Angle Energy Inc.

2010 Annual Report

More oil.

From every angle.

More reach.

More value.

Selected Highlights.............. 6 Management’s Q & A.......... 8

$185 million capital budget in 2010 added highly prospective lands and strategic new facilities – plus funded 30 net horizontal wells.

Exploration and Operations Review..............18 Operations Statistical Review................36 Financial Management......................... 44

We tripled proved plus probable reserves year-over-year and drove our reserve-life-index to 12 years. (1)

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

We added a net 1,000 bbls per day of high-netback light oil by year-end 2010, complementing our liquids-rich natural gas.

From every angle, we’re becoming an intermediate energy producer.

13,500 boe/d 2010 exit production

59.7

million boe proved plus probable reserves (2) (1) (2)

Based on 2010 exit production.

At December 31, 2010.

274

net sections developable land (2)

>800

drilling locations

It adds up to one of the most exciting stories in the Canadian energy sector.

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.

Our new value is just beginning.

Angle Energy inc

2010 Annual Report

1

Growth drivers 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.

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.

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.

Asset quality

We shine in technical control

Our assets are deep and wide and allow us to

Our technical team of geoscientists

add more oil, while prudently developing our

and engineers is one of the best in the

liquids-rich natural gas.

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.

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Angle Energy inc

2010 Annual Report

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.

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.

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.

Value makers Our efficiencies provide high rates of return

Technologies that optimize reservoir development

Through the first half of our full-cycle

We’re mastering the application of horizontal

exploration program, Angle is maintaining

wells with multi-stage fracturing in formations

competitive rates of return and netbacks on

that were previously untested for this

oil and natural gas production.

completion technology.

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.

Angle Energy inc

2010 Annual Report

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4

Angle Energy inc

2010 Annual Report

Where we go from here. . .

We’re excited about 2011 and beyond.

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-overyear and exiting 2011 at greater than 2,000 bbls of light oil per day. All told, Angle aims to drive organically to nearly 16,000 boe per day exiting 2011, 40 percent of it light oil and NGLs.

Angle Energy inc

2010 Annual Report

5

Selected Highlights Years Ended December 31

2010

2009

% Change

Financial ($000s, except per share data)

121,468 62,003 0.98 0.96 53,566 (5,098) (0.08) (0.08) 355,071 558,969 152,378 343,167

79,998 40,154 0.92 0.90 27,843 (3,032) (0.07) (0.07) 64,575 246,465 (38,255) 212,201

52 54 7 7 92 68 14 14 450 127 498 62

71,969 63,224 64,481

54,481 43,748 44,533

32 45 45

34,248 2,892 643

26,334 2,995 144

30 (3) 347

Combined average (boe/d) Average wellhead prices (1) Natural gas ($/mcf) NGLs ($/bbl) Light crude oil ($/bbl)

9,243

7,528

23

4.47 45.42 75.39

4.06 34.46 61.74

10 32 22

Total oil equivalent ($/boe) Netbacks ($/boe) Operating (5) Funds from operations (2) Reserves (December 31, 2010 evaluation) Proved (mboe) Proved plus probable (mboe) Total net present value – proved plus probable (10% discount) ($000s) Gross (net) wells drilled (#) Natural gas Oil Dry and abandoned Total Average working interest (%)

36.00

29.11

24

22.14 18.38

17.03 14.63

30 26

31,900 59,696

12,309 20,033

159 198

749,296

276,847

171

19 (17.2) 18 (15.6) 3 (1.7)

40 (34.5)

86

9 (7.9) – (–) 4 (4.0) 13 (11.9) 92

111 (118) 100 (100) (25) (-58) 208 (190) (6)

Commodity revenues (1) Funds from operations (2) Per share – basic Per share – diluted Cash flow from operating activities Net loss Per share – basic Per share – diluted Capital expenditures (3) Total assets Net debt (working capital) (4) Shareholders’ equity

Common Share Data Shares outstanding (000s) At end of year Weighted average – basic Weighted average – diluted

Operating Sales Natural gas (mcf/d) NGLs (bbls/d) Light crude oil (bbls/d)

(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.

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Angle Energy inc

2010 Annual Report

7% Light Crude Oil

31% NGLs

62% Natural Gas

06 1,281

07

08

09

10

3,334 6,586 7,528 9,243 Light Crude Oil

NGLs

Production Mix

Average Daily Production

Percentages at year-end 2010

(boe/d)

Natural Gas

5% Light Crude Oil

63% Natural Gas

32% NGLs

06

07

08

09

10

12.4

13.6

15.9

20.0

59.7

Light Crude Oil

NGLs

Proved Plus Probable Reserves Mix

Proved Plus Probable Reserves

Percentages at year-end 2010

(mmboe at year-end)

Angle Energy inc

Natural Gas

2010 Annual Report

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Management’s Q & A With Heather Christie-Burns and D. Gregg Fischbuch Angle’s Strategy and Evolution 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 Heather Christie-Burns President & Chief Operating Officer

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

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Angle Energy inc

2010 Annual Report

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 LETTER

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.

And lastly the transition from very gas-focused to a combination of light oil and liquids-rich gas?

Christie-Burns: First, Angle has always had high liquids content in its vertically drilled gas plays, so no strategic shift there was required.

Throughout our years of operation, over half of our revenue has come from our NGLs production. As for the light oil pursuit, in drilling our previous targets with vertical wells we’ve found a series of additional formations that historically yielded light oil. But these finds weren’t very productive as vertical wells. We were finding resources, not reserves.

The new technology, combined with the huge differential between gas and oil prices, and Alberta’s royalty drilling incentives, opened a path to making money drilling these light oil resources. We closely watched the Cardium light oil play’s evolution in Alberta, and in 2010 advanced our understanding of that play as it relates to our asset base. Our next oil play became the Viking, which is present in thick deposits in our original Harmattan core area. In 2011, we’re unlocking the components of all-in per well cost, development pace and recovery factors.

Now, we see an opportunity to further strengthen our liquids netback, with these light oil plays generating a netback of about $65 per boe, compared to our 2010 operating netback of approximately $22 per boe.

That will lift Angle’s corporate netback, cash flow and overall valuation.

Angle Energy inc

2010 Annual Report

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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-inplace 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

A

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.

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Angle Energy inc

2010 Annual Report

How are you demonstrating that Angle specifically can make money in this Basin?

Christie-Burns: These new plays will yield a variety of individual well results but will generate a rate of return over a number of wells on a project basis.

You need to do your geological homework, you need to drill your pilot wells and find the best areas for development, before you know what will happen.

Our investors understand this careful, phased, project-based approach to our Cardium and Viking plays. Also, corporate production growth has to be viewed differently when variable commodities are being produced – production per share and cash flow per share are not necessarily identical.

So, we are focusing on increasing the value of our barrels by growing our light oil opportunities in lockstep with the most liquids-rich gas opportunities.

Ultimately, a business is about cash flow and sustainable returns.

So what “is” Angle today?

Fischbuch: Until 2009 we were seen as a small entity drilling successful vertical wells with low costs. Today we’re bigger, but we’re still a low-cost operator and we continue to be a very good driller. Of our 13,500 boe per day in production exiting 2010, our drilling specifically resulted in over 10,000 boe per day. In our 2010 acquisitions that added 3,200 boe per day, we targeted assets with drilling opportunities – we weren’t “buying production”. Today’s Angle is a company that in four years has grown through the junior stages into the mid-cap and then intermediate class in a controlled manner using an exploration-based growth strategy. Angle today has multiple oil and natural gas plays to drive further organic growth.

Angle Energy inc

2010 Annual Report

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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.

2010 Results

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.

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Angle Energy inc

2010 Annual Report

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.

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.

Angle Energy inc

2010 Annual Report

13

How were your financial results, and what do they tell us?

Christie-Burns: Our financial results show that we generated a positive rate of return in 2010, even in a transitional year, with year-over-year growth in our recycle ratio. We understand that we’re a business, and we want to achieve the best rate of return. Our goals in 2010 were to drill across our asset base, understand the variability, and then learn how to optimize the drilling, completions, tie-ins and production parameters for larger-scale development drilling. Our cost structure per well was high in 2010, due to this phase of research experimentation, and we believe we can bring it down in 2011. For example, in drilling to get the best reservoir data to set up future development, a new location can be miles from the nearest well site and gathering line. When you develop, you lower per-well costs through measures like drilling multiple wells from common pads, which is the focus in 2011. We expect to further strengthen our recycle ratio in 2011, by targeting higher netbacks per boe and being more efficient in our development programs.

What are the strategic and resource benefits of the new Edson play area?

Fischbuch: This is a true multi-zone, liquids-rich natural gas area with large resource-in-place and running room for multiple drilling seasons.

What we call “Old Angle� had only two areas, Harmattan from the start, and Ferrier since 2007. We needed portfolio diversification, to broaden our development opportunities, but also on an infrastructure basis, to become less dependent on a single key gas plant. The Alberta Deep Basin, of which Edson is a part, is an extension of the technical expertise we have as a team. That positioned us to go in and accelerate an underexploited area that the company we acquired, Stonefire, had demonstrated offers a highly favourable cost structure even on a vertical drilling basis. Our initial horizontal results in the Wilrich and Notikewin formations at Edson have been good.

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Angle Energy inc

2010 Annual Report

Outlook and 2011 Plans

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.

Angle Energy inc

2010 Annual Report

15

Are Angle’s plans seriously exposed to a drop in natural gas prices?

Are there things that offset or limit the price risks?

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.

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.

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,

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Angle Energy inc

2010 Annual Report

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.

