angle energy inc

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


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.


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.


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.


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


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


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.


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


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.


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


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.


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.


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


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?


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.


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.


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

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Shareholders’ equity ($mm) Total assets ($mm)


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


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.


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.


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


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.


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


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


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





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.


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.


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.


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





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


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





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.


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

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


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.


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


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


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



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


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


Proved (years)

4.7 4.3 4.0 5.1 5.9

06 07 08 09 10


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


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.


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


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.


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.


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


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 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


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


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


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


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


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


(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


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


(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



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


INTErEST ExpENSE



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



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)



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.


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


($/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.


FUNDS FrOM OpErATIONS, CASh FLOw FrOM OpErATING ACTIvITIES AND NET INCOME Or LOSS


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


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).


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.


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.


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.


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.


• 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.


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.


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.


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


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.


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


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


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


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


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)



CONSOLIDATED STATEMENTS OF CASh FLOwS


(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



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.


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.


(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.


(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.


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.


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.


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.


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:


(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


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


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


(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


(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)


Granted in 2010 2,653,000 7.59

Exercised in 2010 (869,699) (3.19)

Forfeited in 2010 (105,000) (5.28)



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:


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.


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.


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:


(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:


(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


(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:


(000s) ($) ($)

Operating (8,437) (12,311)

Financing (112) 68

Investing 20,343 (1,267)

11,794 (13,510)


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 – –


(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.


(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



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.


(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.


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.


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)


Edward Muchowski (2)(4)


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


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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

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