Annual report 2013

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ANNUAL REPORT 2013

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ANNUAL REPORT 2013

will be held on June 6, 2014 Time: 9:00 am Calgary Time

Metropolitan Conference Centre 333-4th Ave SW Calgary, Alberta Royal Ballroom

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ANNUAL REPORT 2013

I am pleased to present the 2013 Annual Report, complete with Financial Statements and MD&A for the year ended December 31, 2013 for Corval Energy Ltd. (the "Company" or "Corval").

Corval commenced operations only a year and a half ago, on October 17, 2012. As we look back on our first full year of operations, we are extremely pleased with the progress that has been made. We have accomplished what we set out to do in the first year, in terms of production growth, completing a capital program within budget, and maintaining financial flexibility. Looking back on the year, a few of Corval’s main accomplishments are:

Grew production from 221 bopd in 2012 to average 526 bopd for the full year of 2013. Corval exited December 2013 at more than 1,200 bopd. Proved and probable reserves increased from 1.2 million bbl to 1.7 million bbls, a 41% increase. Proved developed reserves increased from 467.7 mboe in 2012 to 879.7 mboe in 2013, an 89% increase. Cash flow for the year ended December 31, 2013 was $8,206,000, compared to a negative cash flow in 2012 of $289,000. Cash flow grew steadily from $876,000 in the first quarter of 2013 to $3,116,000 in the fourth quarter of 2013. In October, 2012, Corval assumed debt under the Plan of Arrangement of approximately $11.6 million. Through the equity raise in December 2012, and cash flow from operations, Corval was able to fund a $28.4 million capital program and still be in strong financial shape at year-end with a $15.0 million unutilized line of credit and strong cash flows.Drilled 16 gross (13.75 net) oil wells in the year, in spite of an unusually wet spring and summer in southwest Manitoba. Operating netbacks increased from $36.65 in 2012 to $56.43 in 2013, based on strong crude oil prices and reduced operating costs.

As discussed above, Corval committed to a 2013 capital program of approximately $28 million. Corval doubled its land position from 21 sections in 2012 to over 44 sections in 2013. The newly acquired lands are in the same fairway to our initialland base, and may provide the Company with a new development area, once we have an opportunity to prove the concept. Corval also made a small “tuck-in” acquisition for $3.3 million in our core Sinclair area, that provided us with additional drilling locations in the Bakken and Lodgepole zones.

In addition, we completed the installation of an oil treater and associated water disposal line at the Sinclair oil battery. Theinstallation of the oil treater and water disposal line have reduced trucking costs by over $2.00 per bbl. Our new wells are now being tied into the battery at a lower cost than if we used single well batteries. We are pleased that this work, completed early in October, was done for only $1.2 million and allows for processing over 2,000 barrels of oil per day, allowing significant room for growth.

When we made the initial acquisition in October, 2012, management and the Board recognized that the lands were highly prospective for the Bakken zone, which had been effectively proved, and also the Lodgepole zone, which was in its infancy as very few horizontal wells had been drilled into this zone. Corval believed that multi-stage horizontal fracking would provide excellent results. In 2013, we drilled 10 Lodgepole wells, and the results have been truly impressive. These wells on averageproduce at initial rates of 110 bopd, with expected reserves of 80,000 bbls. With a capital cost of $1.7 million, we are seeingpayouts of less than one year on certain wells, which make these wells some of the most economic in the Western Canadian Sedimentary Basin. As we drill additional wells, and have a longer production history, we expect that Corval’s reserve bookings should increase significantly in future years. In addition, we will be experimenting with downspacing these wells from 4 wells per section, to 8 wells per section, which should provide Corval with additional drilling locations and additionalreserves.

In the initial acquisition in 2012, we acquired a small land position in Crossfield, Alberta with rights in the Cardium zone. This came with 7 wells one of which was shut in as required by the Alberta Energy Regulator due to an inability to capture and conserve the small volumes of natural gas produced with the crude oil. Through the efforts of our operations department, we were able to tie-in the well in late December. This well has been producing at a constant rate of 50 bopd, and associated natural gas volumes, which has exceeded our expectations.

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ANNUAL REPORT 2013

During the year, Corval fixed the price on 400 bbls/day of crude oil for 2014 at an average price of approximately $101.00 WTI ($Cdn). As crude oil prices continue to be volatile in North America, with new oil volumes coming on stream, we believe it to be prudent to lock in the price of certain volumes to reduce the volatility of our cash flow. This provides us with an extra level of security in planning our capital program.

That explains a little about where we have been, now I’d like to share with you some things about where we plan to go in the remainder of 2014. In January, the Board of Directors approved a capital program of $34.7 million, to be funded primarily from cash flow and some debt. This includes drilling up to 19 gross (16.25 net) wells. In addition, capital has been budgetedfor expanding our land position, shooting/processing seismic, expanding facilities as needed and well optimization. If everything goes as planned, we expect to average at least 1,100 bopd in 2014, exiting 2014 within the range of 1,400 to 1,500 bopd. Our budget (based on an average price for WTI of $95.00) suggests cash flow of $20 million for 2014

Throughout the year, I have talked to many of the shareholders. I get a lot of questions on what is our value? That is an impossible question for me to answer as we are not publically traded so there is no way I can accurately answer. We will all find that out when we either go public or sell the Company but rest assured that we are all in this together and the Board andmanagement’s primary goal is to increase the value of Corval while still running a safe and environmentally responsible company.

We invite shareholders to view Corval’s updated website and to attend the Annual General Meeting on June 6, 2014 at 9:00 am at the Metropolitan Conference Centre in Calgary. The website has been changed to allow only shareholders of Corval to view financial information and news releases. Our website is at www.corvalenergyltd.com. If you have any questions, please contact us at [email protected].

In closing I would like to thank all the shareholders in showing confidence in us as a team and I would like to thank the Board,my fellow officers and employees for all their efforts to grow the value of our Company.

Sincerely,

Thomas Stan President & CEO Corval Energy Ltd.

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ANNUAL REPORT 2013

In this Annual Report, the abbreviations set forth below have the following meanings:

bbl Barrel bbls Barrels Mbbls thousand barrels bbl/d barrels per day NGLs natural gas liquids

The following table sets forth certain standard conversions from Standard Imperial Units to the International System of Units (or metric units).

Bbls Cubic metres 0.159 Cubic metres Bbls 6.293 Feet Metres 0.305 Metres Feet 3.281 Acres Hectares 0.405 Hectares Acres 2.47

Certain terms used in this Annual Report in describing reserves and other oil and natural gas information are defined below. Certain other terms and abbreviations used in this Annual Report, but not defined or described, are defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (" ") or the Canadian Oil and Gas Evaluation Handbook (the " ") and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook.

API American Petroleum Institute ˚API an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid

petroleum with a specified gravity of 35.1˚ API or greater is generally referred to as light crude oil. Liquid petroleum with a specified gravity of 25.8˚ to 35˚ API or greater is generally referred to as medium crude oil. Liquid petroleum with a specified gravity of 25.7˚ API or lower is generally

referred to as heavy crude oil. BOE barrel of oil equivalent of natural gas and crude oil on the basis of 1 Bbl of crude oil for 6 Mcf of natural gas. Disclosure provided herein in respect of boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. BOE/d barrel of oil equivalent per day m3 cubic metres MBOE 1,000 barrels of oil equivalent WTI West Texas intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

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ANNUAL REPORT 2013

OPERATIONS SUMMARY

Sinclair/Daly, Manitoba

In December of 2012, Corval commenced a drilling program at Sinclair and Daly. The first well of a six well program was drilled in December, 2012, with the remaining five wells being drilled in the first quarter of 2013. This program included three horizontal wells into the Lodgepole zone and three horizontal wells into the Bakken zone. For the remainder of 2013, Corval drilled an additional ten wells at Sinclair and Daly, which included seven wells into the Lodgepole zone and three wells into the Bakken zone. All wells were completed using multi-stage fracture stimulation techniques consistent with those used successfully by other companies in the Sinclair area. These wells were then equipped with pumpjacks and brought on production. The all-in cost to drill, complete and bring on production has been approximately $1.7 million per well, which is on budget. During 2013, Corval also built an oil battery at Sinclair, installed an oil treater and associated water disposal line, thus allowing for the processing of over 2,000 bopd and eliminated significant costs associated with trucking volumes. The Company's properties in the Sinclair/Daly areas had proved reserves of 1,048,500 boe and proved plus probable reserves of 1,583,200 boe at December 31, 2013. The net present value discounted at 10% for proved plus probable reserves at December 31, 2013 was $51,022,000 (2012 - $19,963,000). Also at December 31, 2013, the Company owned 13,544 gross (10,448 net) acres of land in the Sinclair/Daly areas, for an average working interest of 77%. Most of the lands are operated by the Company. The Company has interests in 65 producing wells in the Sinclair/Daly areas. In the first quarter of 2014, three Lodgepole and two Bakken wells have been drilled and brought on production.