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

Angle Energy inc

2010 Annual Report

17

Exploration and Operations Review A Full-Cycle Value Approach After five years of steady, drillbit-driven growth as a junior

Horizontal drilling was key to the

exploration and production company, Angle entered 2010 with a

2010 program. The greater reservoir

transformative agenda:

contact area created by a horizontal

•G rowing to a mid-cap and then an intermediate producer by

wellbore that is hydraulically fractured

achieving volumes substantially greater than 10,000 boe per day; •E stablishing 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

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

• Proving up, delineating and de-risking several key new plays.

wells. It is far less restrictive than vertical drilling, which must focus on the best parts of a reservoir. This technology shift thereby transforms

Edson Deep Basin liquids-rich gas

much more resource-in-place into producing reserves.

Angle delivered success across the

EDMONTON

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

Angle Core Area Ferrier Cardium light oil

individual wells coming on-stream at up to 1,900 boe per day. The Cardium and Viking light oil programs

Lone Pine Creek Wabamun gas

established high-value “sweet spots”, positioning Angle to drive profitable growth in light oil volumes. Proved and proved plus probable reserves

Harmattan Viking light oil Mannville liquids-rich gas

Alberta

Edmonton

CALGARY

Calgary

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Angle Energy inc

2010 Annual Report

tripled year-over-year, lengthening the Company’s reserve-life-index to 12.1 years based on exit production.

Building full-cycle corporate value Project Life

Value build begins

Land/seismic acquisition Appraisal drilling Understanding the reservoir Infrastructure

Exploitation drilling Optimizing all aspects Production growth Increasing well inventory

Reaping rewards

operations

n Increas ing productio Increasing cash ow

Moving the needle 600

500

400

300

200

100

0

05

06

07

08

Shareholders’ equity ($mm)

09

10

Total assets ($mm)

Angle Energy inc

2010 Annual Report

19

Land – a Key Exploration Driver Running room keeps us drilling

An oil or natural gas lease is traditionally

running room in its own right. At Harmattan,

considered “developed” when a section

for example, Angle is developing a Mannville

(640 acres) of land has reserves assigned to it

gas condensate pool, is growing its Viking

from one successful well. Historically, producers

oil development, and is establishing Cardium

were seen as requiring vast undeveloped land

potential – all on a common land base. In some

areas to sustain their growth. Today’s approach

cases, the Company can drill horizontal natural

of developing successive play types in stacked

gas and oil wells into separate plays from

reservoirs underlying a common land area

the same drilling pad – often on land already

renders this traditional view largely irrelevant.

classified as “developed”.

It matters far less how much “undeveloped”

An asset portfolio with a concentrated

land a producer has, than how much land is

and highly prospective land base offers

prospective for a particular targeted play.

advantages over sprawling amounts of raw

Virtually all of Angle’s land holdings are

land. The producer can lever existing facility

prospective for at least two – and often three

infrastructure, improving capital and operating

or more – separate productive oil or natural

efficiencies. The historical vertical well control

gas-bearing zones, which lie stacked or

usually offered on developed lands provides

overlapping beneath the same land area.

critical data in geological resource assessments

The Deep Basin asset at Edson, for example,

for new plays, and in planning horizontal

holds at least seven productive reservoirs.

well locations.

Angle refers to this concept as “urban density”

Angle entered 2011 with a high-quality land

vs. “urban sprawl” – each layer is a formation

base prospective for numerous plays and

with many sections of prospectivity, creating

offering years of running-room with an inventory of approximately 850 well

Land Picture

175,619

net undeveloped acres

248,069 total net acres

20 Angle Energy inc

2010 Annual Report

locations – and which continues to grow.

2011 Growth Plan Angle entered 2011 with a diversified,

spending is focused mainly on lower-risk

high-working-interest asset base of four core

development drilling. Angle foresees driving

areas – all in the high-quality “Golden Spine”

major production growth at lower incremental

of west-central Alberta – with seven

cost, with better per-well results, generating

large-scale light oil and natural gas play types.

higher capital and operating efficiencies.

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.

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

Last year, Angle largely concluded the “first

further growth in the corporate average

half” of the exploration and development

netback per boe of production. The Company

cycle at several of its key plays. This included

is targeting an exit production rate of

substantial investment in land, facilities and

15,000-16,000 boe per day, of which

higher-risk delineation drilling, which helped

approximately 40 percent will be light oil

to de-risk the most promising growth plays.

and NGLs. Angle’s current well inventory

In 2011 and beyond, Angle is moving into the

offers visible organic drilling growth to

“second half” of the cycle, in which capital

greater than 20,000 boe per day.

Angle Energy inc

2010 Annual Report

21

More Oil Shifting to a higher-value commodity Angle’s high-liquids natural gas-producing

early-stage delineation programs tested

properties create an ideal platform to

reservoir variability, identified sweet spots

add volumes of higher-netback light oil at

and generated data needed to refine the

competitive capital efficiency. The Company’s

numerous parameters in the drilling and

extensive land base and control of area

completions processes. Metrics recorded for

infrastructure reduce the full-cycle cost to

2010 represented full-cycle exploration costs

develop a new project. Existing landholdings

– including land capture, new facilities and

can be complemented by aggressive,

higher-cost exploration wells – but only

lower-cost land capture early in the

first-half-cycle value generation.

exploration cycle.

Beginning this year, production and reserve

In addition, Angle levered a key technical

additions will mainly incur second-half-cycle

advantage in rapidly creating its successful

drilling and completion costs while generating

Cardium and Viking light oil plays. Years of

full-cycle value. This should drive production

vertical drilling targeting liquids-rich natural

and reserves growth at low incremental cost,

gas generated an extensive dataset of well

resulting in increased netbacks and cash flow

control indicating oil-bearing zones. These

per share and per boe, reduced F&D costs per

oil-bearing horizons would not have been

boe and a higher recycle ratio – better metrics

economic to complete as vertical producers –

across the board.

but the well logs pointed to vast oil-in-place potentially accessible through horizontal wells completed with multi-stage fracturing.

In 2011 Angle is continuing to delineate its Viking and Cardium oil plays, while pushing them outward into new areas, such as

Angle’s successful Viking and Cardium

establishing Cardium potential at Harmattan

horizontal wells drilled at Harmattan and

and Edson. Half of this year’s capital budget

Ferrier in 2010 (please see following

of $150 million is allocated to Viking and

write-ups) added a combined 1,000 bbls per

Cardium oil development. This will fund the

day of stabilized light oil production exiting

drilling of a planned 15 net horizontal wells.

the year. This new production is generating

The Company is aiming to double light oil

netbacks as high as $65 per bbl, lifting the

volumes – entirely through the drillbit – to

Company-wide average netback for 2010.

greater than 2,000 bbls per day by

The 2010 program positioned Angle for major

year-end 2011.

light oil production growth and improved per well results in 2011 and beyond. The

22 Angle Energy inc

2010 Annual Report

Running room: Angle’s undeveloped land by play

Cardium – 195 net sections, 97% undeveloped

Viking – 227 net sections, 90% undeveloped Notikewin Falher/Wilrich Glauconitic/Bluesky Ostracod Ellerslie Fernie

300 net sections, 83% undeveloped

Rock Creek – 250 net sections, 89% undeveloped

Wabamun – 204 net sections, 96% undeveloped

Angle Energy inc

2010 Annual Report

23

West Central Alberta – Cardium Light Oil Angle’s strong presence from its pursuit of

sixth-best Cardium well for the entire

multi-zone gas opportunities at Ferrier since

industry through year-end 2010. The latter

2006 created the initial dataset to develop

three wells outperformed the first three,

a Cardium light oil play around the Ferrier

demonstrating the need to drill multi-well

Cardium pool. This new opportunity became

batches when testing a new play. This first

of interest after the Company assessed the

round added a combined 600 bbls per day of

results from the industry’s early exploitation

premium-priced light oil to Angle’s production

in the “halo” around the historical Pembina

base exiting 2010.

Cardium pool.

With the best reservoir areas established at

The Cardium is a conventional reservoir to

Ferrier, Angle can proceed with development

which unconventional technology is being

to add high-netback production and cash

applied in untapped pool areas not amenable

flow at declining risk. Repetition and further

to historical techniques. The Cardium

technical work such as micro-seismic

sandstone around Ferrier lies at 2,200 metres

monitoring will optimize key well parameters –

versus the typical 1,300-1,800 metres. This

horizontal leg orientation, fracturing fluids

meant Angle was pioneering a new variant on

and the density and tonnage per stage of

the play. It’s an example both of Angle’s drive

hydraulic fracture treatments.

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.

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

Following technical work to establish Cardium

the Company is also developing Viking oil

prospectivity on Angle’s lands at Ferrier, in

and Mannville liquids-rich gas (see following

January 2010 the Company began drilling

pages).

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.

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

As expected, the reservoir proved variable.

play generating a project-wide recycle ratio

Angle’s final Cardium well of the year tested

of 3.6 times.

at 1,200 boe per day after eight days – the

24 Angle Energy inc

2010 Annual Report

Edson

Ferrier Lone Pine Creek

Harmattan

Angle Land – Cardium Rights

Cardium Production

Value Drivers

2010 Area Summary

•L evering existing land base and operating presence

Land (net acres)

• Premium-priced light oil

Proved plus probable reserves (mmboe)

119,935

Avg. land working interest (%)

82 3.71

• Large oil-in-place per acre of reservoir •H igh initial productivity and moderate per-well costs • Strong returns on a multi-well project basis

Angle Energy inc

2010 Annual Report

25

Harmattan – Viking Light Oil Alberta’s Viking sandstone is being revitalized

The first batch of wells came on-stream at

after more than a half-century history as

150-590 boe per day each and included the

a conventional light oil and natural gas-

most prolific Viking horizontal oil well drilled

producing reservoir. The Viking’s new iteration

in Alberta to date (based on public data). The

is earlier-stage than the Cardium, and Angle

program generated combined production of

is an industry pioneer. This play levers Angle’s

800 boe per day (including some natural gas

solid presence at Harmattan. The Company’s

volumes) exiting 2010 after six months on

founding property is again demonstrating

production for the earliest well. Last year an

the remarkable geological variety that keeps

independent third-party evaluation estimated

generating new possibilities.

that Angle’s Viking lands hold discovered

In 2009 Angle recognized opportunity to

petroleum initially-in-place of 471 million

create new value by drilling horizontal multistage-fractured wells into a reservoir that frequently showed up on the area’s vertical well logs. The relatively low-permeability

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

or “tighter” Viking sands would not be

has had reserves attributed.

productive or economic as vertical wells. The

Angle’s oil Viking wells are generating a

dramatic increase in wellbore contact created

netback of approximately $65 per bbl at an

by horizontal wells with multiple fractures was

Alberta light oil par price of $85 per bbl (the

the key to unlocking the up to 20 metres of

reservoir also generates some natural gas

net pay offered by this reservoir.

and NGLs). Initial capital efficiencies have

Angle’s test phase involved pilot program

averaged $33,000 per daily flowing boe

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

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

to build its Viking play around Harmattan to

and beyond.

