is
prospective for a particular targeted play.
Virtually all of Angle’s land holdings are
prospective for at least two – and often three
or more – separate productive oil or natural
gas-bearing zones, which lie stacked or
overlapping beneath the same land area.
the Deep Basin asset at edson, for example,
holds at least seven productive reservoirs.
Angle refers to this concept as “urban density”
vs. “urban sprawl” – each layer is a formation
with many sections of prospectivity, creating
running room in its own right. At Harmattan,
for example, Angle is developing a Mannville
gas condensate pool, is growing its Viking
oil development, and is establishing Cardium
potential – all on a common land base. In some
cases, the Company can drill horizontal natural
gas and oil wells into separate plays from
the same drilling pad – often on land already
classified as “developed”.
An asset portfolio with a concentrated
and highly prospective land base offers
advantages over sprawling amounts of raw
land. the producer can lever existing facility
infrastructure, improving capital and operating
efficiencies. the historical vertical well control
usually offered on developed lands provides
critical data in geological resource assessments
for new plays, and in planning horizontal
well locations.
Angle entered 2011 with a high-quality land
base prospective for numerous plays and
offering years of running-room with an
inventory of approximately 850 well
locations – and which continues to grow.
Running room keeps us drilling
Land picture
175,619 net undeveloped acres
248,069 total net acres
Angle energy inc 2010 ANNuAL RepORt20
2011 Growth plan
Angle entered 2011 with a diversified,
high-working-interest asset base of four core
areas – all in the high-quality “Golden Spine”
of west-central Alberta – with seven
large-scale light oil and natural gas play types.
the Company’s 850-well inventory, including
300 light oil drilling locations, creates years
of running room. the more diversified asset
base offers optionality to “design” each year’s
program according to prevailing commodity
prices, then adjust activities according to well
results and emerging opportunities.
Last year, Angle largely concluded the “first
half” of the exploration and development
cycle at several of its key plays. this included
substantial investment in land, facilities and
higher-risk delineation drilling, which helped
to de-risk the most promising growth plays.
In 2011 and beyond, Angle is moving into the
“second half” of the cycle, in which capital
spending is focused mainly on lower-risk
development drilling. Angle foresees driving
major production growth at lower incremental
cost, with better per-well results, generating
higher capital and operating efficiencies.
this year’s capital program is budgeted at
$150 million and will include 32.9 net wells,
of which virtually all will be horizontal wells
completed with multi-stage fracturing. the
program is focused on growing light oil
volumes plus the highest-return liquids-rich
gas opportunities. Angle aims to achieve
further growth in the corporate average
netback per boe of production. the Company
is targeting an exit production rate of
15,000-16,000 boe per day, of which
approximately 40 percent will be light oil
and NGLs. Angle’s current well inventory
offers visible organic drilling growth to
greater than 20,000 boe per day.
Angle energy inc 2010 ANNuAL RepORt 21
More Oil
Shifting to a higher-value commodity
Angle’s high-liquids natural gas-producing
properties create an ideal platform to
add volumes of higher-netback light oil at
competitive capital efficiency. the Company’s
extensive land base and control of area
infrastructure reduce the full-cycle cost to
develop a new project. existing landholdings
can be complemented by aggressive,
lower-cost land capture early in the
exploration cycle.
In addition, Angle levered a key technical
advantage in rapidly creating its successful
Cardium and Viking light oil plays. Years of
vertical drilling targeting liquids-rich natural
gas generated an extensive dataset of well
control indicating oil-bearing zones. these
oil-bearing horizons would not have been
economic to complete as vertical producers –
but the well logs pointed to vast oil-in-place
potentially accessible through horizontal wells
completed with multi-stage fracturing.
Angle’s successful Viking and Cardium
horizontal wells drilled at Harmattan and
Ferrier in 2010 (please see following
write-ups) added a combined 1,000 bbls per
day of stabilized light oil production exiting
the year. this new production is generating
netbacks as high as $65 per bbl, lifting the
Company-wide average netback for 2010.
the 2010 program positioned Angle for major
light oil production growth and improved
per well results in 2011 and beyond. the
early-stage delineation programs tested
reservoir variability, identified sweet spots
and generated data needed to refine the
numerous parameters in the drilling and
completions processes. Metrics recorded for
2010 represented full-cycle exploration costs
– including land capture, new facilities and
higher-cost exploration wells – but only
first-half-cycle value generation.
Beginning this year, production and reserve
additions will mainly incur second-half-cycle
drilling and completion costs while generating
full-cycle value. this should drive production
and reserves growth at low incremental cost,
resulting in increased netbacks and cash flow
per share and per boe, reduced F&D costs per
boe and a higher recycle ratio – better metrics
across the board.
In 2011 Angle is continuing to delineate its
Viking and Cardium oil plays, while pushing
them outward into new areas, such as
establishing Cardium potential at Harmattan
and edson. Half of this year’s capital budget
of $150 million is allocated to Viking and
Cardium oil development. this will fund the
drilling of a planned 15 net horizontal wells.
the Company is aiming to double light oil
volumes – entirely through the drillbit – to
greater than 2,000 bbls per day by
year-end 2011.
Angle energy inc 2010 ANNuAL RepORt22
Running room: Angle’s undeveloped land by play
Cardium – 195 net sections, 97% undeveloped
300 net sections,
83% undeveloped
Viking – 227 net sections, 90% undeveloped
Rock Creek – 250 net sections, 89% undeveloped
NotikewinFalher/WilrichGlauconitic/Bluesky
OstracodellerslieFernie
Wabamun – 204 net sections, 96% undeveloped
Angle energy inc 2010 ANNuAL RepORt 23
West Central Alberta – Cardium Light Oil
Angle’s strong presence from its pursuit of
multi-zone gas opportunities at Ferrier since
2006 created the initial dataset to develop
a Cardium light oil play around the Ferrier
Cardium pool. this new opportunity became
of interest after the Company assessed the
results from the industry’s early exploitation
in the “halo” around the historical pembina
Cardium pool.
the Cardium is a conventional reservoir to
which unconventional technology is being
applied in untapped pool areas not amenable
to historical techniques. the Cardium
sandstone around Ferrier lies at 2,200 metres
versus the typical 1,300-1,800 metres. this
meant Angle was pioneering a new variant on
the play. It’s an example both of Angle’s drive
to add light oil volumes and its shift from
vertical to horizontal drilling, combined with
the Company’s traditional focus on technical
excellence and unique thinking to develop
opportunities others overlook.
Following technical work to establish Cardium
prospectivity on Angle’s lands at Ferrier, in
January 2010 the Company began drilling
six horizontal wells on two land blocks,
representing the first half-cycle or testing
phase of the new play. the first four wells
were drilled with partners to reduce risks and
capital costs, while the year’s final two wells
were 100 percent Angle.
As expected, the reservoir proved variable.
Angle’s final Cardium well of the year tested
at 1,200 boe per day after eight days – the
sixth-best Cardium well for the entire
industry through year-end 2010. the latter
three wells outperformed the first three,
demonstrating the need to drill multi-well
batches when testing a new play. this first
round added a combined 600 bbls per day of
premium-priced light oil to Angle’s production
base exiting 2010.
With the best reservoir areas established at
Ferrier, Angle can proceed with development
to add high-netback production and cash
flow at declining risk. Repetition and further
technical work such as micro-seismic
monitoring will optimize key well parameters –
horizontal leg orientation, fracturing fluids
and the density and tonnage per stage of
hydraulic fracture treatments.
Concurrently, with successful Cardium wells
being drilled over a wide area of west central
Alberta, Angle intends to expand the play
over its extensive land holdings around
Harmattan and edson. Harmattan is where
the Company is also developing Viking oil
and Mannville liquids-rich gas (see following
pages).
Angle has budgeted to drill five
high-working-interest Cardium horizontal
wells in 2011 and a further 12 in 2012 from its
inventory of up to 220 locations. Angle is
targeting Cardium oil production of 1,200 bbls
per day exiting 2011, and foresees its Cardium
play generating a project-wide recycle ratio
of 3.6 times.
Angle energy inc 2010 ANNuAL RepORt24
Edson
Lone Pine Creek
Harmattan
Ferrier
Angle Land – Cardium Rights Cardium production
Value Drivers• Levering existing land base and
operating presence
• Premium-priced light oil
• Large oil-in-place per acre of reservoir
• High initial productivity and moderate per-well costs
• Strong returns on a multi-well project basis
2010 Area Summary
Land (net acres) 119,935
Avg. land working interest (%) 82
proved plus probable reserves (mmboe) 3.71
Angle energy inc 2010 ANNuAL RepORt 25
Harmattan – Viking Light Oil
Alberta’s Viking sandstone is being revitalized
after more than a half-century history as
a conventional light oil and natural gas-
producing reservoir. the Viking’s new iteration
is earlier-stage than the Cardium, and Angle
is an industry pioneer. this play levers Angle’s
solid presence at Harmattan. the Company’s
founding property is again demonstrating
the remarkable geological variety that keeps
generating new possibilities.
In 2009 Angle recognized opportunity to
create new value by drilling horizontal multi-
stage-fractured wells into a reservoir that
frequently showed up on the area’s vertical
well logs. the relatively low-permeability
or “tighter” Viking sands would not be
productive or economic as vertical wells. the
dramatic increase in wellbore contact created
by horizontal wells with multiple fractures was
the key to unlocking the up to 20 metres of
net pay offered by this reservoir.
Angle’s test phase involved pilot program
drilling over a wide land area, following
Company practice. Last year, five horizontal
wells were spread over 100 square miles
(three townships) to determine reservoir and
resource variability and find sweet spots.
Angle also conducted aggressive early-cycle
land capture, spending approximately
$35 million on Crown sales and property deals
to build its Viking play around Harmattan to
60 net prospective sections at high working
interest, before reports of drilling success
made these lands too expensive. the property
deals also furnished vertical well control to
help map the prospective area.
the first batch of wells came on-stream at
150-590 boe per day each and included the
most prolific Viking horizontal oil well drilled
in Alberta to date (based on public data). the
program generated combined production of
800 boe per day (including some natural gas
volumes) exiting 2010 after six months on
production for the earliest well. Last year an
independent third-party evaluation estimated
that Angle’s Viking lands hold discovered
petroleum initially-in-place of 471 million
barrels. this resource is largely untapped and
unbooked by Angle’s independent evaluators
on a reserve basis. Less than five percent of
the well inventory of 190 horizontal locations
has had reserves attributed.
Angle’s oil Viking wells are generating a
netback of approximately $65 per bbl at an
Alberta light oil par price of $85 per bbl (the
reservoir also generates some natural gas
and NGLs). Initial capital efficiencies have
averaged $33,000 per daily flowing boe
added. Angle now intends to demonstrate
across-the-board improvements to metrics
as the play enters the second half of the
exploration cycle. the Company will exploit
its large land base, existing infrastructure and
well control to add reserves and production
at high capital and operating efficiencies,
targeting a recycle ratio of 3.6 times in 2011
and beyond.
Results to date suggest Angle’s Viking play
could well outperform the Cardium. In 2011,
Angle plans to drill 12 horizontal Viking wells
and 15 in 2012, further delineating the play and
substantiating the inventory while initiating
Angle energy inc 2010 ANNuAL RepORt26
VIKING OILDEVELOPMENT
FAIRWAY
Angle Land – Viking Rights Angle – Viking producers Viking Oil producers Angle – 2011 Locations
0 3 6
miles
Value Drivers• Early entry, large land base, high average
working interest
• High-netback light oil – ~$65 per bbl on pure oil wells
• Massive reserve upside on large oil-in-place resource – minimal reserves booked to date
• Multi-year running room on 190-well inventory of horizontal locations
lower-risk development of known
sweet spots. the main technical focus
is to reduce variability, generate
consistently high oil-cuts and increase
average per-well performance. the
Company is targeting growth to 1,800
boe per day by year-end and up to
4,000 boe per day of high-netback
Viking light oil by the end of 2012.
2010 Area Summary
Land (net acres) 52,254
Avg. land working interest (%) 97
proved plus probable reserves (mmboe) 1.81
Angle energy inc 2010 ANNuAL RepORt 27
The economics of Angle’s liquids–rich gas playscombined Value
$6.14/mcf
Harmattan Mannville
combined Value $6.52/mcf
combined Value $7.79/mcf
Sales dry gas value ($/mcf)
Lone Pine Wabamun
$2.81
$3.71
Edson Wilrich
$1.81
$4.34
$4.80
$2.99
Liquids-equivalent price ($/mcf)
Natural Gas
Making it economic through NGLs content and operating efficiencies
Western Canada’s higher-quality natural
gas reservoirs continue to be profitable at
current commodity prices if managed in the
right hands. At multiple plays over successive
years, Angle has generated strong natural gas
economics through:
• Top-quartile capital efficiencies. For the year
ended December 31, 2010, the Company’s
all-in costs were only $14.30 per proved plus
probable boe of reserves added;
• Low operating and all-in cash costs to
generate reasonable production netbacks;
• Consistent focus on pools rich in natural gas
liquids.
Liquids are valuable commodities
benchmarked to crude oil (see chart,
opposite), levering the profitability of natural
gas operations. today’s strong crude oil
pricing gives NGLs, on average, double the
value per boe of natural gas. Since Angle’s
inception, liquids content has consistently
generated more than half of corporate
revenue and has lifted the average corporate
netback per boe.
Company-wide average NGLs content of
Angle’s production in 2010 was 84 bbls per
mmcf of sales gas. At Harmattan, the average
NGLs content averages 160 bbls per mmcf
of sales gas – five to 10 times the NGLs
concentration of competing reservoirs
such as the Deep Basin, widely touted as
liquids-rich. In 2010 Angle’s NGLs content
added revenue of $1.81 to $4.80 per mcf –
more than doubling the Company’s equivalent
natural gas sales price to over $7.50 per mcf.
Angle’s NGLs production totalled 2,892 bbls
per day in 2010, generating sales revenue of
$45.42 per bbl.
Angle energy inc 2010 ANNuAL RepORt28
Natural gas liquids: The upside of Angle’s gas production
Fourth Quarter 2010
C5+ Condensate 28% Dilutes heavy oil/bitumen for transport
C4 Butane 15% Blending fuel in refineries
C3 propane 27% Winter heating fuel and other uses
C2 ethane 30% production of ethylene in petro-chemical industry
market
Methane (dry gas)
Natural Gas Liquids (NGLs)
NGLs production
3,495 bbls/dNGLs revenue
$48.75/bblNGLs yield
82 bbls/mmcf
Succeeding in liquids-rich natural gas
operations requires control of or secure
access to key facilities, both to bring new
production on-stream quickly and to
transform raw gas into separate saleable
commodities. Angle is strongly positioned
in this regard. At Harmattan, Company
production is processed through a “deep-cut”
third-party facility that extracts all liquids.
At Ferrier, Angle operates its own gathering
and compression facilities, with processing
from a mid-stream operator. At Lone pine
Creek, the Company’s new 13-km, 8” diameter
gas pipeline ultimately connects to an
underutilized third-party gas plant. At edson,
Angle is installing a second, 100 percent-
owned gas processing facility to increase
out-take capacity by 10 mmcf per day, giving
Angle integrated control of gathering systems,
compression and processing.
Fundamentally, making money from natural
gas in western Canada requires the technical
expertise to identify high-potential new plays,
the exploration ability to locate and delineate
new pool areas, and the operating discipline
to generate repeatable successes at declining
per-well costs and continually improving
metrics. At Harmattan, Ferrier, Lone pine
Creek and edson, Angle has proved its ability
to succeed on all counts.
Angle energy inc 2010 ANNuAL RepORt 29
Harmattan – Mannville Liquids-Rich Gas
Angle’s Harmattan asset illustrates the
profitability found in high-quality, liquids-rich
reservoirs. Harmattan is where Angle began
operations in 2005 through a farm-in to drill
for Mannville natural gas. Repeated vertical
drilling success in the Mannville pushed out
the play’s boundaries and was followed by
exploring the more technical elkton carbonate
reservoir. Angle’s concept at Harmattan (as
with the Company’s more recent Wabamun
gas play at Lone pine Creek) has been
to locate pool extensions to high-quality
historical reservoirs that the conventional
wisdom considered tapped out.
Angle’s Mannville pools offer the highest
liquids content in western Canada – up to
195 bbls per mmcf of sales gas, spanning
the NGLs spectrum from ethane (C2) to
condensate (C5+). the extraordinary liquids
content is a function of the reservoir’s
complex geological history, which may
have included successive hydrocarbon-
charging events.
production at Harmattan entering 2010 had
grown to 4,900 boe per day from 42 vertical
producers. production is taken to a third-party
facility with “deep cut” capacity that extracts
the full array of NGLs. this yields an average
netback of up to $27.00 per boe – very high
for natural gas production.
entering 2010 Angle’s objective was to
establish the feasibility of increasing
per-well productivity, resource recovery and
overall capital and operating metrics through
horizontal drilling. Angle began drilling
Mannville horizontal wells in the second
half of 2010.
the first well, with a horizontal leg of only
400 metres, was completed with three
fractures and came on-stream at an initial
rate exceeding 500 boe per day. the second
well, with a 1,065-metre horizontal leg and
10 fracture treatments, was literally “off the
chart” and production was monitored for
two months before the well’s capability was
disclosed in Angle’s February 2011 operational
update. the well averaged 1,900 boe per day
over its first two months, with 44 percent of
this volume being natural gas and 66 percent
NGLs. A third horizontal well, similar in length
and completion to the second, finished testing
in late February at approximately 1,500 boe
per day. these results are exceeding the
Company’s expectations.
With these tremendous initial results, Angle
intends to continue exploitation of the known
pool area with horizontal wells. two further
horizontal Mannville wells were underway
in the first quarter of 2011, with four more
planned this year and an additional 30
by 2014. Angle’s goals are to lever all the
benefits of post-exploration, second-half cycle
economics: high-rate production additions
at low risk, increased recovery of in-place
resources and improved metrics across
the board.