Crossfield, Alberta

At December 31, 2013, the Company's properties in the Crossfield area of Alberta had proved reserves of 35,500 boe and proved plus probable reserves of 45,600 boe. The net present value discounted at 10% for proved plus probable reserves at December 31, 2013 was $1,398,000. Also at December 31, 2013, the Company owned 1,600 gross (1,328 net) acres of land at Crossfield, for an average working interest of 83%. The Company has interests in seven wells capable of production in the area. During late 2013, Corval tied-in the associated gas production of one well and for the first three months in 2014 the well has been producing at a constant rate of 50 bopd and associated natural gas volumes.

Other Manitoba and Saskatchewan Properties

The Company has properties in other areas of Manitoba and Saskatchewan, including Pierson and Souris Hartney. The Company's properties in these other areas had proved reserves of 68,400 boe and proved plus probable reserves of 83,000 boe at December 31, 2013. The net present value discounted at 10% for proved plus probable reserves at December 31, 2013 was $1,478,000. Also at December 31, 2013, the Company owned 17,198 gross (16,113 net) acres of land in these areas of Manitoba and Saskatchewan, for an average working interest of 94%. The Company has interests in 13 producing wells inthese areas, producing an aggregate of 40 boe/d.

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OIL & GAS RESERVES

RESERVES SUMMARY

This statement of reserves data and other information (the "Statement") is dated March 3, 2014 and is effective December 31, 2013.

Oil and Natural Gas Reserves

The following reserves data and associated tables summarize the reserves of crude oil, natural gas and associated products and the estimated present worth of future net cash flows associated with the Company's reserves as estimated by Sproule Associates Limited (“Sproule” or the “Sproule Report”). The reserves are based on forecast price assumptions. The information herein in respect of the reserves was derived from the Sproule Report, which was prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook.

The tables below summarize the data contained in the Sproule Report and, as a result, may contain slightly different numbers than the Sproule Report and may not add due to rounding. The values in the Sproule Report do not include the value of undeveloped land holdings nor the tangible value of the Company’s interest in any associated plant and wellsite facilities. The cash flow forecasts account for downhole well abandonment costs. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this Annual Report are estimates only. The recovery and reserve estimates of the oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein. In general, estimates of economically recoverable oil, NGLs and natural gas reserves and the futurenet cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil, NGLs and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable oil, NGLs and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with theCompany's assets may vary from the information presented herein and such variations could be material.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

All of the reserves held by the Company as at December 31, 2013 were located in Canada and, specifically, in the provinces of Alberta and Manitoba.

The following tables detail the aggregate gross (working interest before royalty) and net reserves of the Company, as at December 31, 2013, using forecast prices and costs as well as the aggregate net present value of future net revenue attributableto the reserves estimated using forecast prices and costs, calculated without discount and using discount rates of 5%, 10%, 15%and 20%:

Summary of Oil and Gas Reserves Forecast Prices and Costs As at December 31, 2013

Light/Medium Oil Heavy Oil Natural Gas NGLs Total boeReserves Category Gross

(Mbbls)Net

(Mbbls)Gross

(Mbbls)Net

(Mbbls)Gross

(MMcf)Net

(MMcf)Gross

(Mbbls)Net

(Mbbls)Gross

(Mbbls)Net

(Mbbls)PROVED

Developed Producing 879.7 748.1 0 0 0 0 0 0 879.7 748.1Developed Non-Producing 8.5 9.1 0 0 0 0 0 0 8.5 9.1Undeveloped 263.9 221.8 0 0 0 0 0 0 263.9 221.8

TOTAL PROVED 1,152.1 979.0 0 0 0 0 0 0 1,152.1 979.0

PROBABLE 559.8 473.4 0 0 0 0 0 0 559.8 473.4

TOTAL PROVED PLUS PROBABLE 1,711.9 1,452.4 0 0 0 0 0 0 1,711.9 1,452.4

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OIL & GAS RESERVES

Summary of Net Present Values of Future Net Revenues Forecast Prices and Costs As at December 31, 2013

Before Income Taxes Discounted At (% /year)Reserves Category 0%

($000s)5%

($000s)10%

($000s)15%

($000s)20%

($000s)

PROVEDDeveloped Producing 44,267 38,423 34,161 30,924 28,384Developed Non-Producing 255 205 171 147 129Undeveloped 6,131 4,255 2,859 1,793 961

TOTAL PROVED 50,654 42,882 37,191 32,863 29,473

PROBABLE 30,107 21,733 16,703 13,413 11,125TOTAL PROVED PLUS PROBABLE 80,761 64,614 53,894 46,276 40,598

The following tables provide a breakdown of various elements of future net revenue attributable to proved reserves and proved plus probable reserves estimated using forecast prices and costs, calculated without discount:

Total Future Net Revenue (Undiscounted)

Forecast Prices and Costs As at December 31, 2013

Reserves Category Revenue RoyaltiesOperating

CostsDevelopment

Costs

Well Abandonment

Costs

Future Net Revenue Before

Income Taxes($000s) ($000s) ($000s) ($000s) ($000s) ($000s)

Proved 111,114 16,929 30,991 10,201 2,339 50,654Proved Plus Probable 170,182 26,123 47,091 13,631 2,576 80,761

Based on Corval’s tax pools plus future development costs, the Company does not expect to be taxable using the Sproule cash flow projections.

The following tables detail by production group the net present value of future net revenue (before deducting future income taxexpenses), estimated using forecast prices and costs, calculated using a discount rate of 10%:

Future Net Revenue by Production Group Forecast Prices and Costs As at December 31, 2013

Reserves Category Production Group

Future Net RevenueBefore Income Taxes(3)

(discounted at 10%/year)($000s) ($/boe)

Proved Light/Medium Oil (1) 37,191 37.99Heavy Oil(1) 0 0Natural Gas(2) 0 0Total(4) 37,191 37.99

Proved Plus Probable Light/Medium Oil(1) 53,894 37.11Heavy Oil(1) 0 0Natural Gas(2) 0 0Total(4) 53,894 37.11

Notes:

(1) Including solution gas and other by-products. (2) Including by-products but excluding solution gas. (3) Unit values are based on the Company's net reserves. (4) Columns may not add due to rounding.

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OIL & GAS RESERVES

Pricing Assumptions

The following tables detail the reference prices as at December 31, 2013 used in the Sproule Report for evaluating the net present values of future net revenues relating to the Company’s reserves disclosed above. The forecast cost and price assumptions assume the continuance of current laws and regulations and increases in wellhead selling prices, and take into account inflation with respect to future operating and capital costs. In addition, operating and capital costs have been inflated at 1.5% per year. Sproule is an independent qualified reserves evaluator and auditor.

Summary of Pricing and Inflation Rate Assumptions as at December 31, 2013 Forecast Prices and Costs

OIL

Year

WTI Cushing

Oklahoma($US/bbl)

EdmontonPar Price

($Cdn/bbl)

CromerLSB

Light 35° Oil

($Cdn/bbl)

Exchange Rate

$US/$Cdn

Forecast2014 94.65 92.64 90.64 0.942015 88.37 89.31 87.31 0.942016 84.25 89.63 87.63 0.942017 95.52 101.62 99.62 0.942018 96.96 103.14 101.14 0.942019 98.41 104.69 102.69 0.94Thereafter +1.5%

Note:

(1) Weighted average historical prices of the Company’s reserves for the period ended December 31, 2013 were $89.91/bbl for crude oil. Transportation expense has been included in the realized price to align with pricing assumptions contained in the SprouleReport.

(2) Exchange rates used to generate the benchmark reference prices in the table.

Future Development Costs

The following table sets forth the future development costs deducted in the estimation of the future net revenue attributable tothe reserves categories noted below.

Forecast Prices and Costs

YearProved Reserves

($000s)Proved Plus Probable Reserves

($000s)

2014 10,201 13,6312015 0 02016 0 02017 0 02018 0 0Remainder 0 0Total: Undiscounted 10,201 13,631Total: Discounted at 10% per year 9,794 13,049

In all years of the economic forecasts, the net revenues from the reserves attributable to the reserves categories noted above are well in excess of the estimated future development costs. Therefore, the Company can meet the funding requirements for future development entirely out of its cash flow and requires no other sources of cash in order to develop the proved or probable reserves. As a result, interest or other costs of external funding are not included in the reserves and future net revenue estimates.

Properties with No Attributed Reserves

The undeveloped land holdings attributable to the Company's reserves, as at December 31, 2013, consisted of approximately 23,798 gross (20,658 net) acres of undeveloped land.

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OIL & GAS RESERVES

No third party evaluation of the undeveloped lands included in the Company’s land holdings has been undertaken. The simple average working interest in undeveloped lands as of December 31, 2013 was 87%.

As at December 31, 2013, approximately 3,280 gross (3,280 net) acres of the Company's land holdings expire in 2014.

Production Estimates

The following table sets out the estimated volume of the Company's gross production for the year ended December 31, 2014 as reflected in the estimates of future net revenue disclosed herein.