60 net prospective sections at high working

Results to date suggest Angle’s Viking play

interest, before reports of drilling success

could well outperform the Cardium. In 2011,

made these lands too expensive. The property

Angle plans to drill 12 horizontal Viking wells

deals also furnished vertical well control to

and 15 in 2012, further delineating the play and

help map the prospective area.

substantiating the inventory while initiating

26 Angle Energy inc

2010 Annual Report

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.

VIKING OIL DEVELOPMENT FAIRWAY

0

3

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miles Angle Land – Viking Rights Viking Oil Producers

Angle – Viking Producers Angle – 2011 Locations

Value Drivers

2010 Area Summary

•E arly entry, large land base, high average working interest

Land (net acres)

•H igh-netback light oil – ~$65 per bbl on pure oil wells

Proved plus probable reserves (mmboe)

52,254

Avg. land working interest (%)

97 1.81

•M assive reserve upside on large oil-in-place resource – minimal reserves booked to date •M ulti-year running room on 190-well inventory of horizontal locations

Angle Energy inc

2010 Annual Report

27

Natural Gas Making it economic through NGLs content and operating efficiencies Western Canada’s higher-quality natural

inception, liquids content has consistently

gas reservoirs continue to be profitable at

generated more than half of corporate

current commodity prices if managed in the

revenue and has lifted the average corporate

right hands. At multiple plays over successive

netback per boe.

years, Angle has generated strong natural gas

Company-wide average NGLs content of

economics through:

Angle’s production in 2010 was 84 bbls per

• Top-quartile capital efficiencies. For the year

mmcf of sales gas. At Harmattan, the average

ended December 31, 2010, the Company’s

NGLs content averages 160 bbls per mmcf

all-in costs were only $14.30 per proved plus

of sales gas – five to 10 times the NGLs

probable boe of reserves added;

concentration of competing reservoirs such as the Deep Basin, widely touted as

• Low operating and all-in cash costs to

liquids-rich. In 2010 Angle’s NGLs content

generate reasonable production netbacks;

added revenue of $1.81 to $4.80 per mcf –

• Consistent focus on pools rich in natural gas

more than doubling the Company’s equivalent

liquids.

natural gas sales price to over $7.50 per mcf.

Liquids are valuable commodities

Angle’s NGLs production totalled 2,892 bbls

benchmarked to crude oil (see chart,

per day in 2010, generating sales revenue of

opposite), levering the profitability of natural

$45.42 per bbl.

gas operations. Today’s strong crude oil pricing gives NGLs, on average, double the value per boe of natural gas. Since Angle’s

The economics of Angle’s liquids–rich gas plays Combined Value $6.14/mcf

Combined Value $6.52/mcf

$4.34

$3.71

$1.81

$2.81

Edson Wilrich

Lone Pine Wabamun Sales dry gas value ($/mcf)

28 Angle Energy inc

Combined Value $7.79/mcf

2010 Annual Report

$2.99 $4.80

Harmattan Mannville Liquids-equivalent price ($/mcf)

Natural gas liquids: The upside of Angle’s gas production Methane (dry gas)

Market

Natural Gas Liquids (NGLs)

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

Fourth Quarter 2010 NGLs production

NGLs yield

NGLs revenue

3,495 bbls/d

82 bbls/mmcf

$48.75/bbl

Succeeding in liquids-rich natural gas

Angle is installing a second, 100 percent-

operations requires control of or secure

owned gas processing facility to increase

access to key facilities, both to bring new

out-take capacity by 10 mmcf per day, giving

production on-stream quickly and to

Angle integrated control of gathering systems,

transform raw gas into separate saleable

compression and processing.

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,

Fundamentally, making money from natural gas in western Canada requires the technical expertise to identify high-potential new plays, the exploration ability to locate and delineate new pool areas, and the operating discipline to generate repeatable successes at declining per-well costs and continually improving metrics. At Harmattan, Ferrier, Lone Pine Creek and Edson, Angle has proved its ability to succeed on all counts.

Angle Energy inc

2010 Annual Report

29

Harmattan – Mannville Liquids-Rich Gas Angle’s Harmattan asset illustrates the

overall capital and operating metrics through

profitability found in high-quality, liquids-rich

horizontal drilling. Angle began drilling

reservoirs. Harmattan is where Angle began

Mannville horizontal wells in the second

operations in 2005 through a farm-in to drill

half of 2010.

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.

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

Angle’s Mannville pools offer the highest

over its first two months, with 44 percent of

liquids content in western Canada – up to

this volume being natural gas and 66 percent

195 bbls per mmcf of sales gas, spanning

NGLs. A third horizontal well, similar in length

the NGLs spectrum from ethane (C2) to

and completion to the second, finished testing

condensate (C5+). The extraordinary liquids

in late February at approximately 1,500 boe

content is a function of the reservoir’s

per day. These results are exceeding the

complex geological history, which may

Company’s expectations.

have included successive hydrocarboncharging events.

With these tremendous initial results, Angle intends to continue exploitation of the known

Production at Harmattan entering 2010 had

pool area with horizontal wells. Two further

grown to 4,900 boe per day from 42 vertical

horizontal Mannville wells were underway

producers. Production is taken to a third-party

in the first quarter of 2011, with four more

facility with “deep cut” capacity that extracts

planned this year and an additional 30

the full array of NGLs. This yields an average

by 2014. Angle’s goals are to lever all the

netback of up to $27.00 per boe – very high

benefits of post-exploration, second-half cycle

for natural gas production.

economics: high-rate production additions

Entering 2010 Angle’s objective was to

at low risk, increased recovery of in-place

establish the feasibility of increasing per-well productivity, resource recovery and

30 Angle Energy inc

2010 Annual Report

resources and improved metrics across the board.

Pengrowth Plant

AltaGas Plant

Pengrowth Compressor

9-5 Compressor

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miles Angle Land – Mannville Rights

Angle – Mannville Producers

Angle – 2011 Locations

Value Drivers

2010 Area Summary

•E xtremely high liquids content generates excellent netbacks

Land (net acres)

•H igh-rate wells yield strong capital and operating efficiencies

Proved plus probable reserves (mmboe)

40,385

Avg. land working interest (%)

95 19.89

•R eserve and production growth through multi-well horizontal exploitation

Angle Energy inc

2010 Annual Report

31

Deep Basin/Edson – Liquids-Rich Multi-Zone Natural Gas Angle’s new Edson core area in the

the previous two years area competitors

liquids-rich Alberta Deep Basin is a gem

had achieved exciting results in the Bluesky,

of an asset that could hold the greatest

Notikewin, Wilrich, Cadomin, Cardium, Rock

long-term value in the Company’s portfolio.

Creek and Fernie formations, all part of the

The Deep Basin is highly attractive for its

Cretaceous Deep Basin column.

multiple productive zones, large resourcein-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.

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

The new core area was created in January

3.5 mmcf per day plus NGLs, but were not

2010 through the $75 million acquisition of

considered representative of the area’s

Stonefire Energy Corp. Stonefire had built

true potential. Angle’s experimental use of

up a high-quality, concentrated play north of

propane-based fracturing, which works well

Edson through vertical drilling. In June 2010

in other areas, may not have been optimal

Angle followed up with a $115 million

for the Wilrich. This year the Company will

property acquisition from Compton Petroleum

use slickwater fractures with heavier sand

Corp. All told, Angle acquired 115 net sections

tonnage, which have yielded great results

of high-working-interest lands plus control

for area competitors.

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 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

Angle was drilling new wells within two weeks

reflect the new way of thinking about

of the Stonefire deal. The objectives for 2010

undeveloped land (please see page 20).

were to maintain field-wide production while

A given land section may have modest

beginning to test key reservoirs through

vertical production and reserve assignments

horizontal, multi-stage-fractured wells. Over

– making it classified as “developed” – yet

32 Angle Energy inc

2010 Annual Report

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.

0

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WILRICH/NOTIKEWIN FAIRWAY

miles Angle Land - All Rights Angle Operated Facilities

Angle 2010 Gas Wells Angle 2011 Locations

Value Drivers

2010 Area Summary

• High gas-in-place, with liquids

Target zones

• Huge inventory of repeatable opportunities – over 300 locations entering 2011 • Low operating costs and long-life production

Wilrich Bluesky Fernie

Land (net acres)

74,566

Avg. land working interest (%) Proved plus probable reserves (mmboe)

71 17.04

• Long-term production growth

Angle Energy inc

2010 Annual Report

33

Lone Pine Creek – High-Rate Wabamun Gas and Liquids Angle’s creation of a new Wabamun play at

complete. As expected for a conventional

Lone Pine Creek exemplifies the Company’s

reservoir, the program revealed considerable

technically-driven method. The Company’s

variability – and found two prolific sweet

technical team had long believed that central

spots. The two northerly wells came

Alberta still held overlooked Wabamun natural

on-stream at initial rates of approximately

gas pools. Lying at an average depth of 2,350

1.5 mmcf per day each. Two further wells to

metres, the Wabamun carbonate is one of the

the south came on-stream at initial rates of

most prolific gas reservoirs ever established in

2.5-4.5 mmcf per day each.

the province, having driven much of Alberta’s natural gas production in the 1960s, but was considered at a dead end.