Angle energy inc 2010 ANNuAL RepORt30
AltaGasPlant
9-5Compressor
PengrowthCompressor
PengrowthPlant
Angle Land – Mannville Rights Angle – Mannville producers Angle – 2011 Locations
0 3 6
miles
Value Drivers• Extremely high liquids content generates
excellent netbacks
• High-rate wells yield strong capital and operating efficiencies
• Reserve and production growth through multi-well horizontal exploitation
2010 Area Summary
Land (net acres) 40,385
Avg. land working interest (%) 95
proved plus probable reserves (mmboe) 19.89
Angle energy inc 2010 ANNuAL RepORt 31
Deep Basin/edson – Liquids-Rich Multi-Zone Natural Gas
Angle’s new edson core area in the
liquids-rich Alberta Deep Basin is a gem
of an asset that could hold the greatest
long-term value in the Company’s portfolio.
the Deep Basin is highly attractive for its
multiple productive zones, large resource-
in-place, broad geographical extent, liquids
content, long-life production and low
operating costs. Its geology is similar to the
Company’s existing operations at Ferrier,
and senior Angle personnel had previous
experience in the Deep Basin, making it
complementary to Angle’s other properties.
the new core area was created in January
2010 through the $75 million acquisition of
Stonefire energy Corp. Stonefire had built
up a high-quality, concentrated play north of
edson through vertical drilling. In June 2010
Angle followed up with a $115 million
property acquisition from Compton petroleum
Corp. All told, Angle acquired 115 net sections
of high-working-interest lands plus control
of key infrastructure, with approximately
3,200 boe per day of low-decline, mainly
vertical well production. the two transactions
created a strategic new asset diversifying
the Company’s operations geologically,
geographically and on a facility basis,
with many years of running room to add
production and reserves.
Angle was drilling new wells within two weeks
of the Stonefire deal. the objectives for 2010
were to maintain field-wide production while
beginning to test key reservoirs through
horizontal, multi-stage-fractured wells. Over
the previous two years area competitors
had achieved exciting results in the Bluesky,
Notikewin, Wilrich, Cadomin, Cardium, Rock
Creek and Fernie formations, all part of the
Cretaceous Deep Basin column.
Angle’s seven-well program in 2010
consisted of two multi-zone vertical wells,
two Notikewin horizontal wells and three
Wilrich horizontal wells. Vertical wells serve
to delineate and core the area’s multiple
reservoirs, important to planning horizontal
programs. the horizontal wells delivered
moderately good initial results of up to
3.5 mmcf per day plus NGLs, but were not
considered representative of the area’s
true potential. Angle’s experimental use of
propane-based fracturing, which works well
in other areas, may not have been optimal
for the Wilrich. this year the Company will
use slickwater fractures with heavier sand
tonnage, which have yielded great results
for area competitors.
Angle foresees major long-term opportunity
to take this asset to the next level by
applying technology and capital to optimize
well drilling and completions and improve
per-well metrics. edson offers multiple
horizons delineated through vertical drilling
that are amenable to exploitation through
horizontal drilling. Angle’s land holdings
reflect the new way of thinking about
undeveloped land (please see page 20).
A given land section may have modest
vertical production and reserve assignments
– making it classified as “developed” – yet
Angle energy inc 2010 ANNuAL RepORt32
WILRICH/NOTIKEWINFAIRWAY
Angle Land - All Rights Angle Operated Facilities
Angle 2010 Gas Wells Angle 2011 Locations
0 3 6
miles
Value Drivers• High gas-in-place, with liquids
• Huge inventory of repeatable opportunities – over 300 locations entering 2011
• Low operating costs and long-life production
• Long-term production growth
still hold many billions of cubic feet
of untapped gas-in-place in each of
several horizons.
With a current inventory of over
300 horizontal and vertical drilling
locations, edson’s potential for major
volume growth with stronger natural
gas prices makes it a cornerstone
of Angle’s longer-term value. For
2011 Angle has budgeted to drill four
(3.1 net) horizontal wells targeting
the Wilrich and Bluesky and aims to
maintain field-wide production at
current rates. Accelerated activity
would be driven by exceptional
per-well results and/or stronger
commodity prices.
2010 Area Summary
target zones Wilrich Bluesky Fernie
Land (net acres) 74,566
Avg. land working interest (%) 71
proved plus probable reserves (mmboe) 17.04
Angle energy inc 2010 ANNuAL RepORt 33
Lone pine Creek – High-Rate Wabamun Gas and Liquids
Angle’s creation of a new Wabamun play at
Lone pine Creek exemplifies the Company’s
technically-driven method. the Company’s
technical team had long believed that central
Alberta still held overlooked Wabamun natural
gas pools. Lying at an average depth of 2,350
metres, the Wabamun carbonate is one of the
most prolific gas reservoirs ever established in
the province, having driven much of Alberta’s
natural gas production in the 1960s, but was
considered at a dead end.
Analysis of certain well behaviour led Angle’s
team to conclude there was an overlooked
pool area in a broad swath between two aging
Wabamun producing areas. the pool just to
the south had generated 500 bcf over several
decades. One well to the north had delivered
30 bcf over 30 years – yet was still producing
1 mmcf per day. Another well showed
near-original reservoir pressure.
this evidence prompted several years of work
spent on low-key land assembly in an area of
mixed Crown and freehold rights plus existing
competitor leases. the new property, dubbed
Lone pine Creek, was ready to test by 2009.
Angle drilled one vertical exploratory well
plus the Company’s first-ever horizontal well,
both of which were tied-in and brought on-
production in 2009.
In 2010 Angle accelerated the new reservoir’s
delineation with a six horizontal well program,
all at 100 percent working interest. the
wells were completed with multi-stage acid
fracturing, averaging $3.3 million to drill and
complete. As expected for a conventional
reservoir, the program revealed considerable
variability – and found two prolific sweet
spots. the two northerly wells came
on-stream at initial rates of approximately
1.5 mmcf per day each. two further wells to
the south came on-stream at initial rates of
2.5-4.5 mmcf per day each.
the final two wells, drilled over the summer,
were by far the best, with one testing at
8 mmcf per day including 39 bbls of NGLs per
mmcf of sales gas. the new production was
tied-in to an underutilized gas plant via the
Company’s new, 13-km, 8” diameter pipeline.
Following extensive community consultation
in a populated area with landholder
sensitivities, the new pipeline entered service
in September.
Lone pine Creek’s very high-rate,
liquids-rich wells generate an estimated 5.3
times recycle ratio. exiting 2010 the new play
was producing a combined 4 mmcf of sales
gas per day plus liquids of approximately 200
bbls per day, with production restricted due
to compression limitations. Development of
the play’s two current sweet spots will include
up to 17 high-working-interest wells over the
next several years, beginning with five wells
planned for 2011. Angle is working with a
third-party processor to free up additional
capacity to process production from the wells
drilled in this area.
Angle energy inc 2010 ANNuAL RepORt34
PengrowthPlant
PengrowthCompressor
ApachePlant
WABAMUN GAS
Angle Land – Wabamun Rights Angle – Wabamun producers Wabamun producers Angle – 2011 Locations pipeline
0 3 6
miles
Value Drivers• High-rate wells – target
Ip 5-8 mmcf per day plus liquids
• Concentrated land base at 100% WI
• Large reserves per well – target 5 bcf
• > Five times recycle ratio
2010 Area Summary
Land (net acres) 24,566
Avg. land working interest (%) 100
proved plus probable reserves (mmboe) 7.78
Angle energy inc 2010 ANNuAL RepORt 35
Land
Undeveloped Developed Total
Gross Net Gross Net Gross Net
(acres) (acres) (acres) (acres) (acres) (acres)
december 31, 2010
Edson 55,040 44,825 45,760 28,806 100,800 73,631
Ferrier 27,520 26,259 14,230 10,018 41,750 36,277
Harmattan 53,468 52,372 28,238 27,051 81,706 79,423
Lone Pine Creek 31,290 31,290 4,835 4,835 36,125 36,125
Other 23,901 20,873 2,720 1,740 26,621 22,613
Total 191,219 175,619 95,783 72,450 287,002 248,069
December 31, 2009
Edson – – – – – –
Ferrier 22,839 21,435 13,124 7,957 35,963 29,392
Harmattan 30,609 29,254 27,443 26,048 58,052 55,302
Lone Pine Creek 26,588 26,588 1,294 1,294 27,882 27,882
Other 26,040 21,689 3,200 2,303 29,240 23,992
Total 106,076 98,966 45,061 37,602 151,137 136,568
At December 31, 2010 Angle controlled an additional 7,520 net acres of
undeveloped land through farm-in arrangements for a total undeveloped land
position of 183,139 net acres at year-end at an average working interest of
92 percent (2009 – 107,286 acres at 94 percent). This represents a 71 percent
increase in net undeveloped acreage year-over-year.
Seaton-Jordan & Associates Ltd., an independent land evaluations firm, evaluated
the controlling lands of Angle as at August 5, 2010 in accordance with the Canadian
Securities Administrators’ National Instrument (NI) 51-101 Standards of Disclosure
for Oil and Gas Activities. The result of this review was an estimated fair market
value of undeveloped land of $80.8 million (December 31, 2009 – $38.3 million).
In 2010 Angle aggressively built its prospect inventory, primarily in the Harmattan
area, targeting the Viking oil play via Crown land sales. The Company recognized
the potential of the land due to earlier vertical well results and was able to acquire a
controlling position in this emerging play prior to industry attention, thus acquiring
the lands at an attractive price point. In 2010, Angle expended approximately
$32.8 million at Alberta Crown land sales acquiring 39,340 net acres of petroleum
and natural gas rights at an average cost of $834.48 per acre.
Undeveloped Developed
Total Land(000s net acres)
47 71 98 137 24806 07 08 09 10
Operations Statistical Review
Angle energy inc 2010 ANNuAL RepORt36
Many of Angle’s lands are contained within the same land tenure documents that overlie productive petroleum and natural
gas rights and, as such, are not technically defined as undeveloped lands.
Angle’s ongoing land acquisition strategy is focused on building a significant land base of high-working-interest, internally
generated prospects, complemented by third-party farm-in arrangements in core exploration areas. The Company
will continue building a significant base of high-working-interest operated prospects, ensuring that the Company is in a
position to control its capital expenditure program.
ReseRves
GLJ Petroleum Consultants Ltd. (GLJ), an independent petroleum engineering firm, evaluated the natural gas, NGLs and
light crude oil reserves of the Company as at December 31, 2010 and 2009. GLJ based its evaluation on land data, well and
geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product
prices, operating cost data, capital budget forecasts and operating plans provided by Angle, and prepared its report in
accordance with NI 51-101. The required disclosure of the reserves estimates and future net revenue of the Company as
at December 31, 2010, based on forecast prices and costs, is outlined below along with the economic assumptions used
in preparing those estimates. For purposes of computing such units, natural gas is converted to equivalent barrels of oil
using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil. This conversion ratio of 6:1 is based on an
energy-equivalent conversion for the individual products at the burner tip and is not intended to represent a value
equivalency at the wellhead. Such disclosures of boe may be misleading, particularly if used in isolation.
summaRy of oiL and natuRaL Gas ReseRves
The following table outlines the oil and natural gas reserves of the Company, as at December 31, 2010, by product type
on a gross (before royalties) and net (after royalties) basis:
december 31, 2010 natural Gas nGLs Light Crude oil Combined total
Gross net Gross net Gross net Gross net
(mmcf) (mmcf) (mbbls) (mbbls) (mbbls) (mbbls) (mboe) (mboe)
Proved
Developed producing 72,270 60,303 6,065 4,114 1,257 1,029 19,367 15,193
Developed non-producing 4,083 3,589 224 160 54 40 958 798
Undeveloped 43,338 38,880 4,098 3,186 255 225 11,576 9,891
Total proved 119,691 102,771 10,386 7,459 1,565 1,294 31,900 25,882
Probable 105,426 89,528 9,081 6,434 1,144 894 27,796 22,249
Total proved plus probable 225,118 192,299 19,467 13,893 2,709 2,189 59,696 48,131
Note: Table may not be additive due to rounding.
Angle energy inc 2010 ANNuAL RepORt 37
net PResent vaLues of futuRe net Revenue
The net present values of future net revenue of the Company’s reserves, as at December 31, 2010, at various discount rates
on a before-tax basis are outlined below:
december 31, 2010 Before income taxes discounted at
(000s) 0% 5% 10% 15% 20%
Proved
Developed producing $ 498,260 $ 392,676 $ 326,646 $ 281,797 $ 249,408
Developed non-producing 22,886 18,214 14,998 12,677 10,936
Undeveloped 226,032 163,735 123,397 95,576 75,428
Total proved 747,178 574,626 465,041 390,050 335,773
Probable 686,771 419,839 284,256 205,194 154,565
Total proved plus probable $ 1,433,948 $ 994,465 $ 749,296 $ 595,244 $ 490,337
Note: Table may not be additive due to rounding.
The Company’s net present value of proved plus probable reserves, discounted at 10 percent before tax, was
$749.3 million at December 31, 2010, up by 171 percent from $276.8 million at December 31, 2009 despite lower
forecast natural gas prices which negatively affected the value of reserves at period-end 2010.
Proved Plus ProbableReserves by Commodity(Year-End 2010) (mboe)
2,709Light Crude Oil
19,467NGLs
37,520Natural Gas
Proved Probable
Net Present Values of FutureNet Revenue (BIT) (10% DCF) ($mm)
$146 $223 $273 $277 $749
06 07 08 09 10
Proved Plus ProbableReserves by Commodity(Year-End 2010) (mboe)
2,709Light Crude Oil
19,467NGLs
37,520Natural Gas
Proved Probable
Net Present Values of FutureNet Revenue (BIT) (10% DCF) ($mm)
$146 $223 $273 $277 $749
06 07 08 09 10
Angle energy inc 2010 ANNuAL RepORt38
ReConCiLiation of ComPany inteRest ReseRves By PRinCiPaL PRoduCt
The reconciliation of the Company’s gross proved, probable and proved plus probable reserves for December 31, 2010
is as follows:
Natural Gas NGLs
Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable
(mmcf) (mmcf) (mmcf) (mbbls) (mbbls) (mbbls)January 1, 2010 43,151 29,736 72,887 4,709 2,507 7,216
Technical revisions 3,487 (7,472) (3,985) 538 (228) 311
Drilling extensions 30,634 28,810 59,444 1,556 1,416 2,972
Infill drilling 14,219 20,124 34,343 3,318 4,398 7,716
Improved recovery 97 13 110 2 – 1
Acquisitions 40,604 34,216 74,820 1,319 988 2,307
Production (12,501) – (12,501) (1,056) – (1,056)
December 31, 2010 119,691 105,427 225,118 10,386 9,081 19,467
Light Crude Oil Total
Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable
(mbbls) (mbbls) (mbbls) (mboe) (mboe) (mboe)
January 1, 2010 408 261 669 12,309 7,724 20,033
Technical revisions (93) (88) (181) 1,027 (1,561) (534)
Drilling extensions 906 578 1,484 7,568 6,795 14,363
Infill drilling 88 22 110 5,776 7,774 13,550
Improved recovery – – – 18 2 20
Acquisitions 491 371 862 8,577 7,062 15,639
Production (235) – (235) (3,375) – (3,375)
December 31, 2010 1,565 1,144 2,709 31,900 27,796 59,696
Note: Table may not be additive due to rounding.
Angle energy inc 2010 ANNuAL RepORt 39
summaRy of PRiCinG and infLation Rate assumPtions
The economic parameters, as determined by GLJ, assumed in preparing the forecast prices and costs reserve report are
outlined below:
natuRaL Gas PRiCe foReCast – effeCtive JanuaRy 1, 2011
AECO Alberta Plant Gate
NIT Spot Spot
Then Constant Then Year Current 2011 $ Current ARP Aggregator Alliance
(Cdn$/mmbtu) ($/mmbtu) ($/mmbtu) ($/mmbtu) ($/mmbtu) ($/mmbtu)
2010 4.17 4.00 3.93 4.17 3.73 3.30
2011 4.16 3.92 3.92 3.89 3.78 3.37
2012 4.74 4.42 4.51 4.37 4.34 4.00
2013 5.31 4.87 5.06 4.91 4.88 4.59
2014 5.77 5.20 5.52 5.35 5.32 5.08
2015 6.22 5.52 5.97 5.80 5.76 5.57
2016 6.53 5.69 6.28 6.09 6.05 5.91
2017 6.76 5.77 6.50 6.31 6.26 6.13
2018 6.90 5.79 6.65 6.45 6.41 6.27
2019 7.06 5.80 6.80 6.60 6.55 6.42
2020 7.21 5.82 6.95 6.75 6.70 6.56
2021+ +2.0%/yr 5.82 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
LiGht CRude oiL and nGL PRiCe foReCast – effeCtive JanuaRy 1, 2011
Bank of NyMEx WTI Near Month Light Sweet
Canada Futures Contract Crude Oil Alberta NGLs
Average Light Crude Oil at (40° API, 0.3%S) (Then Current Dollars)
Noon Cushing Oklahoma at Edmonton Edmonton Exchange Constant Then Then Spec Edmonton Edmonton Pentanesyear Inflation Rate 2011 $ Current Current Ethane Propane Butane Plus
(%) (US$/Cdn$) (US$/bbl) (US$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl)
2010 1.8 0.971 80.86 79.42 78.02 – 46.87 65.59 84.04
2011 2.0 0.980 88.00 88.00 86.22 13.66 54.32 67.26 90.54
2012 2.0 0.980 87.25 89.00 89.29 15.68 56.25 68.75 91.96
2013 2.0 0.980 86.51 90.00 90.92 17.62 57.28 70.01 92.74
2014 2.0 0.980 86.69 92.00 92.96 19.21 58.56 71.58 94.82
2015 2.0 0.980 87.92 95.17 96.19 20.79 60.60 74.07 98.12
2016 2.0 0.980 88.35 97.55 98.62 21.85 62.13 75.94 100.59
2017 2.0 0.980 89.03 100.26 101.39 22.62 63.87 78.07 103.42
2018 2.0 0.980 89.44 102.74 103.92 23.14 65.47 80.02 106.00
2019 2.0 0.980 90.00 105.45 106.68 23.67 67.21 82.15 108.82
2020 2.0 0.980 90.00 107.56 108.84 24.20 68.57 83.80 111.01
2021+ 2.0 0.980 90.00 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Angle energy inc 2010 ANNuAL RepORt40
ReseRve-Life-index
The reserve-life-index (RLI) of Angle has been calculated using 2011 estimated production volumes and gross proved and
proved plus probable reserves using forecast prices and costs, all of which were taken from the December 31, 2010 GLJ
reserve report. The RLI of the Company as at December 31, 2010, on a boe basis, was 5.9 years (December 31, 2009 – 5.1 years)
for total proved reserves and 9.4 years (December 31, 2009 – 7.3 years) for total proved plus probable reserves.