2014 Estimated Average Daily Production – Forecast Prices and CostsProduction

Gas(Mcf/d)

Light Oil(bbls/d)

Heavy Oil(bbls/d)

NGLs(bbls/d)

OilEquivalent

(boe/d)Proved ProducingSinclair/Daly - 564 - - 564Crossfield - 22 - - 22Other properties - 31 - - 31Total Proved Producing - 617 - - 617

Total ProvedSinclair/Daly - 726 - - 726Crossfield - 22 - - 22Other properties - 34 - - 34Total Proved - 782 - - 782

Proved Plus ProbableSinclair/Daly - 862 - - 862Crossfield - 22 - - 22Other properties - 34 - - 34Total Proved Plus Probable - 918 - - 918

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FIELD OPERATIONS

Corval Sinclair Battery #1 (4-34):

Under Construction – Treater was installed in Oct, 2013

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FIELD OPERATIONS

Corval Sinclair Battery #1 (4-34):

Fully operational with treater & water disposal facilities

Present throughput of 1,200 bbl fluid per day at 70% oil (Capacity = 3,000 bbl fluid per day)

15 New horizontal wells and 5 old vertical wells currently tied into the battery

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FIELD OPERATIONS

100/04-23-008-28W1 Bakken Oil Well (Equipped with Pumpjack)

102/04-23-008-28W1 Lodgepole Oil Well (Waiting on Pumpjack)

Both wells came on production in September 2013

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FIELD OPERATIONS

100 & 102 / 08-23-008-28W1 Bakken & Lodgepole Oil Wells

Drilled and on production in Q1, 2014

Pipelined into the 4-34 battery

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FIELD OPERATIONS


Drilled and on production in Q1, 2014

5 Pumpjacks in foreground are now installed on new 2014 wells

All recent wells are now pipelined into the 4-34 battery

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FIELD OPERATIONS


Drilled and on production in March, 2013

Pipelined into the 4-34 Battery

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FIELD OPERATIONS

Corval Energy Ltd. supported Goulter School in Virden with their Breakfast Program

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PRODUCTION & CASH FLOW GRAPHS

100

200

300

400

500

600

700

800

900

221

Q4 2012

318

547

457

777

Q1 2013 Q2 2013 Q3 2013 Q4 2013

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

($0.3)

Q4 2012

$0.9

$2.3$1.9

$3.1

Q1 2013 Q2 2013 Q3 2013 Q4 2013

100

($0.5)

Growth ProfileProduction - BOPD

Growth ProfileCash Flow - $Millions

Pro

du

ctio

n -

BO

PD

Cas

h F

low

- $

Mill

ion

s

Wet Weather Delays

Wet Weather Delays

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MANAGEMENT’S DISCUSSION & ANALYSIS

Financial and Operations Overview

Financial ($000s except per share amounts)

Year ended December 31, 2013

($000s)

Year endedDecember 31, 2012

($000s)

Petroleum and natural gas sales 17,253 1,365

Funds from (used in) operations*(before changes in non-cash working capital) 8,206 (289)

Basic ($/share) 0.14 (0.05)

Net loss (767) (8,475)Basic ($/share) (0.01) (1.53)

Working capital (deficiency)(excluding non-cash commodity price contract asset) (1,242) 2,802

Capital expendituresLand and seismic 362 99Drill and complete 22,593 1,197Equipment, facilities and other 1,442 62Development capital 24,397 1,358

Exploration and evaluation 2,558 -Property acquisitions 3,292 -Property dispositions (1,874) -

28,373 1,358

OperatingAverage production (bbl/d) 526 221Average realized price ($/bbl) 89.91 82.39

Netback ($/bbl)Petroleum and natural gas sales 89.91 82.39Realized loss on commodity price contract (1.00) -Royalties (13.07) (13.74)Operating expenses before workovers (16.01) (23.53)Netback before workovers 59.83 45.12Workovers (3.40) (8.47)

Operating netbacks* 56.43 36.65

Total wells drilled 16 1Working interest wells 13.75 1

Land holdings (net acres) 27,889 13,

Common shares o/s at period-end (000’s) 70,391 45,826*Note: Funds from operations and operating netbacks do not have a standardized meaning under GAAP. Refer to non-GAAP measures in this report.

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April 24, 2014

Corval Energy Ltd. (“Corval” or the “Company”) is an oil and gas exploration, development and production Company based inCalgary, Alberta, Canada. The Company conducts its operations in Alberta and the Williston basin in Manitoba and Saskatchewan. The consolidated financial statements of the Company as at December 31, 2013 comprise the Company and its wholly owned subsidiaries. Corval Energy Ltd. is domiciled in Canada at Suite 2400, 500 – 4th Avenue SW, Calgary, Alberta T2P 2V6.

Although Corval had been incorporated in 2011, Corval formally commenced operations in October, 2012. Therefore, the consolidated financial statements and the Management’s Discussion and Analysis reflect operations only after October 2012, as a result, no comparison of operations has been provided for the three months ended December 31, 2013 and 2012.

HIGHLIGHTS

Corval raised $16.2 million during 2013 through a private placement and through draws under its line of equity During 2013, Corval drilled 16 (13.75 net) wells of which 14 (12.5 net) were completed and on production at December 31, 2013 Corval’s Sinclair oil battery came on stream in the fourth quarter of 2013, resulting in significantly reduced operating costs During 2013 the Company acquired certain producing oil and gas assets in Manitoba for $3.3 million Corval doubled its lands holdings by acquiring land in new exploration plays At Crossfield, the Company tied-in its gas production in late 2013, the well was placed on production in January 2014. Renegotiated a new bank facility for $15.0 million In order to manage exposure to fluctuating crude oil pricing and to protect the capital program, Corval entered into four commodity price contracts in 2013 at an average price of approximately $101.00 WTI Cdn. Corval exited December, 2013 at approximately 1,200 bopd, up from 221 bopd at the year end of 2012. The exit production includes flush production from new wells which will decline quickly until production stabilizes approximately 90 days after completion.

ADVISORIES

Management’s discussion and analysis (“MD&A”) and results of operations should be read in conjunction with the consolidated financial statements for the year ended December 31, 2013. Barrels of oil equivalent (“boe”) may be misleading as boes are based on a relative energy content conversion of six thousand cubic feet (“mcf”) of natural gas to one equivalentbarrel (“bbl”) of oil (6 mcf = 1bbl) when measured at burner tip and does not represent a value equivalency at the wellhead. Production volumes reported are the Company’s interest before royalties, and all amounts are expressed in Canadian dollars, unless otherwise stated.

The financial data presented has been prepared in accordance with Canadian Generally Accepted Accounting principles (“GAAP”), which are based on International Financial Reporting Standards (“IFRS”). Additional terms used in this Management Discussion and Analysis are “funds from operations” or “funds used in operations”, and “netback”. Funds from operations are presented for information purposes only, and should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined by GAAP. Corval determines funds from operations to be the cash flow before changes in non-cash working capital. Management believes that in addition to net earnings, funds from operations is a useful supplemental measure to assess the financial performance and the ability of Corval to finance future growth throughcapital investment. In addition, management uses netback to analyze operating performance and leverage. Netback equals total revenue less royalties, operating costs and transportation costs calculated on a per boe basis.

Forward-looking information

Certain information set forth in this document, including management’s assessment of future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, many of which are beyond management’s control. Those risks include, without limitation, the effect of general economic conditions,risks associated with oil and gas exploration, development, production, marketing and transportation, the effects of inclement weather and natural disasters, loss of markets, the fact that the Company does not operate all of its properties, industry conditions and competition, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the ability to access qualified personnel and oilfield services,decisions by regulators and the ability to access sufficient capital from internal and external sources. Readers are cautioned not to place undue reliance on the forward-looking statements as the assumptions used in the preparation of such information,

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although considered reasonable at the time of preparation, may prove to be imprecise. Actual results, performance or achievements could materially differ from those expressed or implied in such forward-looking statements and accordingly, no assurance can be given that any of the events anticipated by forward looking statements will transpire or occur, or if any of them do so, what benefit the Company will derive therefrom.

Specific forward-looking statements include the following: Corval’s business strategy and focus, capital expenditure budget, drilling and completion plans, anticipated production levels, projected land acquisitions, future debt levels, operating and transportation costs, and other financial results, source of funding of the Company’s capital program, tax pools, future production, and decline rates.

OVERVIEW OF PERFORMANCE AND DISCUSSION OF OUTLOOK

Overview

Production for the year ended December 31, 2013 averaged 526 bopd. The fourth quarter of 2013 saw an increase in production as result of having a full quarter of production from the wells that were placed on production late in the third quarter. For the fourth quarter, the Company averaged 777 bopd with associated cash flow of $3.1 million. New wells drilled in December allowed Corval to exit the year at 1,200 bopd.