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

Analysis of certain well behaviour led Angle’s

mmcf of sales gas. The new production was

team to conclude there was an overlooked

tied-in to an underutilized gas plant via the

pool area in a broad swath between two aging

Company’s new, 13-km, 8” diameter pipeline.

Wabamun producing areas. The pool just to

Following extensive community consultation

the south had generated 500 bcf over several

in a populated area with landholder

decades. One well to the north had delivered

sensitivities, the new pipeline entered service

30 bcf over 30 years – yet was still producing

in September.

1 mmcf per day. Another well showed near-original reservoir pressure.

Lone Pine Creek’s very high-rate, liquids-rich wells generate an estimated 5.3

This evidence prompted several years of work

times recycle ratio. Exiting 2010 the new play

spent on low-key land assembly in an area of

was producing a combined 4 mmcf of sales

mixed Crown and freehold rights plus existing

gas per day plus liquids of approximately 200

competitor leases. The new property, dubbed

bbls per day, with production restricted due

Lone Pine Creek, was ready to test by 2009.

to compression limitations. Development of

Angle drilled one vertical exploratory well

the play’s two current sweet spots will include

plus the Company’s first-ever horizontal well,

up to 17 high-working-interest wells over the

both of which were tied-in and brought on-

next several years, beginning with five wells

production in 2009.

planned for 2011. Angle is working with a

In 2010 Angle accelerated the new reservoir’s

third-party processor to free up additional

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

34 Angle Energy inc

2010 Annual Report

capacity to process production from the wells drilled in this area.

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WABAMUN GAS

Pengrowth Plant

Apache Plant

Pengrowth Compressor

Angle Land – Wabamun Rights Wabamun Producers Pipeline

Angle – Wabamun Producers Angle – 2011 Locations

Value Drivers

2010 Area Summary

•H igh-rate wells – target IP 5-8 mmcf per day plus liquids

Land (net acres) Avg. land working interest (%)

100

•C oncentrated land base at 100% WI

Proved plus probable reserves (mmboe)

7.78

24,566

•L arge reserves per well – target 5 bcf • > Five times recycle ratio

Angle Energy inc

2010 Annual Report

35

Operations Statistical Review 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

Total Land (000s net acres)

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

06

07

08

09

10

area, targeting the Viking oil play via Crown land sales. The Company recognized

47

71

98

137

248

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.

36 Angle Energy inc

2010 Annual Report

Undeveloped

Developed

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

Gross Net (mmcf)

(mmcf)

Light Crude Oil

Gross Net (mbbls)

Gross Net

Combined Total Gross Net

(mbbls)

(mbbls)

(mbbls)

(mboe)

(mboe)

4,114

1,257

1,029

19,367

15,193

Proved Developed producing

72,270

60,303

6,065

4,083

3,589

224

160

54

40

958

798

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

Developed non-producing Undeveloped

Note: Table may not be additive due to rounding.

Angle Energy inc

2010 Annual Report

37

Net Present Values of Future Net Revenue

The net present values of future net revenue of the Company’s reserves, as at December 31, 2010, at various discount rates on a before-tax basis are outlined below: December 31, 2010

Before Income Taxes Discounted At

(000s)

0%

5%

10%

15%

20%

498,260

$ 392,676

$ 326,646

$ 281,797

$ 249,408

Proved $

Developed 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

$ 1,433,948

$ 994,465

$ 749,296

$ 595,244

$ 490,337

Developed non-producing

Total proved plus probable Note: Table may not be additive due to rounding.

The Company’s net present value of proved plus probable reserves, discounted at 10 percent before tax, was $749.3 million at December 31, 2010, up by 171 percent from $276.8 million at December 31, 2009 despite lower forecast natural gas prices which negatively affected the value of reserves at period-end 2010.

Proved Plus Probable Proved Plus Probable Net Present ValuesNet of Future Present Values of Future Reserves Reserves by Commodity Net Revenue (BIT)Net (10% Revenue DCF) ($mm) (BIT) (10% DCF) ($mm)by Commodity (Year-End 2010) (mboe) (Year-End 2010) (mboe)

19,467 NGLs

06

07

08

$146

$223

$273

Proved

38 Angle Energy inc

09 06

10 07

$277 $146 $749 $223

19,467 NGLs

08

09

10

$273

$277

$749

ProbableProved

2010 Annual Report

Probable

2,709 Light Crude Oil

2,709 Light Crude Oil

37,520 Natural Gas

37,520 Natural Gas

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

Proved

January 1, 2010

Probable

NGLs Proved Plus Probable

Proved

Probable

Proved Plus Probable

(mmcf)

(mmcf)

(mmcf)

(mbbls)

(mbbls)

(mbbls)

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

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

Proved

Probable

Improved recovery

Light Crude Oil

Total

Proved

Probable

Proved Plus Probable

(mbbls)

(mbbls)

(mbbls)

(mboe)

(mboe)

(mboe)

408

261

669

12,309

7,724

20,033

January 1, 2010

Proved Plus Probable

Technical revisions

(93)

(88)

(181)

1,027

(1,561)

(534)

Drilling extensions

906

578

1,484

7,568

6,795

14,363

88

22

110

5,776

7,774

13,550

–

–

–

18

2

20

Acquisitions

491

371

862

8,577

7,062

15,639

Production

(235)

–

(235)

(3,375)

–

(3,375)

1,565

1,144

2,709

31,900

27,796

59,696

Infill drilling Improved recovery

December 31, 2010 Note: Table may not be additive due to rounding.

Angle Energy inc

2010 Annual Report

39

Summary of Pricing and Inflation Rate Assumptions

The economic parameters, as determined by GLJ, assumed in preparing the forecast prices and costs reserve report are outlined below: Natural Gas Price Forecast – Effective January 1, 2011

AECO

NIT Spot Then Current

Year

Alberta Plant Gate

Spot

Constant 2011 $

Then 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

+2.0%/yr

5.82

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

2021+

Light Crude Oil and NGL Price Forecast – Effective January 1, 2011 Nymex WTI Near Month Bank of Futures Contract Canada

Light Crude Oil at Average

Cushing Oklahoma Noon Exchange Constant Then Rate 2011 $ Current

Year Inflation

(%)

(US$/Cdn$)

(US$/bbl)

(US$/bbl)

Light Sweet

Crude Oil Alberta NGLs (40° API, 0.3%S) (Then Current Dollars) at Edmonton

Edmonton Then Spec Edmonton Edmonton Pentanes Current Ethane Propane Butane Plus (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

40 Angle Energy inc

2010 Annual Report

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 Proved

Plus Expected

Proved Probable 2011

Reserves Reserves Production

Proved Plus Probable Expected 2011 RLI Production Proved

Natural gas (mmcf) NGLs (mbbls)

(years)

119,691

225,118

19,907

23,249

6.01

9.68

10,386

19,467

1,741

2,075

5.97

9.38

1,565

2,709

357

434

4.38

6.24

31,900

59,696

5,416

6,384

5.89

9.35

Light crude oil (mbbls) Total (mboe)

(years)

RLI Proved Plus Probable

Reserve Replacement Ratio Year ended December 31, 2010

Proved

Proved Plus Probable

Light Crude Natural Oil Gas NGLs Combined

Light Crude Oil

Natural 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

Reserve-Life-Index Year ended December 31, 2010 Proved (years)

Proved Plus Probable (years)

06

07

08

09

10

06

07

08

09

10

4.7

4.3

4.0

5.1

5.9

7.8

5.5

5.0

7.3

9.4

Undeveloped

Developed

Undeveloped

Angle Energy inc

Developed

2010 Annual Report

41

Finding and Development Costs

The following table provides detailed calculations related to finding and development (F&D) and finding, development and acquisition (FD&A) costs and recycle ratios for 2010 and 2009. These have been calculated in accordance with NI 51-101, Part 5.

Years Ended December 31

(000s)

Three-Year

2010

2009

2008

($)

($)

($)

($)

303,242

184,675

39,140

79,427

Capital Expenditures Exploration and development 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

–

47,768

47,768

–

–

108,550

108,550

–

–

(mboe)

(mboe)

(mboe)

(mboe)

2,269

Proved – change in future capital (acquisitions) Proved plus probable – change in future capital (acquisitions)

Reserve Additions

Proved Exploration and development

12,383

10,326

(212)

Acquisitions

10,324

9,265

1,059

–

Production

8,532

3,374

2,748

2,410

31,239

22,965

3,595

4,679

Total added reserves

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

54,590

43,037

6,846

4,707

($/boe)

($/boe)

($/boe)

($/boe)

Total added reserves

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

13.50

14.67

14.23

14.30

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.

42 Angle Energy inc

2010 Annual Report

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: 2010

2009

$ 749,296

$ 276,847

80,801

20,335

(152,378)

38,255

8,000

8,000

December 31 (000s, except per share data)

Present value of petroleum and natural gas reserves (1) Net undeveloped land (2) Bank debt and working capital deficiency Seismic data (3)

33,036

18,152

$ 718,755

$ 361,589

Proceeds from stock options (4)

Net asset value

77,810

Diluted shares outstanding (#) (5) Net asset value per share

$

9.24

58,862 $

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.

Net Asset Value ($/Share)

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.