Proved Plus Proved Proved Probable RLI Plus Expected Expected Proved Proved Probable 2011 2011 RLI Plus Reserves Reserves Production Production Proved Probable
(years) (years)
Natural gas (mmcf) 119,691 225,118 19,907 23,249 6.01 9.68
NGLs (mbbls) 10,386 19,467 1,741 2,075 5.97 9.38
Light crude oil (mbbls) 1,565 2,709 357 434 4.38 6.24
Total (mboe) 31,900 59,696 5,416 6,384 5.89 9.35
ReseRve RePLaCement Ratio
year ended december 31, 2010 Proved Proved Plus Probable
Light Light Crude Natural Crude Natural Oil Gas NGLs Combined Oil Gas NGLs Combined
(mbbls) (mmcf) (mboe) (mboe) (mbbls) (mmcf) (mboe) (mboe)
Reserve additions, including revisions 1,392 89,041 6,733 22,966 2,275 164,732 13,307 43,038
Production 235 12,501 1,056 3,375 235 12,501 1,056 3,375
Reserve replacement ratio 5.9 7.1 6.4 6.8 9.7 13.2 12.6 12.8
Undeveloped Developed
Proved (years)
4.7 4.3 4.0 5.1 5.9
06 07 08 09 10
Undeveloped Developed
Proved Plus Probable (years)
7.8 5.5 5.0 7.3 9.4
06 07 08 09 10
reserve-life-index year ended December 31, 2010
Angle energy inc 2010 ANNuAL RepORt 41
findinG and deveLoPment Costs
The following table provides detailed calculations related to finding and development (F&D) and finding, development
and acquisition (FD&A) costs and recycle ratios for 2010 and 2009. These have been calculated in accordance with
NI 51-101, Part 5.
years Ended December 31
three-year 2010 2009 2008
(000s) ($) ($) ($) ($)
Capital expenditures
Exploration and development 303,242 184,675 39,140 79,427
Proved – change in future capital (exploration and development) 51,911 48,249 12,613 (8,951)
Proved plus probable – change in future capital (exploration and development) 143,683 125,791 28,252 (10,360)
Acquisitions 221,535 196,510 25,025 –
Proved – change in future capital (acquisitions) 47,768 47,768 – –
Proved plus probable – change in future capital (acquisitions) 108,550 108,550 – –
(mboe) (mboe) (mboe) (mboe)
Reserve additions
Proved
Exploration and development 12,383 10,326 (212) 2,269
Acquisitions 10,324 9,265 1,059 –
Production 8,532 3,374 2,748 2,410
Total added reserves 31,239 22,965 3,595 4,679
Proved plus probable
Exploration and development 28,452 23,336 2,819 2,297
Acquisitions 17,606 16,327 1,279 –
Production 8,532 3,374 2,748 2,410
Total added reserves 54,590 43,037 6,846 4,707
($/boe) ($/boe) ($/boe) ($/boe)
finding and development Costs
Proved (including future capital)
Total finding and development costs 16.98 17.00 20.41 15.06
Total finding, development and acquisition costs 19.99 20.78 21.36 15.06
Proved plus probable (including future capital)
Total finding and development 12.08 11.62 12.11 14.67
Total finding, development and acquisition costs 14.23 14.30 13.50 14.67
FD&A recycle ratio – proved 1.1 1.1 0.8 2.1
FD&A recycle ratio – proved plus probable 1.6 1.5 1.3 2.1
(1) For a description of the boe conversion ratio, refer to the commentary in the Management’s Discussion and Analysis.(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated
future development costs may not reflect total finding and development costs related to reserve additions for that year.
Angle energy inc 2010 ANNuAL RepORt42
The Company reduced F&D and FD&A costs on proved reserve additions despite spending a record $36.3 million on
undeveloped land, primarily in the Harmattan Viking light oil play, along with $13.8 million on facilities in 2010. These
expenditures will provide future value via drilling and control of infrastructure in years to come. Angle also reduced F&D
costs while slightly increasing FD&A cost for proved plus probable reserve additions in 2010.
The recycle ratio measures the efficiency of capital investment. It accomplishes this by dividing the FD&A cost per boe by
the year’s operating netback per boe (3 year average – $22.96, 2010 – $22.18). The Company targets a recycle ratio of 2.0
or better for corporate activities. In 2010, Angle did not achieve this target due to the large increase in future development
costs and the land and facility expenditures mentioned on page 42.
net asset vaLue
The following table details Angle’s net asset value at December 31, 2010 and 2009:
December 31 2010 2009
(000s, except per share data)
Present value of petroleum and natural gas reserves (1) $ 749,296 $ 276,847
Net undeveloped land (2) 80,801 20,335
Bank debt and working capital deficiency (152,378) 38,255
Seismic data (3) 8,000 8,000
Proceeds from stock options (4) 33,036 18,152
net asset value $ 718,755 $ 361,589
Diluted shares outstanding (#) (5) 77,810 58,862
net asset value per share $ 9.24 $ 6.14
(1) Total proved plus probable, discounted at 10 percent, before tax per the GLJ December 31 reserve evaluations.(2) As evaluated by Seaton-Jordan & Associates Ltd., effective August 5, 2010 and December 31, 2009.(3) Estimated replacement value of seismic data.(4) Calculated proceeds from in-the-money options using a 2010 year-end closing common share price of $8.30 per share (2009 – $6.72 per share).(5) Calculated as basic shares outstanding at December 31 plus in-the-money options.
Angle’s net asset value at December 31, 2010 increased to $718.8 million, up
by 99 percent from $361.6 million at December 31, 2009. On a per share basis,
net asset value increased by 50 percent to $9.24 per share from $6.14 per
share at December 31, 2009. Angle’s average net undeveloped land value per
Seaton-Jordan & Associates Ltd. was $442.11 per acre at August 5, 2010 and
$198.06 per acre at December 31, 2009. Although undeveloped land acreage
has increased since August 5, 2010, Angle did not commission an independent
report as at December 31, 2010.
Net Asset Value($/Share)
$4.56 $5.84 $7.07 $6.14 $9.24
06 07 08 09 10
Angle energy inc 2010 ANNuAL RepORt 43
Financial ManagementFunding Our Growth
Like nearly all oil and natural gas producers,
Angle requires large investments of capital
beyond self-generated cash flow to fund growth
in its financial and operational measures.
It is essential that we raise this required
capital on the most favourable terms and at
appropriate times, and focus it towards the best
development and/or acquisition opportunities to
achieve profitable growth for our shareholders.
Angle’s operations have been funded through
a combination of sale of our common shares,
internally generated cash flow and debt. From
its inception in 2004 to December 31, 2010
Angle made capital investments totalling $504
million, including land purchases, well drilling
and completions, and construction of
facilities. In 2010 we also invested $190
million to assemble a new core area at
edson through a corporate acquisition
and an asset transaction. Since
the Company’s inception,
Angle’s capital program has
been funded 46 percent
from the net proceeds of
issuing common shares,
34 percent from internally
generated cash flow and
the balance of
20 percent through debt.
Stuart Symon Chief Financial Officer
heather postController
During this period we have raised equity at
share prices ranging from $0.60 to a high of
$10.05 for flow-through common shares issued
in November 2010. Angle also has a revolving
committed credit facility with three Canadian
chartered banks with a borrowing base of
$180 million, and in January 2011 raised an
additional $60 million in convertible unsecured
subordinated debentures, for total debt capacity
of $240 million. Angle has historically maintained
a strong financial position through its prudent
use of equity and debt. We target a debt to
forward cash flow ratio of not greater than 2:1 to
ensure ongoing liquidity.
Angle energy inc 2010 ANNuAL RepORt44
heather postController
On a forward basis, we must project our capital
needs through vigorous budget modelling and
comparison to actual results for all aspects
of our business. this helps us understand our
capital needs and timing, and seek continual
improvements in cost control and operational
methods. We control those elements of our
business that we can directly influence, and
seek to mitigate elements over which we have
less control, such as commodity prices. Angle
employs financial instruments such as forward
sales contracts for natural gas and crude oil to
mitigate the inherent volatility of pricing and to
fix a portion of its cash flow, which ensures that
the Company can carry out its planned capital
projects. Angle will have less than 50 percent of
its oil and natural gas production hedged at all
times. We may increase our position in relation
to changes in the commodity markets and our
debt ratios.
Angle is subject to numerous risk factors
inherent to the oil and natural gas industry and
some that are global in nature. We identify these
risks and implement risk-mitigation programs
wherever possible. Angle maintains a system
of internal and disclosure controls designed to
protect its assets and ensure their use is properly
authorized. Full discussion of these issues is
included in the Management’s Discussion and
Analysis. In addition, we maintain a Corporate
Conduct Handbook that sets out expected
corporate business and securities conduct for all
staff and consultants.
Angle energy inc 2010 ANNuAL RepORt 45
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management’s Discussion and Analysis (MD&A) reports on the financial condition and the results of operations
of Angle Energy Inc. (“Angle” or the “Company”) for the three months and years ended December 31, 2010 and 2009 and
should be read in conjunction with the audited consolidated financial statements and accompanying notes. All financial
measures are expressed in Canadian dollars unless otherwise indicated. This commentary is based on the information
available as at and is dated March 14, 2011.
Angle is a growth-oriented, exploration-focused oil and natural producer, with a focus on achieving cost-effective reserves
discovery and production in large, resource-in-place accumulations of liquids-rich natural gas and light oil. Angle prefers
to drill in areas where it can complete multi-well projects at high working interest and operate the resulting production.
Additionally, to maintain control, such areas should also have available access to existing infrastructure to transport and
process the commodities produced.
Prior to 2009, all of Angle’s reserves had been added through drilling as the Company had not previously completed any
material property or corporate acquisitions. In 2009, Angle completed its first property acquisition in its existing Ferrier
core area. In 2010, Angle built a new core area in Edson through its first corporate acquisition and a subsequent material
property acquisition. Additionally, in 2010 the Company made the transition from vertical to horizontal drilling.
Angle currently has four core operating areas: Harmattan, Ferrier, Edson and Lone Pine Creek, all in Alberta. Angle is
focusing on five main “plays” in these four core areas: Cardium light oil, Viking light oil, Mannville liquids-rich natural gas,
Deep Basin liquids-rich multi-zone natural gas and Wabamun high-rate natural gas and liquids. Exit production in 2010
was 13,500 boe per day, consisting of approximately 60 percent natural gas, 30 percent natural gas liquids and 10 percent
light oil.
The terms “2010” and “2009” are used throughout this document and refer to the years ended December 31, 2010 and
2009, respectively. The terms “fourth quarter of 2010” and “same period of 2009” or similar terms are used throughout
this document and refer to the three-month periods ended December 31, 2010 and 2009, respectively.
Angle energy inc 2010 AnnuAl RepoRt46
GUIDANCE AND OUTLOOk
Angle issued guidance for projected 2010 results as part of its third quarter report released on November 3, 2010. The
table below provides Angle’s guidance for 2010 along with actual results.
2010 GUIDANCE
2010 Guidance Actual % Difference
2010 pricing (fourth quarter)
Natural gas – AECO $4.00/mcf $4.24/mcf 6
Crude oil – Edmonton par $75.00/bbl $78.36/bbl 4
2010 production (boe/d)
Annual 9,600 9,243 (4)
Exit 13,500 13,500 0
2010 royalties (percentage of revenue) 20% – 22% 20% 0
2010 operating costs (per boe) $6.35 – $6.50 $6.83 6
2010 general and administrative costs (per boe) $2.20 – $2.30 $2.35 4
2010 capital budget
Expenditures (excluding acquisitions) $187 million $185 million (1)
Wells drilled (gross/net) 39/34 40/34.5 3/1
Total year-end net debt (1) $170 – $173 million $152 million (11)
(1) Net debt is current assets less current liabilities and long-term debt, excluding derivative instruments and the related tax effect.
Average daily production for 2010 was slightly lower than guidance due to delays in facility expansion and pipeline
construction projects in the fourth quarter related to poor weather and contractor delays. Operating costs for 2010 were
higher than guidance due to non-recurring unanticipated operating cost adjustments of $0.6 million for gas processing in
the Harmattan area booked in the fourth quarter. Total year-end net debt was lower than guidance due to Angle receiving
the proceeds from its $25 million flow-through share offering that closed in November, partially offset by slightly higher
than expected operating and G&A costs.
2011 GUIDANCE
The following table provides Angle’s guidance for 2011, as previously disclosed by press release on January 13, 2011. With
proceeds from its flow-through equity financing in November 2010, convertible debenture financing in January 2011 and
its inventory of opportunities, Angle has prepared a budget based on capital expenditures that are in excess of funds from
operations. However, throughout 2011 Angle plans to maintain a net debt to annualized quarterly funds from operations
ratio no higher than 2.0:1. The Company is well-positioned to monitor commodity prices and resulting cash flows and
adjust its capital budget accordingly. Angle expects its 2011 drilling program to include approximately 19 (19.0 net) wells
in Harmattan, 7 (5.8 net) wells in Ferrier, 5 (5.0 net) wells in Lone Pine Creek and 4 (3.1 net) wells in Edson.
MD
&A
Angle energy inc 2010 AnnuAl RepoRt 47
The planned activities outlined above result in a $150 million capital budget from which Angle is projecting 2011 average
daily production to increase by a range of 41 percent to 46 percent over the 2010 daily average. This production increase
includes the effect of a scheduled plant turnaround in Harmattan, which will decrease yearly average production by
approximately 400 boe per day, as well as a shift of new Lone Pine Creek volumes from the second quarter of 2011 to the
fourth quarter due to timing of facility construction. Due to increased production, along with higher oil and NGLs prices,
funds from operations are projected to increase by 69 percent to 77 percent to $105 million to $110 million ($1.35 to $1.40
per diluted share). Angle has forward-sold approximately 25 percent of 2011 natural gas sales at an average price of $4.00
per mcf. Year-end net debt is projected to increase to $195 million to $200 million with a net debt to annualized fourth
quarter funds from operations ratio of 1.75:1. The table below summarizes the Company’s 2011 guidance.
2011 Guidance
2011 pricing
Natural gas – AECO $4.10/mcf
Crude oil – Edmonton par $85.00/bbl
2011 production (boe/d)
Annual 13,000 – 13,500
Exit 15,000 – 16,000
2011 net operating income
Annual $121 – $126 million
Annual – per boe $24.50 – $26.50
2011 funds from operations
Annual $105 – $110 million
Annual – per diluted share $1.35 – $1.40
2011 capital budget
Expenditures $150 million
Wells drilled (gross/net) 35/32.9
Total year-end net debt $195 – $200 million
OpErATING rESULTS
CApITAL ExpENDITUrES
Three Months Ended December 31 Years Ended December 31
(000s) 2010 2009 % Change 2010 2009 % Change
Drilling $ 9,516 $ 3,828 149 $ 70,811 $ 22,039 221
Drilling credits (1,294) (35) 3,597 (7,784) (2,224) 250
Completions 12,381 173 7,057 49,600 5,318 833
Equipping and tie-ins 7,314 389 1,780 19,642 4,529 334
Facilities and pipelines 2,265 157 1,343 13,780 4,981 177
Geological and geophysical 8 842 (99) 1,281 1,440 (11)
Land and lease retention 506 2,362 (79) 36,261 4,812 654
Acquisitions (578) – (100) 170,093 22,451 658
Head office 66 305 (78) 303 410 (26)
Capitalized G&A and other 286 263 9 1,084 819 32
Total capital expenditures $ 30,470 $ 8,284 268 $ 355,071 $ 64,575 450
Angle energy inc 2010 AnnuAl RepoRt48
The year 2010 was transformational for Angle. Capital expenditures totalled $355.1 million and included two material
acquisitions, the Company’s largest annual drilling program to date, construction of facilities and pipelines to increase
out-take in several core areas and significant land purchases at Crown sales to provide the Company with future
drilling opportunities.
Angle’s capital program for the fourth quarter was reduced from the other quarters in 2010 and resulted in total expenditures
of $30.5 million. These expenditures included $9.5 million for drilling 6 gross (5.2 net) wells, $12.4 million for completing
six wells and $7.3 million for the equipping and tie-in of 10 wells. Angle also completed the construction of its sour pipeline
in Lone Pine Creek during the fourth quarter.
Drilling expenditures totalled $70.8 million during 2010 and included 40 gross (34.5 net) wells resulting in an average cost of
$2.1 million per net well. This was a large increase over 2009 expenditures of $22.0 million on 13 gross (11.9 net) wells
($1.8 million per net well). The increase in the drilling cost per well was primarily due to Angle shifting from vertical to
horizontal drilling techniques in 2010. Angle’s 2010 drilling expenditures were reduced by $7.8 million in recognized
Alberta Crown drilling credits.
Completion expenditures were $49.6 million in 2010 versus $5.3 million in 2009. In 2010, Angle completed 36 gross wells
and recompleted three gross wells, compared to only 12 gross wells completed in 2009. The increase in the completion
cost per well is the result of Angle applying multi-stage fracturing techniques to horizontal wells in 2010.
Equipping and tie-in costs were $19.6 million in 2010 compared to $4.5 million in 2009. In 2010, Angle brought 30 gross
wells on production, compared to only 13 gross wells in 2009. The higher cost per well in 2010 was the result of more
complex tie-in operations.
Facility and pipeline expenditures were $13.8 million in 2010, a large increase over the $5.0 million spent in 2009. During
2010, Angle completed several large-scale projects to enhance out-take and processing capacity. These projects included
the construction of a natural gas compression facility in Ferrier, an 8” diameter, 13 km sour gas pipeline in Lone Pine Creek
and a connector pipeline between gas processing facilities in Edson.