Crude oil pricing continued to be strong in 2013, averaging $89.91/bbl in the field, before recognizing losses from the hedgingprogram. Crude oil prices have remained strong after the year end, with prices (WTI in $US) remaining near $100.00/bbl. In addition the Canadian dollar has continued to decline in value since year end thus further increasing the field price received.The Company continues to receive solid netbacks due to its high quality crude oil and low operating costs. The Company completed its construction of the Sinclair oil battery in the fourth quarter. The effects were immediate, operating costs decreased to under $15.00/bbl in the fourth quarter prior to workovers. Operating costs have continued to trend downward into 2014. The Company has budgeted that all in operating costs for 2014 will average $16.00/bbl compared to $19.41/bbl for 2013. Field netbacks averaged $56.43/bbl for the year ended December 31, 2013. The Company anticipates that netbacks will remain high, in excess of $55.00/bbl if crude oil prices remain above $90.00/bbl at the field.

During 2013, Corval entered into four commodity price contracts. The contracts fixed 100 bopd of Edmonton Par at $90.02 from May 2013 until December 2013, 100 bopd of WTI at $101.35 Cdn. from August 2013 to July 2014 and 300 bopd of WTI at an average price of $100.87 Cdn. from January 2014 to December 2014. On February 12, 2014, the Company entered into another crude oil commodity price contract to fix 100 bopd of WTI from August 1, 2014 until December 31, 2014 at a price of $103.14 Cdn. per barrel.

During the year, Corval spent $24.4 million on capital expenditures, to drill 15 gross (12.75 net) developmental wells. As at December 31, 2013, 14 gross (12.5 net) of the wells were completed and on production. The one remaining well was completed and brought on to production in January. The Company also spent $2.6 million on exploration and evaluation assets during the year to extend the Bakken and Lodgepole plays. The expenditures included land acquisitions and the drilling of one well in December.

During the year ended December 31, 2013, Corval used the net proceeds from its 2012 financing to repay $545,193 of promissory notes, including accrued and unpaid interest, and $7,450,000 of bank debt. In April, Corval called $8.0 million on its line of equity, and in September, the remaining $9.0 million of the line of equity financing was called to fund the ongoingcapital program.

In the fourth quarter, Corval reviewed its credit facilities with the lender, and increased its available line of credit to $15.0million and is subject to review by June 2014. As of the date hereof, there is approximately $2.0 million drawn on the line of credit..

Corporate

Grey Market Trading

Corval’s common shares are not listed, traded or quoted on any stock exchange. Registered dealers may facilitate trades of the Company's common shares to eligible purchasers through the grey market. Since grey market securities are not traded or quoted on an exchange or interdealer quotation system, investor's bids and offers are not collected in a central spot so markettransparency is diminished and best execution of orders is difficult. The sale of the Company's common shares through the greymarket is at the shareholder's own risk and the Company does not endorse such trades.

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The Company understands that Acumen Capital Partners Limited and AltaCorp Capital, both registered dealers, have previously organized trades in Corval’s common shares on the grey market. Please contact these dealers with inquiries regarding trading your common shares on the grey market.

If you are interested in selling your Corval shares, to find a contact, you may either: i) Look on our website at www.corvalenergyltd.com;ii) E-mail us at [email protected].

2013 Results of Operations

Although Corval had been incorporated in 2011, Corval formally commenced operations in October, 2012. Therefore, the consolidated financial statements and the Management’s Discussion and Analysis reflect operations only after October 2012, as a result, no comparison of operations has been provided for the three months ended December 31, 2013 and 2012.

Average daily sales volumes were 777 bopd and 526 bopd for the three and twelve months ended December 31, 2013. The production for the fourth quarter of 2013 is an increase of 320 bopd from the third quarter production or 70%. The increase inproduction was due to having a full quarter of production from the wells that were drilled and place on production late in the third quarter. Production in 2013 of 526 bopd increased from 221 bopd in 2012, due to increased drilling activity.

Revenues in the fourth quarter, comprised entirely of oil sales, were $6,010,570, representing an average price of $84.04 per bbl for the three-month period, and $17,253,461, representing an average price of $89.91 per bbl, for the year, both prices priorto the impact of the hedging program. The revenues for the three-month period ending December 31, 2013 were $1,693,765higher than the three-month period ending September 30, 2013, a 39% increase. The average price for the fourth quarter of 2013 was $18.36 (18%) per bbl lower than the average price for the third quarter of 2013. Revenue for 2012 was $1,364,553.

The Company reported a net loss of $766,698 for the year ended December 31, 2013 versus a loss of $8,774,535 in 2012. The 2012 loss included an impairment of property, plant and equipment of $7,287,000.

For the three months ended December 31, 2013, the Company recorded a net income of $27,196, reflecting increased production. The Company incurred capital expenditures of $5,837,598 during the three-month period ended December 31, 2013, primarily related to the drilling, completing, equipping, and tying-in four wells in the Sinclair area of Manitoba. Two additional wells were completed, equipped and tied-in that were drilled in the third quarter. The total capital spent was $24,397,259 for the year ended December 31, 2013 before acquisitions and divestitures as compared to $1,357,855 for the year ended December 31, 2012. The 2013 capital program included the drilling of 15 gross development wells and the building of an oil battery. During the year the Company incurred $2,558,131 of exploration and evaluation expenditures on the acquisition of land and seismic and the drilling of one well in a new area. Corval will continue to evaluate this new area over the next year.

Funds from operations for the three and twelve months ended December 31, 2013 were $3,116,079 and $8,206,442 respectively versus funds used in operations of $288,633 for 2012. The funds from operations for the fourth quarter of 2013 represents an increase of $1,156,843, or 59%, from the third quarter of 2013 resulting from both an increase in production andfrom a decrease in operating costs.

OUTLOOK

Capital Expenditure Program-2014

In January, 2014, the Board approved the 2014 capital program of $34.8 million, which includes drilling a total of 19 (16.25 net) wells. As of March 31, 2014, Corval has drilled, completed, equipped and placed on production 5 gross (4.3 net) wells.The increased production associated with the first quarter 2014 drilling program will not be realized until the second quarter of 2014 as the wells came on production in the last week of March. The 2014 capital program also included up to $2.0 million in land acquisitions, $1.0 million in seismic and $1.0 million in facility upgrades that are anticipated to be required to handle the increased production at Sinclair. The all-in cost to drill, complete and bring on production continues to be approximately $1.7million per well, which means with current netbacks, the Lodgepole wells are expected to payout in less than a year. We are pleased that the initial part of our first quarter capital program was completed on budget. As many of you are aware, Southwestern Manitoba has had an unusually cold winter, therefore completing the program on budget is a tribute to Corval’s technical team. Once road bans are lifted in Manitoba, Corval has plans to drill 6 gross (4.7 net) wells in the second and thirdquarters in Manitoba, weather permitting.

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Corval is moving forward as planned, with well costs and well performance on target. With production currently in excess of 1,000 bopd, and the continuation of strong crude oil prices, cash flows are expected to remain strong.

Corval is in a unique position for a junior/emerging oil company as it is:

i) well-financed with a $15.0 million unutilized line of credit that is expected to be increased based on current reserves,

ii) expected to generate cash flows in excess of $20 million in 2014 based on current production and netbacks that are over $55.00 per bbl,

iii) well-positioned with a strong management team, directors and major investors to take advantage of additional opportunities that will arise in Western Canada, and

iv) continuing to capitalize on the potential of its significant multi-zone light oil resource plays in Manitoba.

IMPACT OF CURRENT ECONOMIC VOLATILITY AND UNCERTAINTY

Crude oil prices have remained strong into 2014, as WTI ($US) has averaged approximately $100.00/bbl for the first quarter.Increased crude oil production in Western Canada and the United States has resulted in ongoing pipeline takeaway constraints for crude oil. Currently Corval has not been impacted, however we continue to monitor the situation. From November 2013 to February 2014, the differential between WTI and Edmonton Par price widened from the $7.00/bbl range to over $15.00/bbl. In mid-February the differential once again narrowed to the $7.00 bbl range. If this differential widens again, it would reduce Corval’s cash flow in future months. Corval is currently in a strong position to continue its planned capital expenditures program. The Company will continue to monitor its funds from operations and available credit facilities to ensure its ability to meet its planned capital program for 2014 and beyond. Corval operates most of its operations and can therefore remain flexible to reduce or increase its capital program as required.

RESULTS OF OPERATIONS

The following tables summarize various aspects of producing properties for 2013 and 2012. Although Corval had been incorporated in 2011, Corval formally commenced operations in October, 2012. Therefore, the financial statements and the Management’s Discussion and Analysis reflect operations only after October 2012, and as a result, no comparison of operations has been provided for the three months ended December 31, 2013 and 2012.

Production

Year ended December 31 2013 2012

Oil, condensate, & ngls – bbls/d 526 221

Production for 2013 increased 305 bbls/d or 138% compared to 2012 as a result of successfully drilling 16 gross (13.75 net) wells throughout 2013. New wells were brought on production in late December, which resulted in increased production levels in the first quarter of 2014.