06

07

08

$4.56 $5.84 $7.07

Angle Energy inc

09

10

$6.14

$9.24

2010 Annual Report

43

Financial Management Funding Our Growth Like nearly all oil and natural gas producers,

During this period we have raised equity at

Angle requires large investments of capital

share prices ranging from $0.60 to a high of

beyond self-generated cash flow to fund growth

$10.05 for flow-through common shares issued

in its financial and operational measures.

in November 2010. Angle also has a revolving

It is essential that we raise this required

committed credit facility with three Canadian

capital on the most favourable terms and at

chartered banks with a borrowing base of

appropriate times, and focus it towards the best

$180 million, and in January 2011 raised an

development and/or acquisition opportunities to

additional $60 million in convertible unsecured

achieve profitable growth for our shareholders.

subordinated debentures, for total debt capacity

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

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.

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

44 Angle Energy inc

2010 Annual Report

Heather Post Controller

On a forward basis, we must project our capital

times. We may increase our position in relation

needs through vigorous budget modelling and

to changes in the commodity markets and our

comparison to actual results for all aspects

debt ratios.

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

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.

its oil and natural gas production hedged at all

Angle Energy inc

2010 Annual Report

45

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (MD&A) reports on the financial condition and the results of operations of Angle Energy Inc. (“Angle” or the “Company”) for the three months and years ended December 31, 2010 and 2009 and should be read in conjunction with the audited consolidated financial statements and accompanying notes. All financial measures are expressed in Canadian dollars unless otherwise indicated. This commentary is based on the information available as at and is dated March 14, 2011.

Angle is a growth-oriented, exploration-focused oil and natural producer, with a focus on achieving cost-effective reserves discovery and production in large, resource-in-place accumulations of liquids-rich natural gas and light oil. Angle prefers to drill in areas where it can complete multi-well projects at high working interest and operate the resulting production.

Additionally, to maintain control, such areas should also have available access to existing infrastructure to transport and process the commodities produced.

Prior to 2009, all of Angle’s reserves had been added through drilling as the Company had not previously completed any material property or corporate acquisitions. In 2009, Angle completed its first property acquisition in its existing Ferrier core area. In 2010, Angle built a new core area in Edson through its first corporate acquisition and a subsequent material property acquisition. Additionally, in 2010 the Company made the transition from vertical to horizontal drilling.

Angle currently has four core operating areas: Harmattan, Ferrier, Edson and Lone Pine Creek, all in Alberta. Angle is focusing on five main “plays” in these four core areas: Cardium light oil, Viking light oil, Mannville liquids-rich natural gas, Deep Basin liquids-rich multi-zone natural gas and Wabamun high-rate natural gas and liquids. Exit production in 2010 was 13,500 boe per day, consisting of approximately 60 percent natural gas, 30 percent natural gas liquids and 10 percent light oil.

The terms “2010” and “2009” are used throughout this document and refer to the years ended December 31, 2010 and 2009, respectively. The terms “fourth quarter of 2010” and “same period of 2009” or similar terms are used throughout this document and refer to the three-month periods ended December 31, 2010 and 2009, respectively.

46 Angle Energy inc

2010 Annual Report

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

$4.00/mcf

$4.24/mcf

6

$75.00/bbl

$78.36/bbl

4

9,600

9,243

(4)

13,500

13,500

0

2010 pricing (fourth quarter) Natural gas – AECO Crude oil – Edmonton par 2010 production (boe/d) Annual Exit 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 $187 million

$185 million

(1)

Wells drilled (gross/net)

Expenditures (excluding acquisitions)

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 MD&A

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.

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 2010

(000s)

$

Drilling

9,516

$

Years Ended December 31

2009

% Change

2010

2009

% Change

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

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)

Geological and geophysical

Capitalized G&A and other Total capital expenditures

48 Angle Energy inc

286 $ 30,470

2010 Annual Report

$

263

9

1,084

819

32

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.

Capital Expenditures ($000s) 2010

2009 $1,387 Head Office/ Capitalized G&A

$170,093 Acquisitions

$132,269 Drilling, Completions, Tie-ins

$22,451 Acquisitions

$13,780 Facilities $1,281 Geological

$36,261 Land

$1,229 Head Office/ Capitalized G&A $29,662 Drilling, Completions, Tie-ins

$4,812 Land $4,981 Facilities

$1,440 Geological

Total $355,071

Total $64,575

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.

Angle Energy inc

2010 Annual Report

49

Angle was very active at Crown land sales during 2010 in order to establish the Company in important new resource plays it is pursuing, in turn positioning

Net Undeveloped Land (000s acres)

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:

06

07

08

09

10

34.5

57.7

68.5

99.0

175.6

• On January 12, 2010, Angle acquired all of the issued and outstanding shares 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; • In June 2010, Angle acquired an additional working interest in several wells and a compression facility in the Ferrier area for cash consideration of $7.3 million; and • On June 30, 2010, Angle acquired certain interests in petroleum and natural gas properties in the Edson area for cash 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 December 31, 2010 Gross Net

Year Ended December 31, 2010 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 December 31, 2010 Gross Net

Year Ended December 31, 2010 Gross Net

1

0.2

11

Ferrier

1

1.0

11

8.0

Harmattan

4

4.0

11

11.0

Edson

8.5

Lone Pine Creek

–

–

7

7.0

Total

6

5.2

40

34.5

50 Angle Energy inc

2010 Annual Report

During the fourth quarter of 2010, Angle drilled 6 gross (5.2) net wells, all of which were successful. In Harmattan, Angle continued to de-risk the Viking oil play by drilling three horizontal wells in the formation and also drilled its first Mannville B horizontal gas well (all four wells were 100 percent working interest). Angle drilled one horizontal Cardium oil well in Ferrier at 100 percent working interest and participated in one non-operated horizontal Cardium oil well in Edson at 24 percent working interest.

For the year ended December 31, 2010, Angle drilled 40 gross (34.5 net) wells, of which 3 gross (1.7 net) wells were unsuccessful. Of the 40 wells, 34 were drilled horizontally, five were drilled directionally and one was drilled vertically. In the Edson area, seven of the 11 wells were operated (all at 100 percent working interest) and the remaining four wells were non-operated at an average working interest of 38.5 percent. In the Ferrier area, Angle operated 10 of the 11 wells at an average working interest of 79 percent and participated in one non-operated well at a 2 percent working interest. All drilling in the Harmattan area and the Lone Pine Creek area was operated at 100 percent working interest.

Financial and Operating Results of Oil and Natural Gas Activities Sales, Revenue and Prices

Three Months Ended December 31

2010

2009

42,786 3,495

Years Ended December 31

% Change

2010

2009

% Change

26,335

62

34,248

26,334

30

2,873

22

2,892

2,995

(3)

Sales Natural gas (mcf/d) NGLs (bbls/d)

986

184

436

643

144

347

11,612

7,446

56

9,243

7,528

23

1,068,281

685,030

56

3,373,808

2,747,804

23

$ 16,692

$ 11,400

46

$ 53,715

$ 39,071

37

334

–

100

2,113

–

100

$ 17,026

$ 11,400

49

$ 55,828

$ 39,071

43

15,675

10,972

43

47,946

37,670

27

455

17,694

3,257

443

Light crude oil (bbls/d) Total (boe/d) Total (boe) Revenue (000s) Natural gas Realized derivative gain Total natural gas NGLs

7,106

1,280

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)

$ 37,257

$ 23,878

56

$ 119,384

$ 80,224

49

$

$

4.71

(10)

$

$

–

100

Light crude oil

Total sales Average Prices Natural gas (per mcf) Total natural gas (per mcf)

$

4.33

$

48.75

NGLs (per bbl)

78.36

Light crude oil (per bbl) Combined average (per boe)

4.24 0.09

Realized derivative gain (per mcf)

$

37.26

$

4.71

(8)

41.51

17

75.64

4

34.53

8

4.30 0.17

$

4.47

$

45.42 75.39 $

36.00

Angle Energy inc

$

4.06

6

–

100

4.06

10

34.46

32

61.74

22

29.11

24

2010 Annual Report

51

Average Realized Product Prices Natural Gas ($/mcf)

NGLs ($/bbl)

06

07

08

09

10

6.80

7.14

8.20

4.06

4.47

06

07

42.90 49.52

08 58.15

Light Crude Oil ($/bbl)

09

10

34.46 45.42

06

07

08

66.00 80.74 86.40

09

10

61.74

75.39

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.

Product Mix of Daily Average Production (boe basis) Q4 2010

2010

2,892 NGLs

986 Light Crude Oil

7,131 Natural Gas

2,995 NGLs

643 Light Crude Oil

Total 11,612

52 Angle Energy inc

2009 5,708 Natural Gas

3,495 NGLs

Total 9,243

2010 Annual Report

4,389 Natural Gas

144 Light Crude Oil

Total 7,528

The Company’s drilling operations often target natural gas that is rich in associated NGLs. Angle’s NGLs are comprised of approximately 30 percent ethane, 27 percent propane, 15 percent butane and 28 percent condensate. The price received for its NGLs is based on this mix, with condensate having the highest value of the NGLs stream.

Angle’s production is sold in Canada and is sensitive to North American natural gas and world crude oil price variations in addition to Canada/U.S. currency exchange rate changes. The Company’s production is sold through eight purchasers to limit reliance on any one purchaser, which helps limit credit risk.