Total $64,575
$1,229Head Office/Capitalized G&A
$22,451Acquisitions
$29,662Drilling,Completions,Tie-ins
$4,981Facilities
$1,440Geological
$1,281Geological
$4,812Land
$13,780Facilities
Total $355,071
20092010$1,387Head Office/Capitalized G&A
$170,093Acquisitions
$132,269Drilling,Completions,Tie-ins
$36,261Land
Capital Expenditures ($000s)
Angle energy inc 2010 AnnuAl RepoRt 49
Angle was very active at Crown land sales during 2010 in order to establish
the Company in important new resource plays it is pursuing, in turn positioning
itself for increased drilling activity, primarily in the Harmattan area where it is
focusing on light oil targets. Angle’s land cost per acre has increased due to the
competitive and prospective nature of the areas that Angle is pursuing. Total
net undeveloped acreage has increased by 77 percent to 175,619 acres at
December 31, 2010 from 98,966 acres at year-end 2009. Land purchase and
lease retention costs were $36.2 million in 2010.
In 2010, Angle closed three acquisitions:
• OnJanuary12,2010,Angleacquiredalloftheissuedandoutstandingshares
of Stonefire Energy Corp. (“Stonefire”) for cash consideration of $46.7 million,
plus the assumption of $26.4 million of net debt and transaction costs of
$1.1 million. Refer to note 3 to the audited consolidated financial statements
for further details;
• InJune2010,AngleacquiredanadditionalworkinginterestinseveralwellsandacompressionfacilityintheFerrierarea
for cash consideration of $7.3 million; and
• OnJune30,2010,AngleacquiredcertaininterestsinpetroleumandnaturalgaspropertiesintheEdsonareaforcash
consideration of $115 million plus transaction costs of $1.4 million.
DrILLING ACTIvITY
Angle’s drilling activity for the three months and year ended December 31, 2010 is summarized below:
Three Months Ended Year Ended December 31, 2010 December 31, 2010 Gross Net Gross Net
Natural gas and NGLs 1 1.0 19 17.2
Light crude oil 5 4.2 18 15.6
Dry and abandoned – – 3 1.7
Total 6 5.2 40 34.5
Success rate 100% 95%
Average working interest 87% 86%
The above drilling activity was allocated to Angle’s core areas as follows:
Three Months Ended Year Ended December 31, 2010 December 31, 2010 Gross Net Gross Net
Edson 1 0.2 11 8.5
Ferrier 1 1.0 11 8.0
Harmattan 4 4.0 11 11.0
Lone Pine Creek – – 7 7.0
Total 6 5.2 40 34.5
Net Undeveloped Land(000s acres)
34.5 57.7 68.5 99.0 175.6
06 07 08 09 10
Angle energy inc 2010 AnnuAl RepoRt50
During the fourth quarter of 2010, Angle drilled 6 gross (5.2) net wells, all of which were successful. In Harmattan, Angle
continued to de-risk the Viking oil play by drilling three horizontal wells in the formation and also drilled its first Mannville
B horizontal gas well (all four wells were 100 percent working interest). Angle drilled one horizontal Cardium oil well in
Ferrier at 100 percent working interest and participated in one non-operated horizontal Cardium oil well in Edson at
24 percent working interest.
For the year ended December 31, 2010, Angle drilled 40 gross (34.5 net) wells, of which 3 gross (1.7 net) wells were
unsuccessful. Of the 40 wells, 34 were drilled horizontally, five were drilled directionally and one was drilled vertically. In
the Edson area, seven of the 11 wells were operated (all at 100 percent working interest) and the remaining four wells were
non-operated at an average working interest of 38.5 percent. In the Ferrier area, Angle operated 10 of the 11 wells at an
average working interest of 79 percent and participated in one non-operated well at a 2 percent working interest. All drilling
in the Harmattan area and the Lone Pine Creek area was operated at 100 percent working interest.
FINANCIAL AND OpErATING rESULTS OF OIL AND NATUrAL GAS ACTIvITIES
SALES, rEvENUE AND prICES
Three Months Ended December 31 Years Ended December 31
2010 2009 % Change 2010 2009 % Change
Sales
Natural gas (mcf/d) 42,786 26,335 62 34,248 26,334 30
NGLs (bbls/d) 3,495 2,873 22 2,892 2,995 (3)
Light crude oil (bbls/d) 986 184 436 643 144 347
Total (boe/d) 11,612 7,446 56 9,243 7,528 23
Total (boe) 1,068,281 685,030 56 3,373,808 2,747,804 23
revenue (000s)
Natural gas $ 16,692 $ 11,400 46 $ 53,715 $ 39,071 37
Realized derivative gain 334 – 100 2,113 – 100
Total natural gas $ 17,026 $ 11,400 49 $ 55,828 $ 39,071 43
NGLs 15,675 10,972 43 47,946 37,670 27
Light crude oil 7,106 1,280 455 17,694 3,257 443
Total revenue before unrealized derivative gain (loss) $ 39,807 $ 23,652 68 $ 121,468 $ 79,998 52
Unrealized derivative gain (loss) (2,550) 226 (1,228) (2,084) 226 (1,022)
Total sales $ 37,257 $ 23,878 56 $ 119,384 $ 80,224 49
Average prices
Natural gas (per mcf) $ 4.24 $ 4.71 (10) $ 4.30 $ 4.06 6
Realized derivative gain (per mcf) 0.09 – 100 0.17 – 100
Total natural gas (per mcf) $ 4.33 $ 4.71 (8) $ 4.47 $ 4.06 10
NGLs (per bbl) 48.75 41.51 17 45.42 34.46 32
Light crude oil (per bbl) 78.36 75.64 4 75.39 61.74 22
Combined average (per boe) $ 37.26 $ 34.53 8 $ 36.00 $ 29.11 24
Angle energy inc 2010 AnnuAl RepoRt 51
For the three months ended December 31, 2010, revenue was $39.8 million compared to $23.7 million for the same
period in 2009 (before unrealized derivative gains/losses). Sales volumes during the fourth quarter of 2010 averaged
11,612 boe per day versus 7,446 boe per day in the comparable 2009 quarter and 10,021 boe per day recorded in the third
quarter of 2010. The increase in revenue of 68 percent was due to both an increase in sales volumes of 56 percent and an
increase in Angle’s average realized price of 8 percent. Natural gas prices declined slightly but this decrease was more than
offset by increases in the NGLs and oil prices.
During the three months ended December 31, 2010, Angle’s product volume mix was 61 percent natural gas, 30 percent
NGLs and 9 percent light crude oil.
In the fourth quarter of 2009, Angle added its third core area when production commenced in Lone Pine Creek, and during
the first half of 2010 added its fourth core area at Edson through the acquisition of Stonefire on January 12, 2010 and the
acquisition of producing assets on June 30, 2010. During 2010, Harmattan contributed approximately 44 percent of the
Company’s total sales volumes, Ferrier 28 percent, Edson 23 percent and Lone Pine Creek the remaining 5 percent.
For the year ended December 31, 2010, revenue was $121.5 million on average sales of 9,243 boe per day compared to
$80.0 million and 7,528 boe per day for 2009 (after realized derivative gains/losses). The 52 percent revenue increase resulted
from a 23 percent increase in sales volumes plus a 24 percent increase in blended product pricing.
Total 11,612
3,495NGLs
986Light
Crude Oil
7,131Natural Gas
Total 9,243
Product Mix of Daily Average Production (boe basis)
2,892NGLs
5,708Natural Gas
Total 7,528
Q4 2010 2010 2009
144Light
Crude Oil
2,995NGLs
4,389Natural Gas
643Light
Crude Oil
Natural Gas($/mcf)
6.80 7.14 8.20 4.06 4.47
NGLs($/bbl)
42.90 49.52 58.15 34.46 45.42
Light Crude Oil($/bbl)
66.00 80.74 86.40 61.74 75.39
06 07 08 09 1006 07 08 09 10 06 07 08 09 10 06 07 08 09 10
Average Realized Product Prices
Angle energy inc 2010 AnnuAl RepoRt52
The Company’s drilling operations often target natural gas that is rich in associated NGLs. Angle’s NGLs are comprised of
approximately 30 percent ethane, 27 percent propane, 15 percent butane and 28 percent condensate. The price received
for its NGLs is based on this mix, with condensate having the highest value of the NGLs stream.
Angle’s production is sold in Canada and is sensitive to North American natural gas and world crude oil price
variations in addition to Canada/U.S. currency exchange rate changes. The Company’s production is sold through
eight purchasers to limit reliance on any one purchaser, which helps limit credit risk.
The Company has fixed the price applicable to future sales through the following contracts, on which $2.1 million in
unrealized losses have been recorded at December 31, 2010:
Period Commodity Type of Contract Quantity Contracted Contract Price ($/unit)
Jan. 1/11 – Dec. 31/11 Natural Gas Financial 5,000 GJ/d AECO Cdn$3.825/GJ
Jan. 1/11 – June 30/12 Crude Oil Financial 500 bbls/d Nymex US$87.05/bbl
Apr. 1/11 – Oct. 31/11 Natural Gas Financial 5,000 GJ/d AECO Cdn$3.82/GJ
Apr. 1/11 – Mar. 31/12 Natural Gas Financial 2,500 GJ/d AECO Cdn$3.775/GJ
Apr. 1/11 – Mar. 31/12 Natural Gas Financial 2,500 GJ/d AECO Cdn$3.815/GJ
The Company has entered into a currency average rate forward swap transaction whereby U.S. dollars have been converted
to Canadian dollars as summarized in the following table:
Period Amount Strike Price
Jan. 1/11 – June 30/12 US$1,300,000/month Cdn$1.0535
Angle is only entitled to a cash settlement if the monthly average currency exchange rate as reported by the Bank of
Canada is greater than 0.95.
rOYALTIES
Three Months Ended December 31 Years Ended December 31
(000s except per boe and % of revenue) 2010 2009 % Change 2010 2009 % Change
Total revenue before derivative gains/losses $ 39,473 $ 23,652 67 $ 119,355 $ 79,998 49
Royalties
Crown $ 2,750 $ 2,678 3 $ 12,306 $ 10,641 16
Freehold and overriding 3,700 2,720 36 11,414 9,261 23
Total royalties $ 6,450 $ 5,398 19 $ 23,720 $ 19,902 19
Total royalties ($/boe) $ 6.04 $ 7.88 (23) $ 7.03 $ 7.24 (3)
As % of revenue
Crown 7% 11% (4) 10% 13% (3)
Freehold and overriding 9% 12% (3) 10% 12% (2)
Total 16% 23% (7) 20% 25% (5)
Angle’s Crown royalties declined to 7 percent and 10 percent of revenue for the three months and year ended
December 31, 2010, respectively, from an average of 11 percent and 13 percent, respectively, for the comparative periods
a year earlier. These decreases were largely due to Alberta Crown royalty incentives which reduce the royalty rate on
production from new Crown wells to 5 percent for the first 50,000 boe. Angle also received higher gas cost allowance
Angle energy inc 2010 AnnuAl RepoRt 53
credits in 2010 related to higher qualifying capital expenditures. Freehold and overriding royalties decreased slightly in
2010 as a percentage of revenue due to a higher proportion of Angle’s revenue coming from Crown wells.
OpErATING ExpENSE
Three Months Ended December 31 Years Ended December 31
(000s except per boe) 2010 2009 % Change 2010 2009 % Change
Operating expense $ 7,453 $ 3,008 148 $ 20,817 $ 12,335 69
Transportation expense 691 245 182 2,236 977 129
Total operating expense $ 8,144 $ 3,253 150 $ 23,053 $ 13,312 73
Total operating expense ($/boe) $ 7.62 $ 4.75 60 $ 6.83 $ 4.84 41
The 60 percent and 41 percent increases in the 2010 per boe rates are due to several factors. During 2010, Angle increased
its oil production significantly and oil production typically has a higher per boe operating expense than natural gas
production. The production acquired in the Edson area in June 2010 has higher operating costs than the Harmattan and
Ferrier areas due to less favourable third-party processing rates. In addition, Angle received an invoice for unanticipated
operating cost adjustments spanning several years for gas processing in the Harmattan area in the fourth quarter of 2010
for $0.6 million. This adjustment increased operating expenses by $0.56 per boe in the fourth quarter and $0.18 per boe
in 2010. These charges are non-recurring and therefore Angle expects operating costs to decrease in 2011 to between
$6.50 and $6.75 per boe.
GENErAL AND ADMINISTrATIvE (G&A) ExpENSE
Three Months Ended December 31 Years Ended December 31
(000s except per boe) 2010 2009 % Change 2010 2009 % Change
G&A expense $ 2,762 $ 2,033 36 $ 10,913 $ 7,772 40
G&A capitalized (direct) (286) (262) 9 (1,084) (818) 33
G&A recoveries via operations (463) (95) 387 (1,909) (604) 216
G&A expense (net) $ 2,013 $ 1,676 20 $ 7,920 $ 6,350 25
G&A expense (net) ($/boe) $ 1.89 $ 2.45 (23) $ 2.35 $ 2.31 2
The 36 percent and 40 percent increases in G&A for the three and 12-month periods, respectively, relate primarily to the
addition of new staff and office space to administer the Company’s increased activity. Capitalized G&A on exploration staff
salaries also increased, although to a lesser extent. G&A recoveries were up over the prior year, consistent with increased
capital spending in 2010. Despite the increases on an absolute basis, net G&A expense rose only 2 percent year-over-year
on a per boe basis.
Royalties($/boe)
16.45 14.59 16.85 7.24 7.03
Operating Expense($/boe)
5.17 4.45 5.16 4.84 6.83
G&A Expenses($/boe)
3.75 1.60 1.79 2.31 2.35
06 07 08 09 1006 07 08 09 10 06 07 08 09 10 06 07 08 09 10
Angle energy inc 2010 AnnuAl RepoRt54
INTErEST ExpENSE
Three Months Ended December 31 Years Ended December 31
(000s except per boe) 2010 2009 % Change 2010 2009 % Change
Interest expense $ 1,756 $ 98 1,692 $ 4,595 $ 245 1,776
Interest expense ($/boe) $ 1.64 $ 0.14 1,071 $ 1.36 $ 0.09 1,411
Interest expense incurred during the fourth quarter of 2010 was $1.8 million on average debt of $131.7 million for an
effective interest rate of 5.3 percent. Interest expense incurred during the year ended December 31, 2010 was $4.6 million
on average debt of $90.4 million for an effective interest rate of 5.1 percent.
Angle incurred almost no interest expense in 2009 due to very low debt levels carried during the year. In comparison,
in 2010 the Company closed two material acquisitions and conducted a large capital program which required Angle to
increase its net debt. As Angle’s debt to cash flow ratio increased throughout 2010 so did the margins charged on the
Company’s bank facility, which resulted in a slightly higher effective interest rate in the fourth quarter.
STOCk-BASED COMpENSATION (SBC) ExpENSE
Three Months Ended December 31 Years Ended December 31
(000s except per boe) 2010 2009 % Change 2010 2009 % Change
SBC expense $ 1,127 $ 682 65 $ 3,635 $ 2,032 79
SBC capitalized (direct) (197) (157) 25 (689) (476) 45
SBC expense (net) $ 930 $ 525 77 $ 2,946 $ 1,556 89
SBC expense (net) ($/boe) $ 0.87 $ 0.77 13 $ 0.87 $ 0.57 53
The 77 percent and 89 percent increases in net SBC expense for the three and 12-month periods, respectively, resulted
from new option grants in 2010 as well as an increase in the fair value per option consistent with the increase in Angle’s
stock price.
DEpLETION, DEprECIATION AND ACCrETION (DD&A)
Three Months Ended December 31 Years Ended December 31
(000s except per boe) 2010 2009 % Change 2010 2009 % Change
Depletion and depreciation expense $ 19,484 $ 10,757 81 $ 63,467 $ 42,136 51
Accretion expense 196 52 277 537 214 151
DD&A expense $ 19,680 $ 10,809 82 $ 64,004 $ 42,350 51
DD&A expense ($/boe) $ 18.42 $ 15.78 17 $ 18.97 $ 15.41 23
The 17 percent and 23 percent increase in DD&A per boe for the three and 12-month periods, respectively, resulted from
assets acquired which carry higher DD&A per boe of reserves, as well as an increase in future development costs based
on the December 31, 2010 reserve report prepared by GLJ Petroleum Consultants Ltd. (GLJ), Angle’s independent
reserves evaluator.
Angle performed a ceiling test as at December 31, 2010. Based on the calculation, the carrying values of the Company’s
property, plant and equipment are less than the sum of the undiscounted cash flows of the Company’s proved reserves
and, therefore, no write-down of property, plant and equipment was required.
Angle energy inc 2010 AnnuAl RepoRt 55
INCOME TAxES
The provision for future income taxes in the financial statements for the fourth quarter and year ended December 31, 2010
was a reduction of $0.5 million and $1.8 million, respectively. Angle did not pay any cash taxes in 2010 and estimates it
has sufficient tax pools to shelter estimated income until 2012 or beyond.
A summary of the Company’s income tax pools is outlined below:
Years ended December 31
(000s) 2010 2009
Canadian Oil and Gas Property Expense (COGPE) $ 160,848 $ 31,853
Canadian Development Expense (CDE) 145,353 69,289
Canadian Exploration Expense (CEE) 29,565 7,781
Non-Capital Losses (NCL) 23,582 –
Undepreciated Capital Costs (UCC) 94,632 41,867
Share issue costs 10,550 5,818
$ 464,530 $ 156,608
NETBACk ANALYSIS
Three Months Ended December 31 Years Ended December 31
($/boe) 2010 2009 % Change 2010 2009 % Change
Sales price $ 37.26 $ 34.53 8 $ 36.00 $ 29.11 24
Royalties (6.04) (7.88) (23) (7.03) (7.24) (3)
Operating expense (7.62) (4.75) 60 (6.83) (4.84) 41
Operating netback $ 23.60 $ 21.90 8 $ 22.14 $ 17.03 30
G&A expense (1.89) (2.45) (23) (2.35) (2.31) 2
Interest expense (1.64) (0.14) 1,071 (1.36) (0.09) 1,411
Asset retirement expenditures (0.01) – (100) (0.05) – (100)
Funds from operations netback (1) $ 20.06 $ 19.31 4 $ 18.38 $ 14.63 26
SBC expense (0.87) (0.77) 13 (0.87) (0.57) 53
DD&A expense (18.42) (15.78) 17 (18.97) (15.41) 23
Unrealized derivative gains (losses) (2.39) 0.33 (824) (0.62) 0.08 (675)
Future tax recovery (expense) 0.48 (0.46) (204) 0.52 0.17 206
Asset retirement expenditures 0.01 – 100 0.05 – 100
Net income (loss) netback $ (1.13) $ 2.63 (143) $ (1.51) $ (1.10) 37
(1) Non-GAAP measure: refer to disclosure on non-GAAP measures. Funds from operations netback is calculated by dividing funds from operations by the sales volume in boe for the period then ended.