Revenue

Year ended December 31 2013 2012Sales - oil $ 17,253,461 $1,364,553Average price

Oil ($/bbl) $89.91 $82.39

The Company’s crude oil production is light, sweet oil with an API of 34 - 38 degrees. The realized average price for the year ended December 31, 2013 is $7.52 per bbl (9%) higher than the price of $82.39/bbl for the year ended December 31, 2012. The crude oil is priced from Cromer, Manitoba, and traded at a discount to WTI in $CDN of approximately $9.00/bbl over the year.

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Commodity price contracts / hedging

Year ended December 31 2013 2012Realized loss on commodity price contract (cash portion)Unrealized loss on commodity price contract (non-cash portion)

$ (192,717)(187,359)

$ --

Total commodity price contract expense $ (380,076) $ -Per bblCash portion of commodity price contract – loss (gain)Non-cash portion of commodity price contract – loss (gain)Total commodity price contract expense – loss (gain)

$ (1.00)$ (0.98)$ (1.98)

$ -$ -$ -

As at December 31, 2013, the Company had three crude oil swaps in-place fixing the price of future production for a specific period of time. For the year ended December 31, 2013, the Company recorded a realized commodity contract loss of $192,717 (2012 - $nil) and an unrealized commodity contract loss of $187,359 (2012 - $nil).

The Company had the following risk management contracts outstanding as at December 31, 2013:

Commodity Volume Sold Term Pricing Fair Value LiabilityOil 100 bbl per day Jan 1, 2014 –July 31, 2014 $101.35 $52,102Oil 200 bbl per day Jan 1, 2014 –Dec 31, 2014 $100.80 $95,484Oil 100 bbl per day Jan 1, 2014 –Dec 31, 2014 $101.02 $39,773

$187,359

Royalties

Year ended December 31 2013 2012Crown royaltiesFreehold royaltiesOverriding royalties

$ 18,0572,364,504

126,130

$ 15,894198,911

12,827Total royalties $2,508,691 $ 227,632Per boePercentage of revenues

$ 13.0714.7%

$ 13.7416.7%

On a per boe basis royalties decreased $0.67 or 5% as a result of drilling news wells in 2013 on freehold lands with lower royalty rates. Most of the Company’s production is from freehold lands, which have royalty rates of between 12.5% and 18%, and provide no incentives for drilling.

Operating and transportation costs

Year ended December 31 2013 2012Operating costsExpensed workovers

$3,072,999652,733

$ 389,804140,141

Total operating costs $3,725,731 $ 529,945Per boe

Operating costs before workoversExpensed workoversTotal operating costs

$ 16.01$ 3.40$ 19.41

$ 23.53$ 8.47$ 32.00

The operating costs averaged $19.41 per bbl for 2013, a decrease of $12.59 or 39% compared to 2012. Operating costs for 2013 consists of $16.01 for regular operating costs and $3.40 per bbl for expensed workovers. Overall operating costs decreased due to increased production that lowered the per boe cost on fixed costs and also due to the construction of the Sinclair oil battery that reduced trucking costs significantly. The Company performed 17 workovers in 2013 on wells acquired from the private trust, including bottomhole pump and packer repairs that were required from the outset at acquisition and werenecessary to maintain production. Maintenance on the water disposal well was also done to prepare it for increased disposal requirements. The operating costs per bbl going forward are expected to be in the range of $16.00 per bbl including workovers that are required from time to time.

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Operating netbacks

Year ended December 31 2013 2012Per boe

RevenuesCommodity price contract expense – realized RoyaltiesOperating costs before workovers

$ 89.91(1.00)

(13.07)(16.01)

$ 82.39-

(13.74)(23.53)

Netback per boe before workovers $ 59.83 $ 45.12Workovers (3.40) (8.47)

Operating Netback per boe $ 56.43 $ 36.65

Netbacks for the year ended December 31, 2013 of $56.43 is $19.78 or 54% higher than the netbacks for the year ended December 31, 2012, due to the increases in oil prices combined with lower operating costs as a result of operating efficienciesachieved through the construction of the Sinclair oil battery. Netbacks for the Manitoba properties are generally higher than industry average due to strong prices for the light sweet crude produced in the region, combined with reasonable operating costs. The Company expects that trend to continue into 2014.

General and administrative expenses

Year ended December 31 2013 2012Human resources costs (salaries and benefits)Professional feesOccupancy costsOffice supplies, software, services and otherCosts associated with various financing and private placementsOverhead recoveries

$ 1,909,401310,546417,557536,807

-(554,431)

$ 311,463113,810

74,35986,973

353,701(44,697)

Total $ 2,619,880 $ 895,609Per boe $13.65 $54.07

General and administrative expenses for the year ended December 31, 2013 were $2,619,880 compared to $895,609 for 2012. The increase is due to a full year of operations and also the hiring of additional staff and consultants. These increases wereoffset by higher overhead recoveries due to the increased capital activity in 2013. General and administrative expenses in 2012included $353,701 in non-recurring costs associated with the efforts required to obtain financing. The cost per boe continues totrend lower and is expected to be less than $10.00/boe in 2014 as production increases and the cost of G&A remains relatively flat.

Depletion and depreciation, and impairment


Depreciation and depletionImpairment of property, plant, and equipment

$6,703,366-

$ 691,3747,287,000

Total depreciation, depletion, and impairment $6,703,366 $7,978,374Per boe $34.93 $481.70

Depletion and depreciation, and impairment charges for 2012 include $7,287,000 of impairment on all CGUs (cash-generating units). Total impairment losses of $7,287,000 were recognized in respect of producing oil and gas properties. The recoverable amounts of the Company’s CGU’s were estimated at fair value less costs to sell, based on the net present value of the after-tax cash flows from oil reserves, using reserves estimated by independent reserve evaluators.

On a per boe, depreciation and depletion (before impairment) was $34.93 for 2013 and $41.74 for 2012. The reduction in depreciation and depletion is due to increases in year end reserves and also due to the effects of the 2012 impairment on the depletable base in 2013.

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Funds from (used in) operations and net loss


Funds from (used in) operations$/share - basic

Net loss$/share - basic

$ 8,206,442$0.14

$ (766,698)$ (0.01)

$(288,633)$(0.05)

$(8,474,535)$(1.53)

The increase in funds from operations is due to increased in netbacks received in 2013 along with increased production. The funds used in operations for 2012 is attributable to the non-recurring general and administrative costs required to complete theacquisition of FGDT.

Capital and Exploration and Evaluation Expenditures

Year ended December 31 2013 2012Development Expenditures (Property, plant & equipment)

Land purchases Geological and geophysicalDrilling and completionEquipping and facilitiesOther

$ 11,155350,424

22,593,2661,409,258

33,156

$ 63,81034,856

1,196,94157,1705,078

Total development expenditures $24,397,259 $ 1,357,855

Exploration and Evaluation ExpendituresLand purchases Geological and geophysicalDrilling and completion

$ 1,422,500108,352

1,027,279

$ ---

Total exploration and evaluation expenditures $ 2,558,131 $ -

Development expenditures for the year ended December 31, 2013 were $24,397,259. Corval drilled 15 (12.75 net) development wells during 2013 compared to one in 2012, and completed, equipped, and tied-in 14 gross (12.5 net) wells and constructed an oil battery as part of the capital program in Sinclair, Manitoba.

Exploration and evaluation expenditures were $2,558,131 for the year ended December 31, 2013. Exploration and evaluation expenditures include land acquisitions in a new area and the drilling of one well on the acquired lands.

Acquisition and divestiture

a) On May 15, 2013, the Company acquired certain assets in Manitoba for cash consideration of $3,291,910. The consideration paid was determined to be equivalent to fair value.

The purchase price allocation is as follows:

Property, plant, and equipmentDecommissioning liability

$ 3,326,551(34,641)

Net assets 3,291,910

Cash consideration paid $ 3,291,910

b) In April, 2013, the Company disposed of their working interest in two non-core wells for cash proceeds of $1,874,318.