The Company has fixed the price applicable to future sales through the following contracts, on which $2.1 million in unrealized losses have been recorded at December 31, 2010: Period

Commodity

Type of Contract

Quantity Contracted

Contract Price ($/unit)

Jan. 1/11 – Dec. 31/11

Natural Gas

Financial

5,000 GJ/d

AECO Cdn$3.825/GJ

Jan. 1/11 – June 30/12

Crude Oil

Financial

500 bbls/d

Nymex US$87.05/bbl

Apr. 1/11 – Oct. 31/11

Natural Gas

Financial

5,000 GJ/d

AECO Cdn$3.82/GJ

Apr. 1/11 – Mar. 31/12

Natural Gas

Financial

2,500 GJ/d

AECO Cdn$3.775/GJ

Apr. 1/11 – Mar. 31/12

Natural Gas

Financial

2,500 GJ/d

AECO Cdn$3.815/GJ

The Company has entered into a currency average rate forward swap transaction whereby U.S. dollars have been converted to Canadian dollars as summarized in the following table: Period

Amount

Strike Price

Jan. 1/11 – June 30/12

US$1,300,000/month

Cdn$1.0535

Angle is only entitled to a cash settlement if the monthly average currency exchange rate as reported by the Bank of Canada is greater than 0.95.

Royalties

Three Months Ended December 31

Total revenue before derivative gains/losses

Years Ended December 31

2010

2009

% Change

2010

2009

% Change

$ 39,473

$ 23,652

67

$ 119,355

$ 79,998

49

$

$

2,678

3

$ 12,306

$ 10,641

16

(000s except per boe and % of revenue)

Royalties Crown

2,750

2,720

36

11,414

9,261

23

Total royalties

$

3,700 6,450

$

5,398

19

$ 23,720

$ 19,902

19

Total royalties ($/boe)

$

6.04

$

7.88

(23)

$

$

7.24

(3)

Freehold and overriding

7.03

As % of revenue Crown

7%

11%

(4)

10%

13%

(3)

Freehold and overriding

9%

12%

(3)

10%

12%

(2)

16%

23%

(7)

20%

25%

(5)

Total

Angle’s Crown royalties declined to 7 percent and 10 percent of revenue for the three months and year ended December 31, 2010, respectively, from an average of 11 percent and 13 percent, respectively, for the comparative periods a year earlier. These decreases were largely due to Alberta Crown royalty incentives which reduce the royalty rate on production from new Crown wells to 5 percent for the first 50,000 boe. Angle also received higher gas cost allowance

Angle Energy inc

2010 Annual Report

53

credits in 2010 related to higher qualifying capital expenditures. Freehold and overriding royalties decreased slightly in 2010 as a percentage of revenue due to a higher proportion of Angle’s revenue coming from Crown wells.

Operating Expense

Three Months Ended December 31 2010

(000s except per boe)

$

Operating expense

7,453

$

691

Transportation expense

Years Ended December 31

2009

% Change

2010

2009

3,008

148

$ 20,817

$ 12,335

69

245

182

2,236

977

129

Total operating expense

$

8,144

$

3,253

150

Total operating expense ($/boe)

$

7.62

$

4.75

60

% Change

$ 23,053

$ 13,312

73

$

$

41

6.83

4.84

The 60 percent and 41 percent increases in the 2010 per boe rates are due to several factors. During 2010, Angle increased its oil production significantly and oil production typically has a higher per boe operating expense than natural gas production. The production acquired in the Edson area in June 2010 has higher operating costs than the Harmattan and Ferrier areas due to less favourable third-party processing rates. In addition, Angle received an invoice for unanticipated operating cost adjustments spanning several years for gas processing in the Harmattan area in the fourth quarter of 2010 for $0.6 million. This adjustment increased operating expenses by $0.56 per boe in the fourth quarter and $0.18 per boe in 2010. These charges are non-recurring and therefore Angle expects operating costs to decrease in 2011 to between $6.50 and $6.75 per boe.

General and Administrative (G&A) Expense

Three Months Ended December 31 2010

(000s except per boe)

$

G&A expense

2,762

$

Years Ended December 31

2009

% Change

2010

2,033

36

$ 10,913

$

2009

% Change

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)

Operating Expense ($/boe)

G&A Expenses ($/boe)

06

07

08

09

10

06

07

08

09

10

06

07

08

09

10

16.45

14.59

16.85

7.24

7.03

5.17

4.45

5.16

4.84

6.83

3.75

1.60

1.79

2.31

2.35

54 Angle Energy inc

2010 Annual Report

Interest Expense

Three Months Ended December 31 2010

(000s except per boe)

2009

% Change

Years Ended December 31 2010

2009

% Change

Interest expense

$

1,756

$

98

1,692

$

4,595

$

245

1,776

Interest expense ($/boe)

$

1.64

$

0.14

1,071

$

1.36

$

0.09

1,411

Interest expense incurred during the fourth quarter of 2010 was $1.8 million on average debt of $131.7 million for an effective interest rate of 5.3 percent. Interest expense incurred during the year ended December 31, 2010 was $4.6 million on average debt of $90.4 million for an effective interest rate of 5.1 percent.

Angle incurred almost no interest expense in 2009 due to very low debt levels carried during the year. In comparison, in 2010 the Company closed two material acquisitions and conducted a large capital program which required Angle to increase its net debt. As Angle’s debt to cash flow ratio increased throughout 2010 so did the margins charged on the Company’s bank facility, which resulted in a slightly higher effective interest rate in the fourth quarter.

Stock-Based Compensation (SBC) Expense

Three Months Ended December 31 2010

(000s except per boe)

SBC expense

$

1,127

$

(197)

SBC capitalized (direct)

2009

% Change

682

65

(157)

25

Years Ended December 31 2010

$

3,635

$

(689)

2009

% Change

2,032

79

(476)

45

SBC expense (net)

$

930

$

525

77

$

2,946

$

1,556

89

SBC expense (net) ($/boe)

$

0.87

$

0.77

13

$

0.87

$

0.57

53

The 77 percent and 89 percent increases in net SBC expense for the three and 12-month periods, respectively, resulted from new option grants in 2010 as well as an increase in the fair value per option consistent with the increase in Angle’s stock price.

Depletion, Depreciation and Accretion (DD&A)

Three Months Ended December 31

Depletion and depreciation expense

Years Ended December 31

2010

2009

% Change

2010

2009

% Change

$ 19,484

$ 10,757

81

$ 63,467

$ 42,136

51

(000s except per boe)

196

52

277

537

214

151

DD&A expense

$ 19,680

$ 10,809

82

$ 64,004

$ 42,350

51

DD&A expense ($/boe)

$

$

17

$

$

23

Accretion expense

18.42

15.78

18.97

15.41

The 17 percent and 23 percent increase in DD&A per boe for the three and 12-month periods, respectively, resulted from assets acquired which carry higher DD&A per boe of reserves, as well as an increase in future development costs based on the December 31, 2010 reserve report prepared by GLJ Petroleum Consultants Ltd. (GLJ), Angle’s independent reserves evaluator.

Angle performed a ceiling test as at December 31, 2010. Based on the calculation, the carrying values of the Company’s property, plant and equipment are less than the sum of the undiscounted cash flows of the Company’s proved reserves and, therefore, no write-down of property, plant and equipment was required.

Angle Energy inc

2010 Annual Report

55

Income Taxes

The provision for future income taxes in the financial statements for the fourth quarter and year ended December 31, 2010 was a reduction of $0.5 million and $1.8 million, respectively. Angle did not pay any cash taxes in 2010 and estimates it has sufficient tax pools to shelter estimated income until 2012 or beyond.

A summary of the Company’s income tax pools is outlined below:

Years ended December 31 2010

2009

$ 160,848

$ 31,853

(000s)

Canadian Oil and Gas Property Expense (COGPE)

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

Canadian Development Expense (CDE)

10,550

5,818

$ 464,530

$ 156,608

Share issue costs

Netback Analysis

Three Months Ended December 31 2010

($/boe)

$

Sales price

37.26

2009

$

(6.04)

Royalties

(7.62)

Operating expense $

Operating netback

23.60

$

Years Ended December 31 2010

% Change

34.53

8

(7.88)

(23)

(4.75)

60

21.90

8

$

36.00

$

(7.03) (6.83) $

22.14

$

2009

% Change

29.11

24

(7.24)

(3)

(4.84)

41

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

(0.01)

Asset retirement expenditures Funds from operations netback (1)

$

20.06

$

–

(100)

19.31

4

(0.05) $

18.38

$

–

(100)

14.63

26

(0.87)

(0.77)

13

(0.87)

(0.57)

53

(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

2.63

(143)

(1.10)

37

SBC expense DD&A expense

Net income (loss) netback

$

(1.13)

$

$

(1.51)

$

(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.

56 Angle Energy inc

2010 Annual Report

Operating Netback ($/boe)

06

07

20.33 26.72

Funds from Operations Netback ($/boe)

08

09

10

06

31.05

17.03

22.14

17.07

07

08

24.38 28.96

09

10

14.63

18.38

Funds from Operations, Cash Flow from Operating Activities and Net Income or Loss

Three Months Ended December 31

Years Ended December 31

2010

2009

% Change

2010

2009

%Change

Funds from operations (000s)

$ 21,433

$ 13,227

62

$ 62,003

$ 40,154

54

Funds from operations (per boe)

$

20.06

$

19.31

4

$

18.38

$

14.63

26

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

Funds from operations per share

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

Basic

$

(0.02)

$

0.04

(150)

$

(0.08)

$

(0.07)

14

Diluted

$

(0.02)

$

0.04

(150)

$

(0.08)

$

(0.07)

14

70,597

48,151

47

63,224

43,748

45

71,804

48,949

47

64,481

44,533

45

Net income (loss) per share

Weighted average shares outstanding (000s) Basic

Diluted (1)

(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.