(2) For a description of the boe in conversion ratio, refer to the commentary at the end of this MD&A.
Angle’s operating netback was $22.14/boe for the year ended December 31, 2010 compared to $17.03/boe in 2009. This
30 percent increase was the result of higher commodity prices, slightly offset by higher operating expenses on a per unit
basis. Angle’s 2010 net loss netbacks were caused in part by higher DD&A rates per boe.
Angle energy inc 2010 AnnuAl RepoRt56
FUNDS FrOM OpErATIONS, CASh FLOw FrOM OpErATING ACTIvITIES AND NET INCOME Or LOSS
Three Months Ended December 31 Years Ended December 31
2010 2009 % Change 2010 2009 %Change
Funds from operations (000s) $ 21,433 $ 13,227 62 $ 62,003 $ 40,154 54
Funds from operations (per boe) $ 20.06 $ 19.31 4 $ 18.38 $ 14.63 26
Funds from operations per share
Basic $ 0.30 $ 0.27 11 $ 0.98 $ 0.92 7
Diluted $ 0.30 $ 0.27 11 $ 0.96 $ 0.90 7
Cash flow from operating activities (000s) $ 23,804 $ 14,179 68 $ 53,566 $ 27,843 92
Net income (loss) (000s) $ (1,208) $ 1,801 (167) $ (5,098) $ (3,032) 68
Net income (loss) (per boe) $ (1.13) $ 2.63 (143) $ (1.51) $ (1.10) 37
Net income (loss) per share
Basic $ (0.02) $ 0.04 (150) $ (0.08) $ (0.07) 14
Diluted $ (0.02) $ 0.04 (150) $ (0.08) $ (0.07) 14
Weighted average shares outstanding (000s)
Basic 70,597 48,151 47 63,224 43,748 45
Diluted (1) 71,804 48,949 47 64,481 44,533 45
(1) For purposes of calculating net loss per diluted share, outstanding options were anti-dilutive and therefore the number of basic weighted average shares outstanding was used in the calculation.
Operating Netback($/boe)
20.33 26.72 31.05 17.03 22.14
Funds from OperationsNetback ($/boe)
17.07 24.38 28.96 14.63 18.38
06 07 08 09 1006 07 08 09 10 06 07 08 09 1006 07 08 09 10
($mm)
8.0 29.7 69.8 40.2 62.0
($/basic share)
0.28 0.91 1.91 0.92 0.98
06 07 08 09 1006 07 08 09 10 06 07 08 09 1006 07 08 09 10
Funds from Operations
Angle energy inc 2010 AnnuAl RepoRt 57
The increase in 2010 funds from operations and cash flows from operating activities was the result of higher volumes as well
as an improvement in the average commodity price realized by Angle. The higher net losses recognized in 2010 resulted
primarily from higher non-cash expenses such as DD&A and SBC.
LIqUIDITY AND CApITAL rESOUrCES
The following table summarizes the change in working capital during the years ended December 31, 2010 and 2009:
Years ended December 31
(000s) 2010 2009
Working capital (deficiency) – beginning of year $ 38,255 $ (8,960)
Funds from operations 62,003 40,154
Issue of capital stock for cash (net of share issue expense) 130,414 71,636
Capital expenditures (184,978) –
Acquisitions (170,093) –
Debt and working capital deficiency acquired on corporate acquisition (27,979) (64,575)
Working capital (deficiency) – end of year $ (152,378) $ 38,255
From its inception on January 23, 2004 to December 31, 2010, Angle raised funds through treasury equity issues in the
amount of $309.3 million (net of share issue expenses and normal course issuer bid) at share prices ranging from $0.60 to
$10.05 per common share.
The Company exited 2010 with a working capital deficiency of $152.4 million compared to available credit lines of
$180 million. On January 6, 2011 Angle closed its $60 million unsecured subordinated debenture offering, increasing the
Company’s total borrowing capacity to $240 million. The debentures bear interest at a fixed interest rate of 5.75 percent,
which helps limit Angle’s exposure to interest rate fluctuations.
Angle’s credit facility is subject to a borrowing base test performed on a semi-annual basis by the lenders, based primarily
on reserves and using commodity prices estimated by the lenders as well as other factors. The next semi-annual review of
the credit facility is to take place on or before April 29, 2011.
Other liabilities included in working capital consist primarily of trade payables and accrued liabilities. Management expects
to be able to fully meet all current obligations when due with funding provided by a combination of accounts receivable
collections, funds from operations and available credit under the bank line.
In order to protect a portion of the Company’s revenue stream, Angle will periodically enter into forward sales contracts
for its commodities. At December 31, 2010, the Company had entered into fixed-price contracts on approximately
25 percent of its estimated 2011 natural gas production and approximately 30 percent of its estimated 2011 oil production
(see “Financial Instruments” below).
Angle energy inc 2010 AnnuAl RepoRt58
As at March 14, 2010, Angle had 71,993,831 common shares and 5,905,550 stock options issued and outstanding.
SELECTED qUArTErLY INFOrMATION
Three Months Ended Dec. 31, Sept. 30, June 30, Mar. 31, Dec. 31, Sept. 30, June 30, Mar. 31,(000s, except per share data) 2010 2010 2010 2010 2009 2009 2009 2009
($) ($) ($) ($) ($) ($) ($) ($)
Total assets 558,969 547,885 490,605 334,973 246,465 212,040 212,578 191,682
Total sales (boe/d) 11,612 10,021 7,290 8,003 7,446 7,552 7,472 7,645
Oil and natural gas revenues (1) 39,807 30,345 23,474 27,842 23,652 17,483 17,405 21,458
Funds from operations 21,433 14,255 12,803 13,512 13,227 8,699 8,539 9,689
Per share – basic 0.30 0.21 0.22 0.25 0.27 0.19 0.21 0.25
Cash flow from operating activities 23,804 15,965 7,138 6,659 14,179 4,907 (3,799) 12,556
Net income (loss) (1,208) (4,546) (955) 1,611 1,801 (1,896) (2,248) (689)
Per share – basic (0.02) (0.07) (0.02) 0.03 0.04 (0.04) (0.05) (0.02)
Capital expenditures (2) 30,470 71,428 167,876 85,297 8,284 9,496 29,020 17,775
Working capital (deficiency) (152,378) (168,314) (111,438) (60,712) 38,255 (9,350) (9,228) (17,046)
Shareholders’ equity 343,167 317,884 321,212 215,346 212,201 166,374 167,231 140,260
(1) Including realized gains/losses on derivative instruments.(2) Total capital expenditures, including acquisitions.(3) The selected quarterly information has been prepared in accordance with the accounting principles as contained in the notes to the consolidated
financial statements for the years ended December 31, 2010 and 2009, except for funds from operations, which is a non-GAAP measure.
FACTOrS ThAT hAvE CAUSED vArIATIONS OvEr ThE qUArTErS
Angle’s total assets and capital expenditures increased significantly during 2010 due to the acquisition of Stonefire that
closed on January 12, 2010, the property acquisition in the Edson area that closed on June 30, 2010 and an active 2010
drilling program. These factors also contributed to the substantial change in working capital. Working capital was positive at
year-end 2009 due to Angle closing an equity financing in December 2009 that was used to fund the Stonefire acquisition
in January 2010. The fluctuations in Angle’s revenue and net earnings from quarter to quarter are primarily caused by
changes in production volumes, realized commodity prices and the related impact on royalties, and realized and unrealized
gains/losses on financial instruments. The increase in revenue and cash flow in the fourth quarter of 2010 was due to an
increase in production volumes as well as an improvement in commodity prices. The decrease in production volumes in
the second quarter of 2010 was primarily due to a planned plant turnaround in Ferrier, which resulted in all of Angle’s
production in the area being shut-in for 17 days. During 2009, Angle’s revenue stream was negatively impacted by the
decrease in commodity prices experienced by the industry as a whole. During the second quarter of 2009, the Company
experienced production downtime due to mechanical failures at its processing facilities in both the Harmattan and Ferrier
core producing areas. Please refer to “Financial and Operating Results of Oil and Natural Gas Activities” and other sections
of this MD&A for detailed discussions on variations during the comparative quarters and to Angle’s previously issued
interim and annual MD&A for changes in prior quarters.
Angle energy inc 2010 AnnuAl RepoRt 59
SELECTED ANNUAL INFOrMATION
Years Ended December 31 2010 2009 2008 2007 2006
($000s, except production and per share data)
Total sales (boe/d) 9,243 7,528 6,586 3,334 1,281
Oil and natural gas revenues (1) 121,468 79,998 127,885 55,683 19,621
Funds from operations 62,003 40,154 69,801 29,663 7,985
Per share – basic 0.98 0.92 1.91 0.91 0.28
Net income (loss) (5,098) (3,032) 26,372 9,650 1,543
Per share – basic (0.08) (0.07) 0.72 0.30 0.05
Capital expenditures (2) 355,071 64,575 79,866 59,110 57,821
Working capital (deficiency) (152,378) 38,255 (8,960) (31,819) (10,772)
(1) Including realized gains/losses on derivative instruments.(2) Total capital expenditures, including acquisitions.(3) The selected quarterly information has been prepared in accordance with the accounting principles as contained in the notes to the consolidated
financial statements for the years ended December 31, 2010 and 2009, except for funds from operations, which is a non-GAAP measure.
CONTrACTUAL OBLIGATIONS
The Company has a committed revolving term facility with three Canadian chartered banks. The authorized borrowing
amount under this facility as at December 31, 2010 was $180 million. The Company’s commitments are summarized
below:
As at December 31 2011 2012 2013 2014
(000s)
Operating lease – office $ 801 $ 690 $ 690 $ 633
Operating lease – compressors 1,594 834 – –
Exploration expenditures (flow-through) 23,507 – – –
Total $ 25,902 $ 1,524 $ 690 $ 633
Please refer to “Liquidity and Capital Resources” for further information.
rELATED-pArTY AND OFF-BALANCE-ShEET TrANSACTIONS
Angle has retained the law firm Osler, Hoskin and Harcourt LLP (“Osler”) to provide legal services. A Director of Angle is a
partner of this firm. During the year ended December 31, 2010, Angle incurred $1.4 million in costs with Osler (2009 – $0.6
million). Services provided related to advice and counsel primarily in the areas of general legal and corporate governance
matters, as well as banking and equity offerings. These services were billed at rates consistent with those charged to third
parties. The Company expects to continue using the firm’s services throughout 2011.
CrITICAL ESTIMATES
Management is required to make judgements and use estimates in the application of Canadian generally accepted
accounting principles (GAAP) that have significant impact on the financial results of the Company. The following discussion
outlines the accounting policies and practices that are critical to determining Angle’s financial results.
Angle energy inc 2010 AnnuAl RepoRt60
FULL COST ACCOUNTING
Angle follows the Canadian Institute of Chartered Accountants’ (CICA) guideline on full cost accounting in the oil and natural
gas industry to account for oil and natural gas properties. Under this method, all costs associated with the acquisition of,
exploration for and development of crude oil and natural gas reserves are capitalized and costs associated with production
are expensed. The capitalized costs are depreciated, depleted and amortized using the unit-of-production method based
on estimated proved reserves. Reserves estimates can have a significant impact on earnings, as they are a key component
in the calculation of DD&A. A downward revision in a reserves estimate could result in a higher DD&A charge to earnings.
In addition, if capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserves
estimates, the excess must be written off as an expense charged against earnings. In the event of a property disposition,
proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the
DD&A rate of 20 percent or greater.
ASSET rETIrEMENT OBLIGATIONS
The Company records a liability for the fair value of its legal obligations associated with the retirement of long-lived assets
in the period in which it is incurred, normally when the asset is purchased or developed. On recognition of the liability,
there is a corresponding increase in the carrying value of the related asset and the asset retirement obligation. The total
amount of the asset retirement obligation is an estimate based on the Company’s net ownership in all wells and facilities,
the estimated cost to abandon and reclaim the wells and facilities, the estimated timing of those cash flows, changes in
environmental regulations and the discount rate used to calculate the present value of those cash flows are estimates
subject to measurement uncertainty. Any change in these estimates would impact the asset retirement liability.
rESErvES DETErMINATION
The proved natural gas, NGLs and crude oil reserves that are used in determining Angle’s depletion rates, the magnitude
of the borrowing base available to the Company from its lender and the ceiling test are based on management’s best
estimates, and are subject to uncertainty. Through the use of geological, geophysical and engineering data, the reservoirs
and deposits of natural gas, NGLs and crude oil are examined to determine quantities available for future production, given
existing operations and economic conditions and technology. The evaluation of reserves is an ongoing process impacted
by current production, continuing development activities and changing economic conditions as reflected in natural gas
and crude oil prices. Consequently, the reserves are estimated, which are subject to variability. To assist with the reserves
evaluation process, the Company employs the services of independent oil and gas reservoir engineers.
INCOME TAxES
The determination of Angle’s income and other tax liability requires interpretation of complex laws and regulations often
involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after lapse of considerable
time. Accordingly, the actual income tax liability could differ significantly from the liability estimated or recorded.
FINANCIAL INSTrUMENTS
Derivative contracts are recorded at fair value based on an estimate of the amounts that would have been received or
paid to settle these instruments prior to maturity given future market prices and other relevant factors. The actual amounts
received or paid to settle these instruments at maturity could differ significantly from those estimated.
Angle energy inc 2010 AnnuAl RepoRt 61
OThEr ESTIMATES
The accrual method of accounting will require management to incorporate certain estimates, including revenues, royalties,
production costs and capital expenditures as at a specific reporting date but for which actual revenue and royalties have
not yet been received, and estimates on capital projects that are in progress or recently completed where actual costs have
not been received at a specific reporting date.
TrANSITION TO INTErNATIONAL FINANCIAL rEpOrTING STANDArDS
On January 1, 2011, International Financial Reporting Standards (IFRS) will become the generally accepted accounting
principles in Canada for publicly traded security-issuers. The adoption date of January 1, 2011 will require the restatement,
for comparative purposes, of amounts reported by Angle for the year ended December 31, 2010, including the opening
balance sheet as at January 1, 2010. The project to convert to IFRS is being managed by in-house accounting professionals
who have engaged in IFRS educational programs and continue to develop the Company’s adoption of IFRS. Angle’s
auditors have been and will continue to be involved throughout the process to ensure Angle’s policies are in accordance
with these new standards.
Although IFRS is principles-based and uses a conceptual framework similar to Canadian GAAP, there are significant
differences and choices in accounting policies as well as increased disclosure requirements under IFRS. As a result, the
transition from current Canadian GAAP to IFRS will affect Angle’s reported financial position and results of operations.
In July 2009, the International Accounting Standards Board (IASB) published amendments to the IFRS 1 deemed cost
exemption. The amendment permits the Company to allocate the Company’s full cost pool under existing GAAP using
its current reserve volumes or reserve values at the transition date, with the provision that an impairment test, under IFRS
standards, be conducted at the transition date. IFRS 1 also provides a number of other optional exemptions and mandatory
exceptions in certain areas to the general requirement for full retrospective application. Angle has determined that it will
use the optional exemption related to IFRS 2, “Share-Based Payments”, which relieves the requirement to restate stock-
based compensation expense for options that were fully vested as of Angle’s transition date to IFRS.
At this time, Angle has identified key differences that will impact the financial statements as follows:
• ExplorationandEvaluation(E&E)expenditures–OntransitiontoIFRS,AnglewillreclassifyallE&Eexpendituresthat
are currently included in the property, plant and equipment (PP&E) balance on the consolidated balance sheet. This
will consist of the book value of undeveloped land and unevaluated seismic data that relates to exploration properties.
E&E assets will not be depleted and must be assessed for impairment when indicators of impairment exist. Angle
determined its E&E asset balance to be approximately $14.2 million at January 1, 2010 and there is no transitional
impairment of the E&E assets.
• PP&E – This includes oil and natural gas assets in the development and production phases. Angle has allocated
the amount recognized under current Canadian GAAP as at January 1, 2010 to cash-generating units (CGUs) using
reserve values.
Angle energy inc 2010 AnnuAl RepoRt62
• ImpairmentofPP&Eassets–UnderIFRS,impairmenttestsofPP&EmustbeperformedattheCGUlevelasopposed
to the entire PP&E balance, which is required under current Canadian GAAP through the full cost ceiling test. IFRS
impairment calculations must be performed using fair values of the PP&E assets and Angle anticipates using discounted
proved plus probable reserve values for impairment tests of PP&E. Angle does not anticipate its PP&E assets being
impaired as at January 1, 2010 under IFRS.
• Depletionexpense–OntransitiontoIFRS,Anglehastheoptiontoperformdepletioncalculationsusingeitherproved
reserves or proved plus probable reserves. Angle anticipates it will use proved plus probable reserves to deplete its
PP&E assets.
• Stock-basedcompensationexpense–Under IFRS,each trancheofoptions is required tobe treatedasa separate
award with a separate life. In addition, under IFRS, a forfeiture rate must be included in the initial expense calculation
and adjusted prospectively if required, rather than accounting for forfeitures as they occur. Angle anticipates these
differences will result in more expense being recognized at the beginning of the award life, thus increasing Angle’s 2010
stock-based compensation expense under IFRS.
• Assetretirementobligations–UnderIFRS,eithercashflowsortheinterestrateshouldberiskedincalculatingtheasset
retirement obligation. This differs from Canadian GAAP, which requires a credit-adjusted risk-free interest rate to be
used to discount future cash flows. There was debate within the industry on the discount rate and whether there should
be a risk component to it. Based on recent comments made by the standard setters and positions within the industry,
Angle believes a risk-free rate is more appropriate. As a result, Angle has measured its ARO liability on transition using
risk-free rates between 1.41 percent and 4.08 percent, depending on the estimated timing of abandonment, resulting
in an increase to the liability at January 1, 2010 of approximately $1.8 million with an offsetting charge to the opening
retained earnings.