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SUMMARY OF QUARTERLY FINANCIAL DATA

The following table summarizes quarterly financial results:

Quarter ended

Dec-13$

Sep-13$

Jun-13$

Mar-13$

Dec-12$

Sep-12$

Jun-12$

Mar-12$

Petroleum and natural gas sales 6,010,570 4,316,805 4,474,797 2,451,289 1,364,553 - - -Funds from (used in) operations 3,116,079 1,959,236 2,255,231 875,690 (361,877) - - -Income (loss) 27,196 137,107 (291,593) (639,408) (8,474,535) - - -Production bopd 777 457 546 318 221 - - -Average price/bbl* $84.04 $102.40 $90.13 $85.75 $82.39 - - -*before impact of commodity price contracts

SUMMARY OF ANNUAL FINANCIAL DATA

The following table summarizes the annual financial results:

Year ended 2013$

2012$

Revenues 17,253,461 1,364,553

Net loss (766,698) (8,474,535)

Total assets 49,921,735 36,525,377

Long-term debt $nil $nil

LIQUIDITY AND CAPITAL RESERVES

The Company started 2013 with a working capital surplus of $2,802,567, which included the remaining promissory notes of $568,828 owing. The Company raised $145,600 through the issue of 208,000 shares through a private placement in February 2013. On April 5, 2013, the Company requested a draw of $8 million from the line of equity, which resulted in $7,510,437 in proceeds net of share issuance costs from the sale of 11,428,571 common shares. Promissory notes, valued at $545,191, were repaid during 2013, as well as the bank loan of $7,450,000. On September 23, 2013, the Company requested the remaining $9 million balance from the line of equity, which resulted in $8,507,000 in proceeds net of share issuance costs from the sale of 12,928,572 common shares. The Company drilled 16 gross (13.75 net) wells, and completed, equipped, and tied-in 14 gross (12.5 net) wells and constructed the oil battery at Sinclair, spending a total of $26,955,390 in 2013. As at December 31, 2013,the Company had a working capital deficiency of $1,241,845, which includes the remaining promissory notes of $25,292 owing and excludes the commodity price contracts.

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The Company monitors its capital program based on available funds, which is the combination of working capital and remaining unused line of credit, as calculated below:

December 31, 2013 December 31, 2012Current assets $ 4,731,446 $ 12,997,246Accounts payable and accrued liabilities(2) (5,947,999) (2,175,851)Promissory notes (25,292) (568,828)Net working capital (1,241,845) 10,252,567

Maximum value of bank loan 15,000,000 8,000,000Amount drawn - (7,450,000)Unutilized bank loan 15,000,000 550,000

Total available line of equity 31,000,000 31,000,000Amount drawn (31,000,000) (13,950,000)Unutilized line of equity - 17,050,000Net available funds $ 13,758,155 $ 27,852,567

Net debt (1,241,845) -Annualized cash flow (1) 12,465,140 -Net debt to annualized cash flow 0.1 -

(1) Based on the last quarter’s cash flow from operations annualized (2) Excludes non-cash Commodity Price Contracts

The Company’s approach to capital management is to present to the Board of Directors a capital program and financial budget and requesting funding and approval. Under this program, the Company plans to maintain a debt to equity ratio of less than 1:1and to maintain a debt to cash flow ratio of less than 1:1. The Company’s 2014 capital program was presented to the Board of Directors, and a capital program of $34.7 million was approved in January 2014. The Company expects that with the bank loan and anticipated cash flow that it will be able to fund its full 2014 capital program and maintain a debt to cash flow ratio of less than 1:1. The Company operates most of its properties and can therefore remain flexible to reduce or increase its capital program as required.

During the year ended December 31, 2013, the Company negotiated a new bank loan. The new bank loan is a revolving operating demand loan that had an initial borrowing base of $9 million, which through additional drilling and added reserves, was increased to $15.0 million as at December 31, 2013. The revolving operating demand loan bears an interest rate of the Bank’s Prime Rate plus 0.75% and a standby fee of 0.25% on the undrawn portion. The new bank loan is covered by a fixed and floating $50 million demand debenture over all of the assets of the Company. The Company is required to comply with a working capital financial covenant. The next review date is June 1, 2014. The Company is compliant will all covenants.

SHARE DATA

Transactions regarding Corval’s shares, options, acquisition warrants and performance warrants are presented in the consolidated financial statements at December 31, 2013 on the consolidated statement of changes in equity and also in Note 12 of the consolidated financial statements.

The Company has 70,391,054 shares outstanding as of the date of this MD&A.

EVENTS AFTER REPORTING PERIOD

Share option issues

Subsequent to the year end, an additional 335,000 common share options exercisable at $0.90 per common share, expiring in five years, were issued to employees. As of the date hereof, there are 6,450,000 options outstanding with a weighted average exercise price of $0.72 per share.

Performance warrant issues

Subsequent to the year end, an additional 278,305 performance warrants with an exercise price of $0.70 per performance warrant, expiring in five years, were issued to employees and directors. As of the date hereof, there are 7,018,305 performancewarrants outstanding with a weighted average exercise price of $0.70 per warrant.

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Financial hedge

On February 12, 2014, the Company entered into a crude oil commodity price contract to sell 100 barrels of production per day from August 1, 2014 until December 31, 2014 at a price of $103.14 per barrel.

TRANSACTIONS WITH RELATED PARTIES

The corporate secretary is a partner in a law firm that provides legal services to the Company. For the year ended December 31, 2013, the Company recorded $168,003 (2012 - $230,642) in general and administrative expenses related to this law firm. As at December 31, 2013, $20,363 (2012 - $48,655) remained in accounts payable.

TAX POOLS

The Company has a deferred tax asset of approximately $6.0 million which has not been recognized. The deferred tax asset arises as the Company’s losses and tax pools are greater than the cost base of the assets.

The Company has the following combined tax pools available to reduce future taxable income:

2013($Millions)

Canadian oil and gas property expense 15.8Canadian development expense 29.7Canadian exploration expense 1.5Undepreciated capital cost 7.6Non-capital losses carried forward – expiring between 2027 and 2033 10.0Share issue costs 1.7Closing Balance 66.3

COMMITMENTS

The Company is carrying a lease on its office space and office equipment:

December 31, 201320142015-20192020-2022

$ 150,337809,150334,265

Total $1,293,752

RISK FACTORS

Investors should carefully consider the risk factors set out below and consider all other information contained herein. Additional risks and uncertainties not currently known to the management of the Company may also have an adverse effect on the Company's business and the information set out below does not purport to be an exhaustive summary of the risks affecting the Company.

Additional risk factors may be found in the consolidated financial statements at December 31, 2013 in notes 3 and 18.

Exploration, Development and Production Risks

Oil and natural gas exploration involves a high degree of risk, which even with a combination of experience, knowledge and careful evaluation the Company may not be able to overcome. There is no assurance that expenditures made on future exploration by the Company will result in new discoveries of oil in commercial quantities. It is difficult to project the costs of implementing a drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones and tools lost in the hole, the availability of adequatelytrained and experienced contractors and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

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The long-term commercial success of the Company depends on its ability to find, acquire, develop and profitably produce oil and natural gas reserves. No assurance can be given that the Company will be able to continue to locate satisfactory propertiesfor acquisition or participation. Moreover, if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive butdo not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents,shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or othergeological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverseeffect on future results of operations, liquidity and financial condition.

Recent economic risks

Many oil and natural gas producers are encountering challenges with low natural gas prices and increasing differentials on crude oil prices, and in accessing new equity capital, while credit conditions and availability may tighten despite low interestrates. Corval is positioned entirely in exploring and producing crude oil, which has maintained stronger pricing over the last few years. Crude oil pricing has been volatile due to world supply and demand factors, bottlenecks in North American transportation from production areas to refining areas. These factors have resulted in wider differentials between prices on the world market based on Brent pricing index, West Texas Intermediate (WTI) which is the North American benchmark, and Edmonton Par price, the Canadian benchmark price for light sweet crude oil. These factors, including wider or more volatile differentials is expected to continue in the near future.

Access to capital

The Company is dependent on access to equity or debt financing to fund working capital requirements and capital expansion programs when operating cash flows are not sufficient to do so. To date, sufficient capital has been obtained to meet the Company’s working capital and capital expansion requirements. Additional working capital requirements or further capital expansion that cannot be funded through operating cash flows or current cash on hand will require external financing, the availability of which is dependent on, for example, credit availability, economic conditions, and commodity prices.

Prices, Markets and Marketing of Crude Oil and Natural Gas

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is and will continue to be affected by numerous factors beyond its control. The Company's ability to market its crude oil and natural gas may depend upon its ability to contract capacity on pipelines that deliver products to commercial markets. The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and processing and storage facilities and operational problems affecting suchpipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowableproduction, the export of oil and natural gas and many other aspects of the oil and natural gas business.

The Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company's ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon prevailing oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions, in the United States and Canada, product “bottlenecks” caused by transportation capacity constraints, the actions of OPEC and Russia, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and gas would have anadverse effect on the Company's carrying value of its proved and probable reserves, borrowing capacity, revenues, profitabilityand cash flows from operations.

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Project Risks

The Company will manage a variety of small and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. The Company's ability to execute projects and market oil and natural gas will depend upon numerous factors beyond the Company's control, including:

the availability of drilling and related equipment; the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of storage capacity; the supply of and demand for oil and natural gas; the effects of inclement weather; unexpected cost increases; accidental events; the availability and productivity of skilled labour; and the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, the Company could be unable to execute projects on time, on budget or at all, and may not be able toeffectively market the oil that it produces.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment(typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities. To the extent the Company is not the operator of its oil and gas properties, the Company will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or controlthe activities of the operators.