Funds from Operations

06

07

08

09

10

06

07

08

09

10

8.0

29.7

69.8

40.2

62.0

0.28

0.91

1.91

0.92

0.98

($mm)

($/basic share)

Angle Energy inc

2010 Annual Report

57

The increase in 2010 funds from operations and cash flows from operating activities was the result of higher volumes as well as an improvement in the average commodity price realized by Angle. The higher net losses recognized in 2010 resulted primarily from higher non-cash expenses such as DD&A and SBC. Liquidity and Capital Resources The following table summarizes the change in working capital during the years ended December 31, 2010 and 2009:

Years ended December 31 2010

2009

$ 38,255

$ (8,960)

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)

–

(27,979)

(64,575)

$ (152,378)

$ 38,255

(000s)

Working capital (deficiency) – beginning of year Funds from operations

Debt and working capital deficiency acquired on corporate acquisition Working capital (deficiency) – end of year

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).

58 Angle Energy inc

2010 Annual Report

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 (000s, except per share data)

Total assets Total sales (boe/d)

Dec. 31, 2010

Sept. 30, 2010

June 30, 2010

Mar. 31, 2010

($)

($)

($)

($)

($)

($)

($)

($)

558,969 547,885 490,605 334,973

246,465

212,040

212,578

191,682

7,446

7,552

7,472

7,645

11,612

10,021

7,290

8,003

Dec. 31, 2009

Sept. 30, 2009

June 30, 2009

Mar. 31, 2009

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

0.25

0.27

0.19

0.21

0.25

0.30

0.21

0.22

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)

(0.07)

(0.02)

0.03

0.04

(0.04)

(0.05)

(0.02)

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

Per share – basic

Per share – basic Capital expenditures (2)

(0.02) 30,470

(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.

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Selected Annual Information Years Ended December 31

2010

2009

2008

2007

2006

9,243

7,528

6,586

3,334

1,281

121,468

79,998

127,885

55,683

19,621

62,003

40,154

69,801

29,663

7,985

($000s, except production and per share data)

Total sales (boe/d) Oil and natural gas revenues

(1)

Funds from operations Per share – basic Net income (loss)

0.98

0.92

1.91

0.91

0.28

(5,098)

(3,032)

26,372

9,650

1,543

(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)

Per share – basic

(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

$

Operating lease – compressors Exploration expenditures (flow-through) Total

801

$

1,594

690

$

690

834

23,507

–

$ 25,902

$ 1,524

$

–

–

– $

690

633 –

$

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.

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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.

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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 stockbased 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: • Exploration and Evaluation (E&E) expenditures – On transition to IFRS, Angle will reclassify all E&E expenditures that 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.

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2010 Annual Report

• Impairment of PP&E assets – Under IFRS, impairment tests of PP&E must be performed at the CGU level as opposed 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. • Depletion expense – On transition to IFRS, Angle has the option to perform depletion calculations using either proved reserves or proved plus probable reserves. Angle anticipates it will use proved plus probable reserves to deplete its PP&E assets.

• Stock-based compensation expense – Under IFRS, each tranche of options is required to be treated as a 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. • Asset retirement obligations – Under IFRS, either cash flows or the interest rate should be risked in calculating the asset 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: • Internal controls over financial reporting – Based on Angle’s accounting policies under IFRS, management has assessed 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.

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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.

64 Angle Energy inc

2010 Annual Report

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.

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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 December 31, 2010

(000s)

Cash flow from operating activities Changes in non-cash working capital Funds from operations

66 Angle Energy inc

2010 Annual Report

Years Ended December 31, 2010

2010

2009

2010

2009

$ 23,804

$ 14,179

$ 53,566

$ 27,843

(2,371)

(952)

8,437

12,311

$ 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.

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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

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2010 Annual Report

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.

Stuart C. Symon

President & Chief Operating Officer

Vice President Finance & Chief Financial Officer

Financials

Heather Christie-Burns

Calgary, Canada, March 14, 2011

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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

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2010 Annual Report

CONSOLIDATED BALANCE SHEETS

As at December 31, (000s)

2010

2009

($)

($)

Assets

Current Cash and cash equivalents Accounts receivable Prepaid expenses and other Derivative instruments (note 10)

–

34,644

19,724

11,988

3,894

3,722

–

226

520

–

24,138

50,580

Property and equipment (note 4)

534,831

195,885

558,969

246,465

Future tax asset (note 8)

Liabilities

Current

37,080

Accounts payable and accrued liabilities Derivative instruments (note 10)

Bank debt (note 5)

1,047

–

38,127

12,099

138,916

–

810

–

31,678

19,453

6,271

2,712

215,802

34,264

Derivative instruments (note 10) Future tax liability (note 8) Asset retirement obligations (note 6)

12,099

Shareholders’ equity Share capital (note 7)

309,648

175,710

7,244

5,118

Contributed surplus (note 7)

26,275

31,373

343,167

212,201

558,969

246,465

Retained earnings

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

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CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS

Years Ended December 31, (000s, except per share data)

Revenue

2010

2009

($)

($)

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 General and administrative

23,053

13,312

7,920

6,350

Interest

4,595

245

Stock-based compensation (note 7)

2,946

1,556

Depletion, depreciation and accretion

Loss before income taxes Income taxes

64,004

42,350

102,518

63,813

(6,854)

(3,491)

Future tax reduction (note 8)

(1,756)

(459)

Net loss for the year

(5,098)

(3,032)

Retained earnings – beginning of year

31,373

34,405

Retained earnings – end of year

26,275

31,373

Net loss per share (note 7) Basic

(0.08)

(0.07)

Diluted

(0.08)

(0.07)

See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, (000s)

2010

2009

($)

($)

Cash provided by (used in): Operating activities

Net loss for the year

(5,098)

(3,032)

–

(35)

Cash settlement of share appreciation rights plan (note 7)

Add back non-cash items: 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)

(177)

–

Depletion, depreciation and accretion

Asset retirement expenditures

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

–

(112)

68

246,518

71,704

Change in non-cash working capital (note 9)

Investing activities Property and equipment additions

(184,979) (46,148)

–

(123,944)

(22,451)

Corporate acquisition (note 3) Property and equipment acquisitions (note 3)

(42,124)

20,343

(1,267)

(334,728)

(65,842)

Net increase (decrease) in cash

(34,644)

33,705

Cash – beginning of year

34,644

939

–

34,644

Change in non-cash working capital (note 9)

Cash – end of year See accompanying notes to the consolidated financial statements.

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73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010 and 2009 1.

Nature of Operations

Angle Energy Inc. (“Angle” or the “Company”) is a publicly traded company incorporated under the laws of Alberta.

The principal business of the Company is the exploration, exploitation, development and production of natural gas and oil reserves.

2.

Accounting Policies

These consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). Since the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions, which have been made with careful judgement. However, actual results could differ from estimated amounts. The consolidated financial statements have, in management’s opinion, been properly prepared using careful judgement within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a) Property and Equipment

(i)

Capitalized Costs The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method, all costs related to the exploration, development and production of petroleum and natural gas reserves are capitalized in a single Canadian cost centre. Costs include lease acquisition costs, geological and geophysical expenses, costs of drilling productive and non-productive wells, asset retirement obligation costs, production equipment costs, general and administrative costs and stock-based compensation directly related to exploration and development activities. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would alter the rate of depletion and depreciation by more than 20 percent. Office equipment is recorded at cost.

(ii) Depletion and Amortization Petroleum and natural gas properties, net of estimated salvage or residual value, and estimated costs of future development of proved undeveloped reserves are depleted and amortized using the unit-ofproduction 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.

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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.

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(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.

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2010 Annual Report

(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.

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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.

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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.

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4. Property and Equipment

Accumulated Depletion and

Cost Amortization (000s)

($)

($)

Net Book Value ($)

December 31, 2010 Petroleum and natural gas properties Office equipment

December 31, 2009 Petroleum and natural gas properties Office equipment

692,018

157,992

534,026

1,440

635

805

693,458

158,627

534,831

289,908

94,765

195,143

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 Price

Natural Gas Price

NGLs Price

($/bbl)

($/mcf)

($/bbl)

2011 2012 2013 2014 2015 *

83.09 86.24 87.91 89.97 93.22

4.24 4.87 5.47 5.96 6.46

53.11 53.29 54.50 56.49 59.00

Year

* Thereafter, annual increases of 2 percent.

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2010 Annual Report

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: 2010

Years Ended December 31,

2009

($)

($)

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

–

(000s)

Balance – beginning of year

Liabilities settled

(177)

–

Accretion of asset retirement obligation

537

214

6,271

2,712

Asset retirement obligation – end of year

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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 2010

Years Ended December 31,

2009

Shares

Amount

Shares

Amount

(#)

($000s)

(#)

($000s)

Common Shares Balance – beginning of year

54,481,132

175,710

39,296,574

104,995

Common shares issued

14,999,699

114,699

15,184,558

76,384

2,488,000

25,004

–

–

Flow-through shares issued Tax effect of flow-through shares

–

–

–

(2,516)

Share issue costs

–

(7,780)

–

(4,212)

–

2,015

–

1,059

71,968,831

309,648

54,481,132

175,710

Tax benefit of share issue costs Balance – end of year

In May 2010, the Company issued 6,080,000 common shares at a price of $7.70 per common share for gross proceeds of $46,816,000 ($44,175,000 net of issue costs).

In June 2010, the Company issued 8,050,000 subscription receipts at a price of $7.90 per subscription receipt, for total proceeds of $63,595,000 ($59,965,000 net of issue costs). Upon exercise, each subscription receipt was convertible to one common share. All subscription receipts were deemed exercised and converted to common shares on June 30, 2010.

In November 2010, the Company issued 2,488,000 flow-through common shares at $10.05 per share for total gross proceeds of $25,004,000 ($23,495,000 net of issue costs). Under the terms of the flow-through agreement, the Company is committed to spending $25,004,000 on qualified exploration and development expenditures by December 31, 2011.

In 2010, the Company issued 869,699 common shares resulting from the exercise of stock options, for cash proceeds of $2,779,000 and previously recognized stock-based compensation expense of $1,509,000.