In addition to the accounting policy differences, Angle’s transition to IFRS will impact internal controls over financial
reporting, disclosure controls and procedures and information technology (IT) systems as follows:
• Internalcontrolsoverfinancialreporting–BasedonAngle’saccountingpoliciesunderIFRS,managementhasassessed
whether additional controls or changes in procedures are required. Angle does not consider these changes to
be significant.
• Disclosure controls and procedures – Throughout the transition process, Angle will be assessing stakeholders’
information requirements and will ensure that adequate and timely information is provided while ensuring the
Company maintains its due process regarding information that is disclosed.
• IT systems – Angle has assessed the readiness of its accounting software and continues to assess other system
requirements that may be needed in order to perform ongoing calculations and analysis under IFRS. Angle does not
consider these changes to be significant.
Angle energy inc 2010 AnnuAl RepoRt 63
Management is continuing to finalize its accounting policies and choices and is continuing with its due process in regards to
information that is disclosed. As such, Angle is currently unable to quantify the full impact of adopting IFRS on the financial
statements; however, the Company has disclosed certain expectations above based on information known to date. Due to
anticipated changes to IFRS and International Accounting Standards prior to Angle’s adoption of IFRS, certain items may
be subject to change based on new facts and circumstances that arise after the date of this MD&A.
CONTrOLS AND prOCEDUrES
DISCLOSUrE CONTrOLS
Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company is
accumulated and communicated to management, including the Chief Executive Officer (CEO) and Chief Financial Officer
(CFO), to allow timely decisions regarding required disclosure. Angle’s CEO and CFO have concluded, based on their
evaluation as of the end of the period covered by the Company’s annual filings, that the Company’s disclosure controls
and procedures are effective to provide reasonable assurance that material information related to the issuer is made known
to them by others within the Company.
INTErNAL CONTrOLS OvEr FINANCIAL rEpOrTING
Management has assessed the effectiveness of the Company’s internal controls over financial reporting as defined by
National Instrumental (NI) 52-109. The assessment was based on the framework in “Internal Control – Integrated Framework”
issued by the Committee of Sponsoring Organizations. Management concluded that the Company’s internal controls over
financial reporting were effective as of December 31, 2010. No changes were made to the Company’s internal controls
over financial reporting during the year ended December 31, 2010 that have materially affected, or are reasonably likely to
materially affect, internal controls over financial reporting.
It should be noted that while Angle’s CEO and CFO believe that the Company’s internal controls and procedures provide a
reasonable level of assurance and that they are effective, they do not expect that these controls will prevent all errors and
fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance
that the objectives of the control system are met.
BUSINESS rISkS AND rISk MITIGATION
There are a number of risks facing participants in the Canadian oil and natural gas industry. Some of the risks are common
to all businesses while others are specific to the sector. The most important of these risks are set out below, together with
the strategies Angle employs to mitigate and minimize these risks.
Angle’s exploration and production activities are concentrated in the Western Canada Sedimentary Basin, where activity
is highly competitive and is subject to a number of risks which are also common to other organizations involved in the
oil and natural gas industry. Such risks include finding and developing oil and natural gas reserves in quantities and at
costs enabling a return to be generated, estimating amounts of reserves, production of oil and natural gas in commercial
quantities, marketability of oil and natural gas produced, fluctuations in commodity prices, financial and liquidity risks and
environmental and safety risks.
Angle energy inc 2010 AnnuAl RepoRt64
The Company’s risk-mitigation strategies include focusing on carefully selected areas of western Canada that are prone to
yielding light oil and liquids-rich natural gas reserves, utilizing a team of highly qualified professionals with expertise and
experience in these areas, continuously assessing new exploration opportunities to complement existing activities and
striving for a balance between higher-risk exploratory drilling and lower-risk development drilling.
Beyond exploration risk, there is the potential that the Company’s oil and natural gas reserves will not be economically
produced at prevailing prices. Angle minimizes this risk by continual economic evaluation of internally generated prospects,
targeting high-quality projects and retaining operatorship with access to the sales market through Company-owned or
mid-stream operated facilities.
Angle has retained an independent engineering consulting firm that assists the Company in evaluating recoverable
amounts of oil and natural gas reserves. Values of reserves are based on a number of variable factors and assumptions such
as commodity prices, projected production, future production costs and government regulation. As such, estimates could
vary from actual results.
Angle is exposed to market risk to the extent that the demand for oil and natural gas produced by the Company varies
within Canada and the United States. External factors beyond the Company’s control may affect the marketability of oil
and natural gas produced. These factors include commodity prices and variations in the Canada-United States currency
exchange rate, which in turn respond to economic and political circumstances throughout the world. Oil prices are affected
by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and
demand fundamentals. Angle uses futures and options contracts to hedge its exposure to the potential adverse impact of
commodity price volatility.
The oil and natural gas industry is very capital-intensive and, as a result, the Company relies on equity markets as a source
of new capital in addition to bank financing to support its ongoing capital investments. Funds from operations also provide
capital required to grow the Company’s business. Equity and debt capital is subject to market conditions and availability
may increase or decrease from time to time. Funds from operations also fluctuate with changing commodity prices. Angle
anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future funds from operations
and available bank debt. The Company had no defaults or breaches on its bank debt or any of its financial liabilities.
Substantially all of the Company’s petroleum and natural gas production is marketed under standard industry terms.
Management monitors purchaser credit positions to mitigate any potential credit losses. The Company does not typically
obtain collateral from petroleum and natural gas marketers or joint venture partners; however, Angle has the ability to
withhold production from joint venture partners in the event of non-payment.
Angle energy inc 2010 AnnuAl RepoRt 65
Oil and natural gas exploration and production can involve environmental risks such as pollution of the environment
and destruction of natural habitat, as well as safety risks such as personal injury. The Company conducts its operations
with high standards in order to protect the environment and the general public and operates in accordance with all
applicable environmental legislation and strives to maintain compliance with such regulations. Angle has established an
Environmental, Health & Safety Committee of the Board of Directors and has updated its operational emergency response
plan and operational safety manual to address these operational issues. In addition, a comprehensive insurance program is
maintained to mitigate risks and protect against significant losses where possible. The amount and terms of this insurance
are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry
standards and government regulations.
The Government of Canada has announced its intention to regulate greenhouse gases (GHG). As these regulations are
under development, the Company is unable to predict the total impact of the potential regulations upon its business.
The Government of Alberta has set targets for GHG emission reductions, including maximum emissions of GHG from
large industrial facilities. In order to comply with the Alberta regulations, companies can make operating improvements
to their facilities, purchase carbon offsets or make a monetary contribution to the Alberta Climate Change and Emissions
Management Fund.
BASIS OF prESENTATION
NON-GAAp MEASUrES
This MD&A contains certain financial measures, such as funds from operations and funds from operations per share,
which should not be considered an alternative to or more meaningful than net earnings or cash flow from operating
activities as determined in accordance with GAAP. Funds from operations is calculated by taking cash flow from operating
activities as presented in the consolidated statement of cash flows and adding back changes in non-cash working capital
and settlement of asset retirement costs. Funds from operations per share is calculated using weighted average shares
outstanding consistent with the calculation of net income or loss per share. Angle uses funds from operations to analyze
operating performance and leverage, and considers funds from operations to be a key measure as it demonstrates the
Company’s ability to generate cash necessary to fund future capital investments and repay debt. Angle’s determination of
funds from operations, on an absolute and per share basis, may not be comparable to that reported by other companies.
The following table reconciles funds from operations to cash flow from operating activities, which is the most directly
comparable measure calculated in accordance with GAAP:
Three Months Ended Years Ended December 31, 2010 December 31, 2010
(000s) 2010 2009 2010 2009
Cash flow from operating activities $ 23,804 $ 14,179 $ 53,566 $ 27,843
Changes in non-cash working capital (2,371) (952) 8,437 12,311
Funds from operations $ 21,433 $ 13,227 $ 62,003 $ 40,154
Angle energy inc 2010 AnnuAl RepoRt66
Management considers corporate netbacks important measures as they demonstrate the Company’s profitability relative
to current commodity prices. Corporate netbacks are comprised of operating, funds from operations and net earnings
netbacks. Operating netback is calculated as the average sales price of Angle’s commodities (including realized derivative
gains and losses) less royalties, operating costs and transportation costs. Funds from operations netback starts with the
operating netback and further deducts general and administrative costs and interest expense. Net earnings netback starts
with the funds from operations netback and deducts unrealized derivative gains and losses, stock-based compensation
expense, depletion, depreciation and amortization charges and future income taxes. These measures do not have
standardized meanings prescribed by GAAP and may not be comparable to netbacks presented by other companies.
Net debt is also considered a non-GAAP measure and is used by Angle’s management to monitor remaining availability
under its credit facilities. Net debt is calculated by subtracting current assets from the sum of current liabilities and
long-term debt, excluding derivative instruments and the related tax effect.
BOE CONvErSIONS
Production information is commonly reported in units of barrels of oil equivalent (boe). For purposes of computing such units,
natural gas is converted to equivalent barrels of crude oil using a conversion factor of 6,000 cubic feet of natural gas to one
barrel of oil. This conversion ratio of 6:1 is based on an energy equivalency conversion for the individual products, primarily
applicable at the burner tip, and is not intended to represent a value equivalency at the wellhead. Such disclosure of boe may
be misleading, particularly if used in isolation. Readers should be aware that historical results are not necessarily indicative of
future performance.
FOrwArD-LOOkING STATEMENTS
Certain statements contained in this MD&A constitute forward-looking statements. All statements other than statements
of historical fact are forward-looking statements. These statements are often, but not always, identified by the use of
words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “guidance”, “intend”, “may”, “plan”,
“predict”, “project”, “should”, “target”, “will” or similar words suggesting future outcomes or language suggesting an
outlook.
Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
More particularly and without limitation, this MD&A contains forward-looking statements relating to the Company’s risk
management program, petroleum and natural gas production, future funds from operations, capital programs, commodity
prices, costs and debt levels. The forward-looking statements are based on certain key expectations and assumptions made
by Angle, including expectations and assumptions relating to prevailing commodity prices, applicable royalty rates and tax
laws, future well production rates, the performance of existing wells, the success of drilling new wells, the capital availability
to undertake planned activities and the availability and cost of labour and services.
Angle energy inc 2010 AnnuAl RepoRt 67
Management believes the expectations reflected in such forward-looking statements are reasonable, but no assurance can
be given that these expectations will prove to be correct. Since forward-looking statements address future events and
conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and risks. Forward-looking statements contained in this document
are made as of the date hereof and Angle undertakes no obligation, except as required by applicable securities legislation,
to update publicly or revise any forward-looking statements, whether as a result of new information, future events or
otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
Stuart C. Symon, CMA
Vice President Finance & Chief Financial Officer
March 14, 2011
Angle energy inc 2010 AnnuAl RepoRt68
MANAGEMENT’S rEpOrT
TO ThE ShArEhOLDErS OF ANGLE ENErGY INC.
The accompanying consolidated financial statements of Angle Energy Inc. and all information in this Annual Report are the
responsibility of management and have been approved by the Board of Directors.
The consolidated financial statements have been prepared by management in accordance with Canadian generally
accepted accounting principles and within the framework of the Company’s significant accounting policies as described
in the notes to the consolidated financial statements. The consolidated financial statements reflect management’s best
estimates and judgements based on currently available information within reasonable limits of materiality.
Financial information presented throughout this Annual Report has been prepared and reviewed by management to ensure
it is consistent with that shown in the consolidated financial statements.
Management is responsible for the integrity of the consolidated financial statements. Management maintains appropriate
systems of internal control to provide reasonable assurance that transactions are appropriately authorized, assets are
safeguarded and financial records are properly maintained to provide reliable financial information for the preparation of
financial statements.
Independent auditors are appointed by the shareholders of the Company to perform an examination of the corporate and
accounting records so as to express an opinion on the consolidated financial statements. Their report is presented with the
consolidated financial statements.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and
is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this
responsibility through its Audit Committee. The Audit Committee meets with management and the independent auditors
to satisfy itself that management’s responsibilities are properly discharged, to review the consolidated financial statements
and recommend the consolidated financial statements be presented to the Board of Directors for approval.
The consolidated financial statements, including the notes to the consolidated financial statements, have been approved
by the Board of Directors on the recommendation of the Audit Committee.
heather Christie-Burns Stuart C. Symon
President & Chief Operating Officer Vice President Finance & Chief Financial Officer
Calgary, Canada, March 14, 2011
Fin
An
ciA
ls
Angle energy inc 2010 AnnuAl RepoRt 69
INDEpENDENT AUDITOrS’ rEpOrT
TO ThE ShArEhOLDErS OF ANGLE ENErGY INC.
We have audited the accompanying consolidated financial statements of Angle Energy Inc. (the “Company”), which
comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of operations
and retained earnings, and cash flows for the years then ended, and notes comprising 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 Canadian generally accepted accounting principles, 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.
AUDITOrS’ 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 our 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, we
consider 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 audits 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 consolidated financial
position of the Company as at December 31, 2010 and 2009, and the results of its consolidated operations and its
consolidated cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada, March 14, 2011
Angle energy inc 2010 AnnuAl RepoRt70
CONSOLIDATED BALANCE ShEETS
As at December 31, 2010 2009
(000s) ($) ($)
ASSETS
Current
Cash and cash equivalents – 34,644
Accounts receivable 19,724 11,988
Prepaid expenses and other 3,894 3,722
Derivative instruments (note 10) – 226
Future tax asset (note 8) 520 –
24,138 50,580
Property and equipment (note 4) 534,831 195,885
558,969 246,465
LIABILITIES
Current
Accounts payable and accrued liabilities 37,080 12,099
Derivative instruments (note 10) 1,047 –
38,127 12,099
Bank debt (note 5) 138,916 –
Derivative instruments (note 10) 810 –
Future tax liability (note 8) 31,678 19,453
Asset retirement obligations (note 6) 6,271 2,712
215,802 34,264
ShArEhOLDErS’ EqUITY
Share capital (note 7) 309,648 175,710
Contributed surplus (note 7) 7,244 5,118
Retained earnings 26,275 31,373
343,167 212,201
558,969 246,465
Commitments (note 7 and 12)
Subsequent events (note 10 and 13)
See accompanying notes to the consolidated financial statements.
On behalf of the Board of Directors,
Timothy v. Dunne Edward Muchowski
Director Director
Angle energy inc 2010 AnnuAl RepoRt 71
CONSOLIDATED STATEMENTS OF OpErATIONS AND rETAINED EArNINGS
Years Ended December 31, 2010 2009
(000s, except per share data) ($) ($)
rEvENUE
Oil and natural gas revenues 119,355 79,998
Realized derivative instrument gain 2,113 –
Unrealized derivative instrument (loss) gain (2,084) 226
119,384 80,224
Royalty expense (23,720) (19,902)
95,664 60,322
ExpENSES
Operating 23,053 13,312
General and administrative 7,920 6,350
Interest 4,595 245
Stock-based compensation (note 7) 2,946 1,556
Depletion, depreciation and accretion 64,004 42,350
102,518 63,813
LOSS BEFOrE INCOME TAxES (6,854) (3,491)
INCOME TAxES
Future tax reduction (note 8) (1,756) (459)
NET LOSS FOr ThE YEAr (5,098) (3,032)
rETAINED EArNINGS – BEGINNING OF YEAr 31,373 34,405
rETAINED EArNINGS – END OF YEAr 26,275 31,373
Net loss per share (note 7)
Basic (0.08) (0.07)
Diluted (0.08) (0.07)
See accompanying notes to the consolidated financial statements.
Angle energy inc 2010 AnnuAl RepoRt72
CONSOLIDATED STATEMENTS OF CASh FLOwS
Years Ended December 31, 2010 2009
(000s) ($) ($)
CASh prOvIDED BY (USED IN):
OpErATING ACTIvITIES
Net loss for the year (5,098) (3,032)
Cash settlement of share appreciation rights plan (note 7) – (35)
Add back non-cash items:
Depletion, depreciation and accretion 64,004 42,350
Stock-based compensation 2,946 1,556
Unrealized gain (loss) on derivative instruments (note 10) 2,084 (226)
Future tax reduction (1,756) (459)
Asset retirement expenditures (177) –
62,003 40,154
Change in non-cash working capital (note 9) (8,437) (12,311)
53,566 27,843
FINANCING ACTIvITIES
Issue of common shares, net of share issue expenses 130,414 71,636
Increase in bank debt 116,216 –
Change in non-cash working capital (note 9) (112) 68
246,518 71,704
INvESTING ACTIvITIES
Property and equipment additions (184,979) (42,124)
Corporate acquisition (note 3) (46,148) –
Property and equipment acquisitions (note 3) (123,944) (22,451)
Change in non-cash working capital (note 9) 20,343 (1,267)
(334,728) (65,842)
NET INCrEASE (DECrEASE) IN CASh (34,644) 33,705
CASh – BEGINNING OF YEAr 34,644 939
CASh – END OF YEAr – 34,644
See accompanying notes to the consolidated financial statements.
Angle energy inc 2010 AnnuAl RepoRt 73
NOTES TO ThE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010 and 2009
1. NATUrE OF OpErATIONS
Angle Energy Inc. (“Angle” or the “Company”) is a publicly traded company incorporated under the laws of Alberta.
The principal business of the Company is the exploration, exploitation, development and production of natural gas and
oil reserves.
2. ACCOUNTING pOLICIES
These consolidated financial statements have been prepared in accordance with Canadian generally accepted
accounting principles (GAAP). Since the determination of many assets, liabilities, revenues and expenses is dependent
upon future events, the preparation of these consolidated financial statements requires the use of estimates and
assumptions, which have been made with careful judgement. However, actual results could differ from estimated
amounts. The consolidated financial statements have, in management’s opinion, been properly prepared using careful
judgement within reasonable limits of materiality and within the framework of the significant accounting policies
summarized below.
(a) property and Equipment
(i) Capitalized Costs
The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under
this method, all costs related to the exploration, development and production of petroleum and natural gas
reserves are capitalized in a single Canadian cost centre. Costs include lease acquisition costs, geological
and geophysical expenses, costs of drilling productive and non-productive wells, asset retirement obligation
costs, production equipment costs, general and administrative costs and stock-based compensation directly
related to exploration and development activities. Proceeds from the sale of properties are applied against
capitalized costs, without any gain or loss being realized, unless such sale would alter the rate of depletion
and depreciation by more than 20 percent. Office equipment is recorded at cost.