Legal Proceedings

The Company may from time to time be subject to litigation and regulatory proceedings arising in the normal course of its business. The Company cannot determine whether such litigation and regulatory proceedings will, individually or collectively, have a material adverse effect on its business, results or operations and financial condition. To the extent expenses incurred inconnection with litigation or any potential regulatory proceeding or action (which may include substantial fees of attorneys andother professional advisors and potential obligations to indemnify officers and directors who may be parties to such actions) arenot covered by available insurance, such expenses could adversely affect the Company's cash position.

Environmental Risks

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and international, national, provincial, state and local law andregulation. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of same can result in the imposition of clean-up orders, fines and/or penalties, some of which may be material, as well as possible forfeiture of requisite approval obtained from the various governmental authorities. The discharge of greenhouse gas (“GHG”) emissions and other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it is in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or amaterial increase in the costs of production, development or exploration activities or otherwise adversely affect its financialcondition, results of operations or prospects.

Permits, Licences and Approvals

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease

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may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease willbe met. The termination or expiration of the Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on its results of operations and business.

Land Tenure

Crude oil and natural gas located in the Canadian western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms and on conditions set forth in provincial legislation including requirements to perform specificwork or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Risk management / commodity price contracts

The Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Company will not benefit from such increases and the Company may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements. Similarly, from time to time the Companymay enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declinesin value compared to the United States dollar, the Company will not benefit from the fluctuating exchange rate.

Additional risk factors may be found in the consolidated financial statements at December 31, 2013 in notes 3 and 18.

FINANCIAL INSTRUMENTS

The financial instruments are described in Note 18 in the consolidated financial statements at December 31, 2013.

CRITICAL ACCOUNTING ESTIMATES

A summary of Corval’s use of accounting estimates and judgments are summarized in Note 3 of the audited consolidated financial statements at December 31, 2013 and the policies for these accounting estimates continued except for those accounting policies noted in Note 4. The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses, and the accompanying disclosures. Estimates and underlying assumptions are reviewed on an ongoing basis and are based on management’s experience, expectations of future events, and other factors that are believed to be reasonable under the current circumstances. Uncertainty surrounding these assumptions and estimates could result in outcomes where the results may differ from these estimates and may require material adjustments to the carrying amount of the assets and liabilities into future periods.

In particular, the Company has identified the following areas where significant judgments, estimates, and assumptions are required.

i) Reserve and resource estimates

The process of estimating reserves is based on available geological, geophysical, engineering and economic data for the wells and reservoirs where the Company has a working interest. To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, many factors and assumptions are incorporated, including the estimates of oil and gas in place, expected reservoir characteristics and recovery rates, production techniques, future commodity prices, operating costs, and development costs, as well as assumed effects of regulation by governmental agencies. The Company estimates its reserves in accordance with National Instrument 51-101, and the Society of Petroleum Engineers’ rules in the Canadian Oil and Gas Evaluation Handbook (COGEH) through the services of an appropriately qualified firm, Sproule Associates Limited.

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As at December 31, 2013, the Company used the following forward price estimates in estimating its reserves:

Crude OilWest Texas Intermediate

(US$/bbl)Edmonton Par

Price (Cdn$/bbl)2014 94.65 92.642015 88.37 89.312016 84.25 89.632017 95.52 101.622018 96.96 103.14

Thereafter +1.5%/yr +1.5%/yr

The value and life of the reserves are important in determining:

a) Depletion charges, and the useful life of certain related assets, b) Provisions for decommissioning and estimates of when such activities could occur, c) The economic feasibility and commercial viability of exploration and evaluation assets and potential related

impairment, d) The existence of impairment of the carrying value of oil properties, and e) The recognition and carrying value of certain deferred tax assets and liabilities.

As the economic assumptions used in determining reserves may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change resulting in potential material changes in the related financial information.

ii) Exploration and evaluation expenditures

The application of the Company’s accounting policy for exploration and evaluation expenditure requires judgment to determine whether it is likely that future economic benefits are likely, either from future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence and value of reserves. Management may use reserve estimates, as well as economic circumstances, to determine possible impairment of exploration and evaluation expenditures, the timing of when a project reaches economic feasibility and commercial viability, and the value with which a project and related expenses may be promoted to property, plant, and equipment. These assumptions may change as new information becomes available, and may impact the future carrying value of exploration and evaluation expenditures.

iii) Units of production (“UOP”) and straight-line depreciation of oil and gas assets

Oil and gas property, plant, and equipment is depreciated by applying a ratio of production volumes over total proved and probable oil and gas reserves (the units of production (“UOP”) method) to the carrying value of each cash-generating unit (“CGU”). Specific, identifiable items of equipment may be depreciated separately using the straight-line method over its remaining useful life. These calculations require the use of estimates and assumptions, including the amount and duration of recoverable reserves, assessment of condition and life of the asset, and estimates of future capital expenditures. The calculationof the UOP rate of depreciation could be impacted by production fluctuations, changes to proved and/or probable reserves, changes in plans for future development, acquisitions or divestitures, or unforeseen operational issues. Changes in estimates are accounted for prospectively.

iv) Recoverability of oil and gas assets

The Company assesses each asset or CGU each reporting period to determine whether any indication of impairment exists. Management must apply judgment to assess whether indicators of impairment exist and the amount of impairment to recognize. A formal estimate of the recoverable amount is made, which is considered to be the higher of the fair value less costs to sell and value in use. The assessment of recoverable amounts require the use of estimates and assumptions such as long-term oil prices (considering current and historical prices, price trends and related factors), discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves (see 3(i) Reserve and resource estimates above) and operating performance (which includes production and sales volumes).

Fair value is determined as the amount that would be obtained from the sale of the asset in an arm’s length transaction between knowledgeable and willing parties. Fair value for oil and gas assets is based on economically recoverable crude oil and natural

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gas reserves and the present value of estimated future cash flows arising from the continued use of the assets, which includes estimates such as the cost of future expansion plans and eventual disposal, using assumptions that an independent market participant may take into account. Cash flows are discounted to their present value using a discount rate that reflects currentmarket assessments of the time value of money and the risks specific to the asset/CGU, resource type, and/or condition of entity compared to the market. Costs to sell are estimated, and usually determined to be negligible. Recent market transactionsare also taken into account.

In assessing value in use, the estimated future cash flows are also used, and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value inuse does not reflect future cash flows associated with improving or enhancing an asset’s performance.

These estimates and assumptions are subject to risk and uncertainty, therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs.

v) Decommissioning costs

Decommissioning costs are expenditures required to abandon wells and pipelines, retire equipment, and/or reclaim associated sites when an asset or property comes to the end of its operating life. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of newrestoration techniques, and/or experience at other production sites. The expected timing of expenditures can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. The Company assesses its decommissioning provision at each reporting date, and the provision at that date represents management’s best estimate of the present value of the future decommissioning costs required.

Significant estimates and assumptions are made in determining these inputs to the provision for decommissioning, and as a result, there could be significant adjustments to the provisions established which would affect future financial results.

vi) Value of deferred tax assets and/or liabilities

Judgment is required in determining whether deferred tax assets are recognized in the consolidated statements of financial position. Deferred tax assets, including those arising from unutilized tax losses, require management to assess the likelihoodthat the Company will generate sufficient taxable earnings in future periods to use these tax assets. Assumptions about the generation of future taxable profits depend on management’s estimates of future cash flows. These estimates of future taxableincome are based on forecast cash flows from operations, which are, in turn, impacted by production and sales volumes, oil and natural gas prices, operating costs, decommissioning costs, capital expenditures, acquisition or divestiture of assets or properties, acquisition or retirement of debt, dividends and other capital management transactions. Judgment is also required regarding the application of existing tax laws in each jurisdiction.

To the extent that future cash flows and taxable income differ significantly from estimates, or future changes in tax laws or rates occur, the value of deferred tax assets or liabilities recorded at the reporting date could be impacted.

vii) Fair value hierarchy

If the fair value of financial assets and financial liabilities recorded in the Consolidated Statements of Financial Position cannot be derived from active markets, then management must determine fair value by using valuation techniques such as discounted cash flow models. The inputs to these models are taken from observable markets where possible, but if this is not feasible, other judgments include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in circumstances orassumptions about these factors could affect the reported fair value of financial instruments.

viii) Contingencies

By their nature, contingencies will only be resolved when one or more uncertain future events occur or fail to occur. The assessment of the existence, likelihood of occurrence, and potential value of contingencies inherently involves the exercise ofsignificant judgment and the use of estimates regarding the outcome of future events.

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ix) Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future depletion and depreciation and asset impairment.

x) Share-based compensation

Share-based compensation calculations are subject to estimated stock volatility, forfeiture and exercise rates, and the future attainment of performance criteria. Future net earnings, contributed surplus, and shareholders’ equity can be affected through changes in these estimates.

CHANGES IN ACCOUNTING POLICIES Future changes in accounting policy are described in note 4 of the Consolidated Financial Statements.