(c) Contributed Surplus Years Ended December 31,

2010

2009

($)

($)

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)

7,244

5,118

(000s)

Balance – beginning of year

Balance – end of year

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2010 Annual Report

(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:

Options

Weighted Average Exercise Price

(#)

($)

Outstanding at December 31, 2008

2,945,000

2.81

Granted in 2009

2,547,750

4.91

Exercised in 2009

(875,334)

(1.30)

Forfeited in 2009

(236,500)

(6.32)

Outstanding at December 31, 2009

4,380,916

4.14

Granted in 2010

2,653,000

7.59

Exercised in 2010

(869,699)

(3.19)

Forfeited in 2010

(105,000)

(5.28)

6,059,217

5.77

Outstanding at December 31, 2010

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83

Outstanding

Exercise Price ($)

(#)

Weighted Average Weighted Remaining Average Contractual Exercise Life Price Exercisable (years)

($)

(#)

Weighted Average Exercise Price ($)

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

–

–

218,500

4.13

8.82

–

–

6,059,217

3.49

5.77

1,963,961

4.09

8.20 – 10.00

As at December 31, 2009 1.00 – 2.79

96,666

2.80 – 4.59

3,359,500

4.60 – 6.39

924,750 4,380,916

3.2

0.3

1.00

96,666

1.00

3.0

3.90

1,624,000

3.44

4.3

5.35

88,249

5.30

4.14

1,808,915

3.40

The fair value of common share options granted during the year ended December 31, 2010 was estimated to be $9,519,000 or $3.59 per weighted average option (2009 – $4,499,000 or $2.64) as at the date of grant using the Black-Scholes pricing model and the following average assumptions: Years Ended December 31,

2009

Risk-free interest rate (%)

2.13

2.45

Expected life (years)

5.00

5.00

52.51

64.25

Expected volatility (%)

2010

(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.

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2010 Annual Report

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.

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8.

Income Taxes

The actual income tax provision differs from the expected amount calculated by applying the Canadian combined federal and provincial corporate tax rates to loss before income taxes. These differences are explained as follows: Years Ended December 31, (000s except percentage rates)

Loss before income taxes Tax rate Computed income tax provision

2010 ($)

2009 ($)

(6,854)

(3,491)

28.00%

29.00%

(1,919)

(1,012)

Increase (decrease) in income taxes resulting from: (482)

(94)

Stock-based compensation

825

451

Other

(225)

159

Rate adjustment

Non-deductible expenses

45

37

(1,756)

(459)

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s net future income tax assets and liabilities are as follows: Years Ended December 31, (000s)

Future income tax assets (liabilities): Share issue costs Net book value of property and equipment in excess of tax basis Other Future income tax asset (liability) 9.

2010

2009

($)

($)

2,691

1,551

(34,342)

(20,941)

493

(63)

(31,158)

(19,453)

Changes in Non-Cash Working Capital Years Ended December 31, (000s)

2010

2009

($)

($)

(6,867)

Accounts receivable

508

343

(2,456)

Accounts payable and accrued liabilities

18,318

(11,562)

11,794

(13,510)

2010

2009

Prepaid expenses and other

The change in non-cash working capital has been allocated to the following activities: Years Ended December 31,

($)

(000s)

(8,437)

Operating

($)

(12,311)

Financing

(112)

68

Investing

20,343

(1,267)

11,794

(13,510)

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2010 Annual Report

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”: • Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable 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

1,857

–

1,857

–

138,916

138,916

–

–

(000s)

Derivative liability Bank indebtedness

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(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.

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2010 Annual Report

(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:

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

Apr. 1/11 – Mar. 31/12

Natural Gas

Financial

2,500 GJ/d

AECO Cdn$3.775/GJ

Apr. 1/11 – Mar. 31/12

Natural Gas

Financial

2,500 GJ/d

AECO Cdn$3.815/GJ

Jan. 1/11 – June 30/12

Crude Oil

Financial

500 bbls/d

Nymex US$87.05/bbl

Subsequent to December 31, 2010, the Company entered into the following contract:

Period Commodity

Apr. 1/11 – Oct. 31/11

Natural Gas

Type of Contract

Quantity Contracted

Contract Price ($/unit)

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

Jan. 1/11 – June 30/12

US$1,300,000/month

Strike Price

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.

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(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.

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2010 Annual Report

HISTORICAL REVIEW Years Ended December 31

2010

2009

2008

2007

2006

Financial (000s, except per share amounts) (unaudited)

Commodity revenues (1) Funds from operations (2) Per share – basic Net income (loss) Per share – basic Capital expenditures (3) Total assets Net debt (working capital) (4) Shareholders’ equity

($)

($)

($)

($)

($)

121,468 62,003 0.98 (5,098) (0.08) 355,071 558,969 152,378 343,167

79,998 40,154 0.92 (3,032) (0.07) 64,575 246,465 (38,255) 212,201

127,885 69,801 1.91 26,372 0.72 79,866 186,985 8,960 143,057

55,683 29,663 0.91 9,650 0.30 59,110 134,371 31,819 82,461

19,621 7,985 0.28 1,543 0.05 57,821 87,072 10,772 65,344

Common Share Data

Common shares outstanding (000s) At December 31 71,969 54,481 39,297 34,523 Weighted average – basic 63,224 43,748 36,576 32,626 Share 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 34,248 26,334 23,336 11,688 Natural gas (mcf/d) 2,892 2,995 2,650 1,372 NGLs (bbls/d) 643 144 46 14 Light crude oil (bbls/d) 9,243 7,528 6,586 3,334 Total oil equivalent (boe/d)

Average wellhead prices (1) 4.47 4.06 8.20 7.14 Natural gas ($ per mcf) 45.42 34.46 58.15 49.52 NGLs ($ per bbl) 75.39 61.74 86.40 80.74 Light crude oil ($ per bbl) Combined average ($ per boe) 36.00 29.11 53.06 45.76 Reserves

31,900 12,309 11,462 9,194 Proved (mboe) 59,696 20,033 15,935 13,638 Proved plus probable (mboe) Total net present value – proved plus probable (10% discount) ($000s) 749,296 276,847 272,614 222,744 Wells drilled (gross) Natural gas Oil Dry and abandoned

19 18 3

Total

40

32,498 28,617 – – – –

3,975 612 7 1,281 6.80 42.90 66.00 41.95 6,203 12,396 146,300

9 14 12 – 4 2 4 6 5 13

24

19

16 – 6 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.

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91

CORPORATE INFORMATION Board of Directors

Officers

Head Office

Noralee Bradley – Chairman (3)(4)

Heather Christie-Burns

Partner Osler, Hoskin & Harcourt LLP

President & Chief Operating Officer

Clarence Chow (2)(4)

Chief Executive Officer

President CGS Asset Management Ltd.

Stuart C. Symon

Suite 700 324 Eighth Avenue S.W. Calgary, Alberta T2P 2Z2 Telephone: 403-263-4534 Facsimile: 403-263-4179 Website: www.angleenergy.com

D. Gregg Fischbuch

Vice President Finance, Chief Financial Officer & Corporate Secretary

Timothy V. Dunne (1)(3) Independent Businessman

G. Graham Cormack

D. Gregg Fischbuch

Vice President Operations

Chief Executive Officer Angle Energy Inc.

Glen Richardson Vice President Land

John Gareau (1)(3) Independent Businessman

Edward Muchowski (2)(4) Independent Businessman

Jacob Roorda (1)(2) Vice Chairman Canoe Financial

Auditors KPMG LLP Calgary, Alberta

Bankers

Elizabeth More

ATB Financial

Vice President Exploration

Calgary, Alberta

Matthew Mazuryk

Bank of Montreal

Vice President Engineering

Calgary, Alberta

Heather Post

Canadian Imperial Bank of Commerce

Controller

Calgary, Alberta

(1) Audit Committee Member

Evaluation Engineers

(2) Reserves Committee Member (3) Corporate Governance & Compensation

GLJ Petroleum Consultants Ltd. Calgary, Alberta

Committee Member (4) Environmental, Health & Safety

Committee Member

Seaton-Jordan & Associates Ltd. Calgary, Alberta

Legal Counsel Osler, Hoskin & Harcourt LLP Calgary, Alberta

Registrar and Transfer Agent Inquiries regarding change of address, registered shareholdings, stock transfers or lost certificates should be directed to: Valiant Trust Company Suite 310 606 Fourth Street S.W. Calgary, Alberta T2P 1T1 Telephone: 403-233-2801

Stock Trading Toronto Stock Exchange Trading Symbol: NGL

92 Angle Energy inc

2010 Annual Report

Designed and produced by Merlin Edge Inc. www.merlinedge.com Printed in Canada

Abbreviations

Conversion of Units

bbls bcf boe GJ /d mbbls mboe mcf mm mmboe mmbtu mmcf NGLs 2-D 3-D

1.0 acre = 0.40 hectares 2.5 acres = 1.0 hectare 1.0 bbl = 0.159 cubic metres 6.29 bbls = 1.0 cubic metre 1.0 foot = 0.3048 metres 3.281 feet = 1.0 metre 1.0 mcf = 28.2 cubic metres 0.035 mcf = 1.0 cubic metre 1.0 mile = 1.61 kilometres 0.62 miles = 1.0 kilometre Natural gas is equated to oil on the basis of 6 mcf : 1 bbl

barrels billion cubic feet barrels of oil equivalent gigajoules per day thousand barrels thousand barrels of oil equivalent thousand cubic feet million million barrels of oil equivalent million British thermal units million cubic feet natural gas liquids two dimensional three dimensional

Suite 700, 324 Eighth Avenue S.W. Calgary, Alberta T2P 2Z2 Telephone:

(403) 263-4534

Fax:

(403) 263-4179

Website:

www.angleenergy.com