(ii) Depletion and Amortization
Petroleum and natural gas properties, net of estimated salvage or residual value, and estimated costs
of future development of proved undeveloped reserves are depleted and amortized using the unit-of-
production method based on estimated gross proved petroleum and natural gas reserves as determined by
independent engineers. For depletion and amortization purposes, relative volumes of petroleum and natural
gas production and reserves are converted at the energy equivalent conversion rate of 6,000 cubic feet of
natural gas to one barrel of crude oil.
Angle energy inc 2010 AnnuAl RepoRt74
Costs of unproved properties and seismic costs on undeveloped land are initially excluded from petroleum
and natural gas properties for the purpose of calculating depletion. When proved reserves are assigned or
the property or seismic is considered to be impaired, the costs of the property or seismic or the amount of
the impairment are added to costs subject to depletion.
Office equipment is amortized over its estimated useful life at declining-balance rates between 20 percent and
50 percent per year.
(iii) Ceiling Test
In applying the full cost method, the Company calculates a ceiling test whereby the carrying value of property
and equipment is compared to the sum of the undiscounted cash flows expected to result from the future
production of proved reserves and the sale of unproved properties. Cash flows are based on third-party
quoted forward prices, adjusted for transportation and quality differentials. Should the ceiling test result in
an excess of carrying value, the Company would then measure the amount of impairment by comparing the
carrying amounts of property and equipment to an amount equal to the estimated net present value of future
cash flows from proved plus probable reserves and the lower of cost and market of unproved properties. A
risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying
value would be recorded as a permanent impairment.
(b) Asset retirement Obligations
The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred when
a reasonable estimate of the fair value can be made. The fair value is determined through a review of engineering
studies, industry guidelines and management’s estimate on a site-by-site basis. The fair value of the estimated
asset retirement obligation is recorded as a liability with a corresponding increase in the carrying amount of the
related asset. The capitalized amount is depleted under the unit-of-production method based on working interest
proved reserves. The liability amount is increased each reporting period to reflect the passage of time with the
corresponding amount charged to earnings as accretion expense. Actual costs incurred upon the settlement
of the asset retirement obligation are charged against the asset retirement obligation to the extent of the
liability recorded.
(c) Future Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, future
income tax assets and liabilities are determined based on differences between financial reporting and income tax
bases of assets and liabilities, and are measured using substantively enacted income tax rates and laws that will
be in effect when the differences are expected to reverse. The effect on future income tax assets and liabilities
of a change in income tax rates is recognized in net income in the period in which the change is substantively
enacted. A valuation allowance is recorded to the extent that there is uncertainty regarding utilization of future
tax assets.
Angle energy inc 2010 AnnuAl RepoRt 75
(d) Joint Operations
Substantially all of the exploration and production activities of the Company are conducted jointly with others and
these financial statements reflect only the Company’s proportionate interest in such activities.
(e) Stock Options
Under the Company’s stock option plan described in note 7, options to purchase common shares are granted
to directors, officers and employees at the most recent publicly traded price of the Company’s common shares.
Stock-based compensation expense is recorded in the statement of operations for all options granted with a
corresponding increase recorded as contributed surplus. Compensation expense is based on the estimated fair
values at the time of the grant and the expense is recognized over the vesting term of the options. Upon the
exercise of the stock options, consideration paid together with the amount previously recognized in contributed
surplus is recorded as an increase in share capital. The Company has not incorporated an estimated forfeiture rate
for stock options that will not vest; rather, the Company accounts for the forfeitures as they occur. In the event that
vested options expire, previously recognized compensation expense associated with such stock options is not
reversed. In the event that options are forfeited, previously recognized compensation expense associated with
the unvested portion of such stock options or stock appreciation rights (SARs) is reversed.
(f) Flow-Through Shares
Periodically, the Company finances a portion of its exploration and development activities through the issuance
of flow-through shares. Under the terms of the flow-through share issues, the tax attributes of the related
expenditures are renounced to subscribers. Share capital is reduced and the future tax liability is increased by
the tax-effected amount of the renounced tax deductions at the time of renunciation, which is when the related
documentation is filed with the appropriate governmental agency and there is reasonable certainty that the
expenditures will be incurred.
(g) revenue recognition
Revenue from the sale of natural gas, natural gas liquids and crude oil is recognized based on volume delivered
at contractual delivery points and rates. The cost associated with the delivery, including operating, transportation
and production-based royalty expenses, is recognized in the same period in which the related revenue is earned
and recorded.
Angle energy inc 2010 AnnuAl RepoRt76
(h) per Share Amounts
Basic net income or loss per share is computed by dividing net income or loss by the weighted average number
of common shares outstanding during the period. The treasury stock method is used to calculate diluted per share
amounts whereby proceeds from the exercise of in-the-money stock options, warrants or SARs and unrecognized
future stock-based compensation expense are assumed to be used to purchase common shares of the Company
at the average market price during the period. Diluted per share amounts reflect the potential dilution that
could occur if stock options or warrants to purchase common shares or SARs were exercised and converted to
common shares.
(i) Cash and Cash Equivalents
The Company considers all highly liquid investments with maturity of three months or less at the time of purchase
to be cash equivalents.
(j) Measurement Uncertainty
The amount recorded for depletion and depreciation of petroleum and natural gas properties and the ceiling test
calculation are based on estimates of gross proved reserves, production rates, commodity prices, future costs
and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the
effects on the financial statements of changes in such estimates in future years could be significant.
Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgements,
including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement
and changes in the legal and regulatory environments. To the extent future revisions to these assumptions impact
the fair value of the existing asset retirement obligation, a corresponding adjustment is made to the property and
equipment account.
The fair value estimates for derivatives are based on expected future natural gas prices and volatility in those
prices. By their nature, these estimates are subject to measurement uncertainty and the effects on the financial
statements of changes in such estimates in future years could be significant.
(k) Financial Instruments
A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or
equity instrument of another entity. Upon initial recognition, all financial instruments, including all derivatives,
are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial
instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables,
available for sale and other liabilities. The Company has designated its cash and derivative instruments as held
for trading, which are measured at fair value. Accounts receivable are classified as loans and receivables, which
are measured at amortized cost. Accounts payable and accrued liabilities, and bank debt are classified as other
liabilities, which are measured at amortized cost that is determined using the effective interest method.
Angle energy inc 2010 AnnuAl RepoRt 77
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates
and interest rates in the normal course of operations. A variety of derivative instruments may be used by the
Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates and interest rates.
The Company does not use these derivative instruments for trading or speculative purposes. The Company
considers all of these transactions to be economic hedges; however, the Company’s contracts do not qualify or
have not been designated as hedges for accounting purposes. As a result, all derivative contracts are classified
as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized
in net income. The fair values of these derivative instruments are based on an estimate of the amounts that would
have been received or paid to settle these instruments prior to maturity given future market prices and other
relevant factors. Proceeds and costs realized from holding the derivative are recognized in net income at the time
each transaction under a contract is settled.
The Company measures and recognizes embedded derivatives separately from the host contracts when the
economic characteristics and risks of the embedded derivative are not closely related to those of the host contract,
when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded
derivatives are recorded at fair value.
The Company immediately expenses all transaction costs incurred in relation to the acquisition of a financial
asset or liability. The Company applies trade-date accounting for the recognition of a purchase or sale of
cash equivalents.
Comprehensive income requires certain gains and losses from changes in fair value to be temporarily presented
outside net income. It includes unrealized gains and losses, such as changes in currency translation adjustment
relating to self-sustaining foreign operations, unrealized gains or losses on available-for-sale investments and the
effective portion of gains or losses on derivatives designated as cash flow hedges. The application of this standard
did not result in comprehensive income being different from the net income for the periods presented.
(l) Future Accounting Changes
(i) International Financial Reporting Standards (IFRS)
In February 2008, the Canadian Institute of Chartered Accountants’ (CICA) Accounting Standards Board
confirmed the changeover to IFRS from Canadian GAAP will be required for publicly accountable enterprises
for interim and annual financial statements for fiscal years beginning on or after January 1, 2011, including
comparative figures for 2010. Although IFRS is principles-based and uses a conceptual framework similar
to Canadian GAAP, there are significant differences and choices in accounting policies as well as increased
disclosure requirements under IFRS. Angle is currently assessing the impact of the conversion from Canadian
GAAP to IFRS on its consolidated financial statements.
Angle energy inc 2010 AnnuAl RepoRt78
3. ACqUISITIONS
(a) Corporate Acquisition
On January 12, 2010, Angle acquired all of the issued and outstanding shares of Stonefire Energy Corp.
(“Stonefire”), a publicly traded junior oil and natural gas exploration company, for cash consideration of
$46,650,000. In addition, Angle incurred transaction costs of $1,060,000 and assumed Stonefire’s net debt of
$26,417,000. The operations of Stonefire have been included with the results of Angle commencing January 12,
2010. The transaction was accounted for by the purchase method.
(000s) ($)
Fair value of net assets acquired:
Petroleum and natural gas assets 89,949
Bank debt (22,700)
Working capital deficiency (1) (3,717)
Asset retirement obligations (594)
Future income tax liability (15,228)
Net assets acquired 47,710
Consideration:
Cash 46,650
Transaction costs 1,060
47,710
(1) Working capital deficiency includes cash of $1,562,000.
(b) property Acquisitions
On June 30, 2010, Angle acquired certain interests in petroleum and natural gas properties in the Edson area for
cash consideration of $116,396,000 (including transaction costs of approximately $1,396,000), with associated
asset retirement obligations of $1,856,000.
In June 2010, Angle acquired an additional working interest in several wells and a compression facility in the
Ferrier area for cash consideration of $7,271,000 (including initial adjustments), with associated asset retirement
obligations of $46,000.
Angle energy inc 2010 AnnuAl RepoRt 79
4. prOpErTY AND EqUIpMENT
Accumulated Depletion and Net Book Cost Amortization Value
(000s) ($) ($) ($)
December 31, 2010
petroleum and natural gas properties 692,018 157,992 534,026
Office equipment 1,440 635 805
693,458 158,627 534,831
December 31, 2009
Petroleum and natural gas properties 289,908 94,765 195,143
Office equipment 1,137 395 742
291,045 95,160 195,885
For the year ended December 31, 2010 the Company capitalized $1,084,000 of direct general and administrative costs
(2009 – $818,000), $689,000 of stock-based compensation expense (2009 – $476,000) and $1,909,000 of operator
overhead related to the Company’s exploration and development activity (2009 – $604,000).
Unevaluated and undeveloped properties with a cost of $59,247,000 as at December 31, 2010 (December 31, 2009
– $18,961,000), included in petroleum and natural gas properties, have not been subject to depletion as reserves
related to these costs had not been assigned for the year ended December 31, 2010. As at year-end 2010, future
development costs totalling $116,838,000 (December 31, 2009 – $20,821,000) were included in amounts subject
to depletion.
The Company performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of
its petroleum and natural gas interests. It was determined that there was no impairment using the prices in the
following table:
Oil Natural Gas NGLsYear Price Price Price
($/bbl) ($/mcf) ($/bbl)
2011 83.09 4.24 53.112012 86.24 4.87 53.292013 87.91 5.47 54.502014 89.97 5.96 56.492015 * 93.22 6.46 59.00
* Thereafter, annual increases of 2 percent.
Angle energy inc 2010 AnnuAl RepoRt80
5. BANk DEBT
The Company has a revolving committed credit facility with three chartered banks with a borrowing base of
$180,000,000. The next semi-annual review of the credit facility is to take place on or before April 29, 2011.
The credit facility may be extended and revolve beyond the initial one-year period, if requested by the Company and
accepted by the lenders. The current revolving period will expire April 29, 2011. If the credit facility does not continue
to revolve, the facility will convert to a 366-day non-revolving term loan facility. The amount of the facility is subject to
a borrowing base test performed on a periodic basis by the lenders, based primarily on reserves and using commodity
prices estimated by the lenders as well as other factors. A decrease in the borrowing base could result in a reduction
to the credit facility, which may require a repayment to the lenders.
The credit facility provides that advances may be made by way of direct advances or bankers’ acceptances. The credit
facility bears interest at the bank’s prime rate plus a margin (1.00 percent to 2.50 percent) or at bankers’ acceptance
rates plus a stamping fee (2.50 percent to 4.00 percent) based on the Company’s total debt to cash flow ratio. For
purposes of this calculation, consolidated total debt is defined as total liabilities less current assets and cash flow
is defined as cash flow from operations for the last two quarters multiplied by two (annualized). A general security
agreement over all present and after-acquired personal property and a floating charge on all lands has been provided
as security.
6. ASSET rETIrEMENT OBLIGATIONS
The Company recorded an asset retirement obligation calculated as the present value of the estimated future cost
to abandon its petroleum and natural gas properties. To determine the value of this obligation as at December 31,
2010, the Company utilized an inflation rate of 2 percent (December 31, 2009 – 2 percent) and a credit-adjusted
risk-free interest rate of 8-10 percent (December 31, 2009 – 8-10 percent) to discount the future estimated cash flows
of $16,642,000 (December 31, 2009 – $6,042,000) of which the majority of costs are expected to be incurred over a
period of one to 25 years. A continuity of the asset retirement obligations in the years ended December 31, 2010 and
2009, along with the liabilities at the beginning and end of each year, are as follows:
Years Ended December 31, 2010 2009
(000s) ($) ($)
Balance – beginning of year 2,712 1,979
Change in estimates 165 (385)
Liabilities incurred 538 904
Liabilities acquired on corporate acquisition 594 –
Liabilities acquired on property acquisitions 1,902 –
Liabilities settled (177) –
Accretion of asset retirement obligation 537 214
Asset retirement obligation – end of year 6,271 2,712
Angle energy inc 2010 AnnuAl RepoRt 81
7. ShArE CApITAL
(a) Authorized
Unlimited number of common voting shares, no par value.
Unlimited number of preferred shares, no par value, issuable in series.
(b) Issued
Years Ended December 31, 2010 2009
Shares Amount Shares Amount
(#) ($000s) (#) ($000s)
Common Shares
Balance – beginning of year 54,481,132 175,710 39,296,574 104,995
Common shares issued 14,999,699 114,699 15,184,558 76,384
Flow-through shares issued 2,488,000 25,004 – –
Tax effect of flow-through shares – – – (2,516)
Share issue costs – (7,780) – (4,212)
Tax benefit of share issue costs – 2,015 – 1,059
Balance – end of year 71,968,831 309,648 54,481,132 175,710
In May 2010, the Company issued 6,080,000 common shares at a price of $7.70 per common share for gross
proceeds of $46,816,000 ($44,175,000 net of issue costs).
In June 2010, the Company issued 8,050,000 subscription receipts at a price of $7.90 per subscription receipt,
for total proceeds of $63,595,000 ($59,965,000 net of issue costs). Upon exercise, each subscription receipt was
convertible to one common share. All subscription receipts were deemed exercised and converted to common
shares on June 30, 2010.
In November 2010, the Company issued 2,488,000 flow-through common shares at $10.05 per share for total
gross proceeds of $25,004,000 ($23,495,000 net of issue costs). Under the terms of the flow-through agreement,
the Company is committed to spending $25,004,000 on qualified exploration and development expenditures by
December 31, 2011.
In 2010, the Company issued 869,699 common shares resulting from the exercise of stock options, for cash
proceeds of $2,779,000 and previously recognized stock-based compensation expense of $1,509,000.
(c) Contributed Surplus
Years Ended December 31, 2010 2009
(000s) ($) ($)
Balance – beginning of year 5,118 3,657
Stock-based compensation – options 3,635 1,393
Reduction due to exercise of options (1,509) (536)
Stock-based compensation – SARs – 639
Reduction due to cash settlement of SARs plan – (35)
Balance – end of year 7,244 5,118
Angle energy inc 2010 AnnuAl RepoRt82
(d) per Share Amounts
For the year ended December 31, 2010, net loss per common share is calculated using the weighted average
number of shares outstanding of 63,224,182 (basic and diluted) (2009 – 43,747,835 basic and diluted). Outstanding
options were anti-dilutive instruments in 2010 and 2009 because the Company incurred a net loss in the years
ended December 31, 2010 and 2009.
For the three months ended December 31, 2010, net loss per common share is calculated using the weighted
average number of shares outstanding of 70,596,866 (basic and diluted) (three months ended December 31,
2009 – 48,150,676 basic and diluted). Outstanding options were anti-dilutive instruments in 2010 and 2009
because the Company incurred a net loss in the three-month periods ended December 31, 2010 and 2009.
(e) Options Outstanding
The Company has a stock option plan, administered by the Board of Directors, under which up to 10 percent of
the issued and outstanding common shares are reserved for issuance to officers, employees and directors. Under
the plan, options vest equally one-third on the first, second and third anniversaries from the option grants and
expire in five years or immediately upon the date the optionee ceases to be a director, officer or employee of the
Company or six months after the involuntary withdrawal of the optionee.
The following tables summarize information about stock options outstanding as at December 31, 2010:
Weighted Average Exercise Options Price
(#) ($)
Outstanding at December 31, 2008 2,945,000 2.81
Granted in 2009 2,547,750 4.91
Exercised in 2009 (875,334) (1.30)
Forfeited in 2009 (236,500) (6.32)
Outstanding at December 31, 2009 4,380,916 4.14
Granted in 2010 2,653,000 7.59
Exercised in 2010 (869,699) (3.19)
Forfeited in 2010 (105,000) (5.28)
Outstanding at December 31, 2010 6,059,217 5.77
Angle energy inc 2010 AnnuAl RepoRt 83
Weighted Average Weighted Weighted Remaining Average Average Contractual Exercise Exercise
Exercise Price Outstanding Life Price Exercisable Price
($) (#) (years) ($) (#) ($)
As at December 31, 2010
2.80 – 4.59 2,645,467 2.35 4.06 1,665,296 3.87
4.60 – 6.39 760,750 3.43 5.36 298,665 5.35
6.40 – 8.19 2,434,500 4.69 7.48 – –
8.20 – 10.00 218,500 4.13 8.82 – –
6,059,217 3.49 5.77 1,963,961 4.09
As at December 31, 2009
1.00 – 2.79 96,666 0.3 1.00 96,666 1.00
2.80 – 4.59 3,359,500 3.0 3.90 1,624,000 3.44
4.60 – 6.39 924,750 4.3 5.35 88,249 5.30
4,380,916 3.2 4.14 1,808,915 3.40
The fair value of common share options granted during the year ended December 31, 2010 was estimated to be
$9,519,000 or $3.59 per weighted average option (2009 – $4,499,000 or $2.64) as at the date of grant using the
Black-Scholes pricing model and the following average assumptions:
Years Ended December 31, 2010 2009
Risk-free interest rate (%) 2.13 2.45
Expected life (years) 5.00 5.00
Expected volatility (%) 52.51 64.25
(f) Management of Capital Structure
The Company’s objective when managing capital is to maintain a flexible capital structure that will allow it to
execute its capital expenditure program, which includes expenditures on oil and natural gas activities that may
or may not be successful. The current economic conditions are such that equity financing may not be available,
and availability of bank credit is generally tightening with the related costs increasing. The Company recognizes
these trends and endeavours to balance the proportion and levels of the debt and equity in its capital structure
to take into account the level or risk being incurred in its capital expenditures.
In the management of capital, the Company includes share capital of $309,648,000 and net debt of $152,378,000
(defined as the sum of current assets, current liabilities and bank debt, excluding derivative instruments and
related tax effects) in the definition of capital.
Angle energy inc 2010 AnnuAl RepoRt84
The key measures that the Company utilizes in evaluating its capital structure are the ratio of net debt to funds
from operations (which is cash flow from operations before changes in non-cash working capital and settlement of
retirement costs) and the current credit available from its creditors in relation to the Company’s budgeted capital
expenditure program. The ratio of net debt to funds from operations is determined as net debt divided by funds
from operations and represents the time it would take to pay off the debt if no further capital expenditures were
incurred and if funds from operations stayed constant. Funds from operations for the year ended December 31,
2010 were $62,180,000 (2009 – $40,154,000), resulting in a net debt to funds from operations ratio of 2.45:1.
This ratio is above the Company’s standard acceptable range of 2.0:1 or less due to the timing of the property
acquisition completed on June 30, 2010. This ratio has decreased from 3.11:1 in the third quarter of 2010 and
the Company expects this ratio to be closer to the acceptable range in 2011.
The Company manages its capital structure and makes adjustments by continually monitoring its business
conditions, including the current economic conditions, the risk characteristics of the underlying assets, the depth
of its investment opportunities, forecast investment levels, the past efficiencies of the Company’s investments,
the efficiencies of forecast investments and the desired pace of investment, current and forecast total debt levels,
current and forecast energy commodity prices, and other factors that influence commodity prices and funds from
operations, such as foreign exchange and quality basis differentials.
In order to maintain or adjust the capital structure, the Company will consider its forecast net debt to forecast
funds from operations ratio while attempting to finance an acceptable capital expenditure program, including
incremental capital spending and acquisition opportunities, the current level of bank credit available from the
commercial bank, the level of bank credit that may be attainable from its commercial bank as a result of growth in
the Company’s oil and natural gas reserves, the availability of other sources of debt with different characteristics
than the existing bank debt, the sale of assets limiting the size of the Company’s capital spending program, and
new common equity if available on terms.
During 2010, the Company’s strategy in managing its capital was unchanged.
Angle energy inc 2010 AnnuAl RepoRt 85
8. INCOME TAxES
The actual income tax provision differs from the expected amount calculated by applying the Canadian combined
federal and provincial corporate tax rates to loss before income taxes. These differences are explained as follows:
Years Ended December 31, 2010 2009
(000s except percentage rates) ($) ($)
Loss before income taxes (6,854) (3,491)
Tax rate 28.00% 29.00%
Computed income tax provision (1,919) (1,012)
Increase (decrease) in income taxes resulting from:
Rate adjustment (482) (94)
Stock-based compensation 825 451
Other (225) 159
Non-deductible expenses 45 37
(1,756) (459)
Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the
Company’s net future income tax assets and liabilities are as follows:
Years Ended December 31, 2010 2009
(000s) ($) ($)
Future income tax assets (liabilities):
Share issue costs 2,691 1,551
Net book value of property and equipment in excess of tax basis (34,342) (20,941)
Other 493 (63)
Future income tax asset (liability) (31,158) (19,453)
9. ChANGES IN NON-CASh wOrkING CApITAL
Years Ended December 31, 2010 2009
(000s) ($) ($)
Accounts receivable (6,867) 508
Prepaid expenses and other 343 (2,456)
Accounts payable and accrued liabilities 18,318 (11,562)
11,794 (13,510)
The change in non-cash working capital has been allocated to the following activities:
Years Ended December 31, 2010 2009
(000s) ($) ($)
Operating (8,437) (12,311)
Financing (112) 68
Investing 20,343 (1,267)
11,794 (13,510)
Angle energy inc 2010 AnnuAl RepoRt86
10. FINANCIAL INSTrUMENTS
The Company has exposure to credit, liquidity and market risk.
Angle’s risk management policies are established to identify and analyze the risks faced by the Company, set appropriate
limits and controls, and monitor risks and adherence to market conditions and the Company’s activities.
(a) Fair value of Financial Assets and Liabilities
Financial instruments of the Company consist primarily of cash and cash equivalents, accounts receivable, accounts
payable, bank debt and derivative contracts. The fair values of these instruments, excluding derivative contracts,
approximate their carrying amounts due to their short term to maturity.
Angle’s derivative contracts, which are recorded at fair value on a recurring basis, have been classified in one of
the following three categories based on a fair-value hierarchy in accordance with the CICA Handbook Section
3862, “Financial Instruments – Disclosures”:
• Level1–Quotedpricesareavailableinactivemarketsforidenticalassetsorliabilitiesasofthereportingdate.
Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
• Level2–PricinginputsareotherthanquotedpricesinactivemarketsincludedinLevel1.Pricesareeither
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
or corroborated in the marketplace.
• Level3–Valuationsinthislevelarethosewithinputsfortheassetorliabilitythatarenotbasedonobservable
market data.
The fair value of the Company’s financial instruments is attributable to the following fair value levels as at
December 31, 2010:
Fair Value Level 1 Level 2 Level 3
(000s)
Derivative liability 1,857 – 1,857 –
Bank indebtedness 138,916 138,916 – –
Angle energy inc 2010 AnnuAl RepoRt 87
(b) Credit risk
Substantially all of the Company’s petroleum and natural gas production is marketed under standard industry
terms. The industry has a pre-arranged monthly settlement day for payment of revenues from all buyers of crude
oil and natural gas. This occurs on the 25th day following the month in which the production is sold. As a result,
Angle collects sales revenues in an organized manner. Management monitors purchaser credit positions to mitigate
any potential credit losses. To the extent Angle has joint interest activities with industry partners, the Company
must collect, on a monthly basis, partners’ share of capital and operating expenses. These collections are subject
to normal industry credit risk. Angle attempts to mitigate risk from joint venture receivables by obtaining partner
approval of capital projects prior to expenditure and collects in advance significant amounts related to partners’
share of capital expenditures in accordance with the industry’s operating procedures. The Company does not
typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, Angle
has the ability to withhold production from joint venture partners in the event of non-payment. At December 31,
2010, of $19,724,000 in accounts receivable, 95 percent was current, 4 percent was 31 to 90 days due and the
balance was over 90 days due. Angle had no material accounts receivable deemed uncollectible.
The Company’s credit risk is limited to the carrying amount of its accounts receivable, which are due primarily from
other entities involved in the oil and natural gas industry. These amounts are subject to the same risks as the
industry as a whole.
(c) Liquidity risk
Liquidity risk relates to the risk the Company will encounter should it have difficulty in meeting obligations
associated with the financial liabilities. The financial liabilities on its balance sheet consist of accounts payable
and bank debt. Accounts payable consist of invoices payable to trade suppliers relating to the office and field
operating activities and the Company’s capital spending program. Angle processes invoices within a normal
payment period. Angle anticipates it will continue to have adequate liquidity to fund its financial liabilities through
its future funds from operations and available bank debt. The Company had no defaults or breaches on its bank
debt or any of its financial liabilities as at or for the year ended December 31, 2010.
(d) Market risk
Market risk is the risk of changes in market prices, such as commodity prices, foreign currency exchange rates and
interest rates, that will affect the net earnings or value of financial instruments. The objective of managing market
risk is to control market risk exposures within acceptable limits, while maximizing returns.
The Company may utilize financial derivative contracts to manage market risk. All such transactions are conducted
in accordance with the risk management policy that has been approved by the Board of Directors.
Angle energy inc 2010 AnnuAl RepoRt88
(i) Commodity Price Risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes
in the commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the
relationship between the Canadian and United States dollars, as outlined below, but also global economic
events that dictate the levels of supply and demand. The Company has attempted to mitigate commodity
price risk through the use of financial derivative contracts. As at December 31, 2010, the Company had fixed
the price applicable to future production through the following contracts:
Type of Quantity ContractPeriod Commodity Contract Contracted Price ($/unit)
Jan. 1/11 – Dec. 31/11 Natural Gas Financial 5,000 GJ/d AECO Cdn$3.825/GJ
Apr. 1/11 – Mar. 31/12 Natural Gas Financial 2,500 GJ/d AECO Cdn$3.775/GJ
Apr. 1/11 – Mar. 31/12 Natural Gas Financial 2,500 GJ/d AECO Cdn$3.815/GJ
Jan. 1/11 – June 30/12 Crude Oil Financial 500 bbls/d Nymex US$87.05/bbl
Subsequent to December 31, 2010, the Company entered into the following contract:
Type of Quantity ContractPeriod Commodity Contract Contracted Price ($/unit)
Apr. 1/11 – Oct. 31/11 Natural Gas Financial 5,000 GJ/d AECO Cdn$3.82/GJ
(ii) Foreign Currency Exchange Rate Risk
Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of
changes in foreign exchange rates. The Company does not sell or transact in any foreign currency; however,
the United States dollar influences the price of petroleum and natural gas sold in Canada.
The Company has entered into a currency average rate forward swap transaction whereby U.S. dollars have
been converted to Canadian dollars as summarized in the following table:
Period Amount Strike Price
Jan. 1/11 – June 30/12 US$1,300,000/month Cdn$1.0535
Angle is only entitled to a cash settlement if the monthly average currency exchange rate as reported by the
Bank of Canada is greater than 0.95.
Angle entered into the above transaction to protect against foreign exchange fluctuations on the U.S. Nymex
oil hedge.
Angle energy inc 2010 AnnuAl RepoRt 89
(iii) Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest
rates. The Company is exposed to interest rate risk to the extent the changes in market interest rates
will impact the Company’s debts that have a floating interest rate. The Company had no interest rate swaps
or hedges at December 31, 2010. With regards to interest rate risk, a change of 1 percent in the effective
interest rate would impact net earnings by approximately $226,000 annually, based on average debt
outstanding in 2010.
11. rELATED pArTIES
During 2010, expenses and share issue costs were recorded totalling $1,375,000 (2009 – $562,000) that were charged
to the Company by a legal firm of which a Director of the Company is a partner, and $85,000 remained in accounts
payable at December 31, 2010 (December 31, 2009 – $115,000). These amounts are billed and recorded at rates
consistent with those charged to third parties.
12. COMMITMENTS
As at December 31, 2010 the Company has lease commitments for office premises that expire in 2014, for three
compressors that expire in 2011 and for four compressors that expire in 2012. Future minimum payments under the
leases are as follows:
(000s) ($)
2011 2,395
2012 1,524
2013 690
2014 633
5,242
The Company is committed to spending $25,004,000 in qualified exploration expenditures by December 31, 2011. At
December 31, 2010, there was $23,507,000 remaining to be expended on this commitment.
13. SUBSEqUENT EvENT
On December 13, 2010, pursuant to a bought-deal public offering, Angle issued convertible unsecured subordinated
debentures for gross proceeds of $60,000,000 (net proceeds estimated to be $57,600,000) at a price of $1,000 per
debenture. The debentures bear interest at a rate of 5.75 percent per annum, which is payable semi-annually in arrears
on January 31 and July 31 of each year commencing on July 31, 2011. The debentures mature on January 31, 2016
and can be converted into common shares of Angle at any time at the option of the holders at a conversion price of
$12.55 per common share. On January 6, 2011, Angle announced the bought-deal was completed.
Angle energy inc 2010 AnnuAl RepoRt90
hISTOrICAL rEvIEw
Years Ended December 31 2010 2009 2008 2007 2006
Financial(000s, except per share amounts) (unaudited) ($) ($) ($) ($) ($)
Commodity revenues (1) 121,468 79,998 127,885 55,683 19,621Funds from operations (2) 62,003 40,154 69,801 29,663 7,985 Per share – basic 0.98 0.92 1.91 0.91 0.28Net income (loss) (5,098) (3,032) 26,372 9,650 1,543 Per share – basic (0.08) (0.07) 0.72 0.30 0.05Capital expenditures (3) 355,071 64,575 79,866 59,110 57,821Total assets 558,969 246,465 186,985 134,371 87,072Net debt (working capital) (4) 152,378 (38,255) 8,960 31,819 10,772Shareholders’ equity 343,167 212,201 143,057 82,461 65,344
Common Share Data Common shares outstanding (000s) At December 31 71,969 54,481 39,297 34,523 32,498 Weighted average – basic 63,224 43,748 36,576 32,626 28,617Share trading High ($) 8.90 6.72 8.52 – – Low ($) 6.77 3.18 3.25 – – Close ($) 8.30 6.72 3.60 – – Volume (000s) 65,513 21,405 14,796 – –
Operating Sales Natural gas (mcf/d) 34,248 26,334 23,336 11,688 3,975 NGLs (bbls/d) 2,892 2,995 2,650 1,372 612 Light crude oil (bbls/d) 643 144 46 14 7 Total oil equivalent (boe/d) 9,243 7,528 6,586 3,334 1,281Average wellhead prices (1) Natural gas ($ per mcf) 4.47 4.06 8.20 7.14 6.80 NGLs ($ per bbl) 45.42 34.46 58.15 49.52 42.90 Light crude oil ($ per bbl) 75.39 61.74 86.40 80.74 66.00 Combined average ($ per boe) 36.00 29.11 53.06 45.76 41.95
Reserves Proved (mboe) 31,900 12,309 11,462 9,194 6,203 Proved plus probable (mboe) 59,696 20,033 15,935 13,638 12,396 Total net present value – proved plus probable (10% discount) ($000s) 749,296 276,847 272,614 222,744 146,300
Wells drilled (gross) Natural gas 19 9 14 12 16 Oil 18 – 4 2 – Dry and abandoned 3 4 6 5 6
Total 40 13 24 19 22
(1) Revenue and product prices include realized gains or losses from derivative instruments.(2) Funds from operations and funds from operations per share are not recognized measures under Canadian GAAP. Refer to the Management’s
Discussion and Analysis for further discussion.(3) Total capital expenditures, including acquisitions.(4) Current assets less current liabilities and bank debt, excluding derivative instruments and the related tax effect.(5) For a description of the boe conversion ratio, refer to the commentary at the end of the Management’s Discussion and Analysis.
Angle energy inc 2010 AnnuAl RepoRt 91
BOArD OF DIrECTOrS
Noralee Bradley – Chairman (3)(4)
PartnerOsler, Hoskin & Harcourt LLP
Clarence Chow (2)(4)
President CGS Asset Management Ltd.
Timothy V. Dunne (1)(3)
Independent Businessman
D. Gregg FischbuchChief Executive OfficerAngle Energy Inc.
John Gareau (1)(3)
Independent Businessman
Edward Muchowski (2)(4)
Independent Businessman
Jacob Roorda (1)(2)
Vice ChairmanCanoe Financial
(1) Audit Committee Member
(2) Reserves Committee Member(3) Corporate Governance & Compensation
Committee Member(4) Environmental, Health & Safety
Committee Member
OFFICErS
Heather Christie-BurnsPresident & Chief Operating Officer
D. Gregg FischbuchChief Executive Officer
Stuart C. SymonVice President Finance, Chief Financial Officer & Corporate Secretary
G. Graham CormackVice President Operations
Glen RichardsonVice President Land
Elizabeth MoreVice President Exploration
Matthew MazurykVice President Engineering
Heather PostController
hEAD OFFICE
Suite 700324 Eighth Avenue S.W.Calgary, Alberta T2P 2Z2Telephone: 403-263-4534Facsimile: 403-263-4179Website: www.angleenergy.com
AUDITOrS
KPMG LLPCalgary, Alberta
BANkErS
ATB FinancialCalgary, Alberta
Bank of MontrealCalgary, Alberta
Canadian Imperial Bank of CommerceCalgary, Alberta
EvALUATION ENGINEErS
GLJ Petroleum Consultants Ltd.Calgary, Alberta
Seaton-Jordan & Associates Ltd.Calgary, Alberta
LEGAL COUNSEL
Osler, Hoskin & Harcourt LLPCalgary, Alberta
rEGISTrAr AND TrANSFEr AGENT
Inquiries regarding change of address, registered shareholdings, stock transfers or lost certificates should be directed to:
Valiant Trust CompanySuite 310606 Fourth Street S.W.Calgary, Alberta T2P 1T1Telephone: 403-233-2801
STOCk TrADING
Toronto Stock ExchangeTrading Symbol: NGL
COrpOrATE INFOrMATION
Angle energy inc 2010 AnnuAl RepoRt92
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AbbreviAtions
bbls barrelsbcf billion cubic feetboe barrels of oil equivalentGJ gigajoules/d per daymbbls thousand barrelsmboe thousand barrels of oil equivalentmcf thousand cubic feetmm million mmboe million barrels of oil equivalentmmbtu million British thermal unitsmmcf million cubic feetNGLs natural gas liquids2-D two dimensional3-D three dimensional
Conversion of Units
1.0 acre = 0.40 hectares2.5 acres = 1.0 hectare1.0 bbl = 0.159 cubic metres6.29 bbls = 1.0 cubic metre1.0 foot = 0.3048 metres3.281 feet = 1.0 metre1.0 mcf = 28.2 cubic metres0.035 mcf = 1.0 cubic metre1.0 mile = 1.61 kilometres0.62 miles = 1.0 kilometreNatural gas is equated to oil on the basis of 6 mcf : 1 bbl
Suite 700, 324 Eighth Avenue S.W.
Calgary, Alberta T2P 2Z2
Telephone: (403) 263-4534
Fax: (403) 263-4179
Website: www.angleenergy.com