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CONSOLIDATED FINANCIAL STATEMENTS

CORVAL ENERGY LTD. CONSOLIDATED FINANCIAL STATEMENTS REPORT OF MANAGEMENT

To the Shareholders of Corval Energy Ltd. (“the Company”);

We are responsible for the preparation and fair presentation of the Consolidated Financial Statements, as well as the financialreporting process that gives rise to such Consolidated Financial Statements. Fulfilling this responsibility requires the preparation and presentation of our Consolidated Financial Statements in accordance with Canadian Generally Accepted Accounting Principles, based on International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), and includes certain estimates that Management has determined to be reasonable in order to be sure that the Consolidated Financial Statements are presented fairly in all material aspects.

We are responsible for developing and implementing internal controls over the financial reporting process. These controls are designed to provide reasonable assurance that the Company’s financial transactions are accurately recorded, that the Consolidated Financial Statements realistically report the Company’s operating and financial results, and the Company’s assets are safeguarded. We believe that our internal controls have operated effectively for the year ended December 31, 2013. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Ernst & Young LLP, an independent firm of chartered accountants, was appointed by the Company’s shareholders to audit the Consolidated Financial Statements of the Company and to provide an independent professional opinion. Their report follows the Report of Management.

To ensure the integrity of our financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities.

Our Board of Directors has reviewed and approved the Consolidated Financial Statements and related notes with management and Ernst & Young LLP as of the date below.

(signed) “Thomas Stan” (signed) “Jim Screaton” President and Chief Executive Officer Vice President Finance and Chief Financial Officer

April 24, 2014

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CORVAL ENERGY LTD. CONSOLIDATED FINANCIAL STATEMENTS

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Corval Energy Ltd.

We have audited the accompanying consolidated financial statements of Corval Energy Ltd., which comprise the consolidated statements of financial position as at December 31, 2013 and 2012 and the consolidated statements of loss and comprehensive loss, changes in equity and cash flows for the years then ended, and a summary of significant accounting policies and explanatory information.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, 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 audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors 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 ofexpressing 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 auditopinion.

Opinion

In our opinion, the financial statements present fairly, in all material respects, the financial position of Corval Energy Ltd. as at December 31, 2013 and 2012 and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards.

Calgary, Alberta

April 24, 2014 Chartered Accountants

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CORVAL ENERGY LTD. Consolidated Statements of Financial Position

As at December 31, 2013 and 2012

NoteDecember 31,

2013December 31,

2012AssetsCurrent assets:

Cash Trade and other receivablesPrepaid expenses

18$ 2,160,543

2,363,634207,269

$ 12,050,366 761,679185,201

4,731,446 12,997,246

Exploration and evaluation 6 2,558,131 -Property, plant and equipment 7,8 42,632,158 23,528,131

Total Assets $ 49,921,735 $ 36,525,377

Liabilities and Shareholders’ Equity

Current Liabilities:Accounts payable and accrued liabilities 18 $ 5,947,999 $ 2,175,851Bank loan 9 - 7,450,000Commodity price contract 18 187,359 -Promissory notes 10 25,292 -

6,160,650 9,625,851

Promissory notesDecommissioning obligations

1011

-1,962,138

568,8281,807,338

Total Liabilities $ 8,122,788 $ 12,002,017

Shareholders’ EquityShare capital 12 49,092,396 32,929,358Contributed surplus 12(e) 1,947,784 68,537Deficit (9,241,233) (8,474,535)Total Shareholders’ Equity 41,798,947 24,523,360

Total liabilities and shareholder’s equity $ 49,921,735 $ 36,525,377

Signed on behalf of the Board of Directors:

“Signed” “Signed”_______________________________________ ________________________________________ Thomas Stan, Director David Eastham, Director

The notes are an integral part of these consolidated financial statements.

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CORVAL ENERGY LTD. Consolidated Statements of Loss and Comprehensive Loss

For the years ended December 31, 2013 and 2012

NoteYear ended

December 31, 2013Year ended December

31, 2012RevenuePetroleum salesRoyalties

$ 17,253,461(2,508,691)

$ 1,364,553(227,632)

14,744,770 1,136,921

Realized loss on commodity price contract 18 192,717 -Unrealized loss on commodity price contract 18 187,359 -

14,364,694 1,136,921

ExpensesOperating General and administrativeShare-based compensationDepletion and depreciationProperty, plant, and equipment impairment

12(e)78

3,725,7312,619,8801,879,2476,703,366

-

529,945895,609

68,537691,374

7,287,00014,928,224 9,472,465

Finance expenses 14 203,168 138,991

Net loss and comprehensive loss for the period $ (766,698) $ (8,474,535)


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CORVAL ENERGY LTD. Consolidated Statements of Changes in Equity


Note

Number of common

sharesShare

CapitalContributed

surplus Deficit

TotalShareholders’

EquityBalance at December 31, 2012 45,825,911 $ 32,929,358 $ 68,537 $ (8,474,535) $ 24,523,360

Private placement 12(iv) 208,000 145,600 - - 145,600Shares issued under the line of

equity 12(v,vi) 24,357,143 17,050,001 - - 17,050,001Share issue costs - (1,032,563) - (1,032,563)Share based expense 12(e) - - 1,879,247 - 1,879,247Net loss for the year - - - (766,698) (766,698)

Balance at December 31, 2013 70,391,054 $49,092,396 $ 1,947,784 $ (9,241,233) $ 41,798,947

Note

Number of common

sharesShare

CapitalContributed

surplus Deficit

TotalShareholders’

EquityBalance at December 31, 2011 10 $ 10 $ - $ - $ 10

Private placementsShares issued to acquire

Foundation Group Development Trust

Warrants exercisedFinancing at December 17, 2012Share issue costsShare based expense Net loss for the year

12(a)(i)

12(a)(ii)12(d)

12(a)(iii)12(a)(iii)

12(e)

1,694,999

20,803,286268,375

23,059,241---

1,096,001

16,642,629214,700

16,141,469(1,165,451)

--

-

----

68,537-

-

-----

(8,474,535)

1,096,001

16,642,629214,700

16,141,469(1,165,451)

68,537(8,474,535)

Balance at December 31, 2012 45,825,911 $ 32,929,358 $ 68,537 $ (8,474,535) $ 24,523,360


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CORVAL ENERGY LTD.Consolidated Statements of Cash Flows


NoteYear ended

December 31, 2013Year ended

December 31, 2012

Operating activities:Net loss for the periodAdd back: finance expense

(interest disclosed in financing activities)

Non-cash items:Depletion and depreciationImpairment of property, plant and equipmentShare based compensationUnrealized loss on commodity price contract

$ (766,698)

203,168

6,703,366-

1,879,247187,359

$ (8,474,535)

138,991

691,3747,287,000

68,537-

8,206,442 (288,633)Net changes in non-cash working capital items 15 (861,411) 600,633Net cash flows from operating activities 7,345,031 312,000

Investing activities:Expenditures – property, plant, and equipment Expenditures – exploration and evaluationAcquisition of oil and gas propertyDisposition of oil and gas propertyPayout to dissenting unitholdersCash acquired from acquisition of Foundation Group

Development TrustNet changes in non-cash working capital items

5

15

(24,397,259)(2,558,131) (3,291,910)

1,874,318-

-3,009,536

(1,357,855)---

(113,318)

400,902551,677

Net cash flows from investing activities (25,363,446) (518,594)

Financing activities:Proceeds from share issuances, net of issue costsExercise of acquisition warrantsRepayment of promissory notesAdvances from /(Repayment) of bank loanInterest paid

12(d)10914

16,163,038-

(545,193)(7,450,000)

(39,253)

16,072,019214,700

(4,506,515)550,000(73,244)

Net cash flows from financing activities 8,128,592 12,256,960

Increase (decrease) in cash and cash equivalents during the year (9,889,823) 12,050,366

Cash and cash equivalents, beginning of the year 12,050,366 -

Cash and cash equivalents, end of the year $ 2,160,543 $ 12,050,366


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Corval Energy Ltd. Notes to the Consolidated Financial Statements For the years ended December 31, 2013 and 2012

1. Nature of operations:

Corval Energy Ltd. (“Corval” or the “Company”) is an oil and gas exploration, development and production Company based in Calgary, Alberta, Canada. The Company conducts its operations in the Western Canadian Sedimentary basin in Alberta and the Williston basin in Manitoba and Saskatchewan. The consolidated financial statements of the Company as at December 31, 2013 comprise the Company and its wholly owned subsidiaries. Corval Energy Ltd. is domiciled in Canada at Suite 2400, 500 – 4th Avenue SW, Calgary, Alberta T2P 2V6.

The consolidated financial statements were authorized for issue by the Board of Directors on April 24, 2014.

2. Basis of preparation:

(a) Statement of compliance:

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards “IFRS” as issued by the International Accounting Standards Board “IASB”.

(b) Basis of measurement:

The consolidated financial statements have been prepared on the historical cost basis except for the derivative financial instruments which are measured at fair value. The methods used to measure fair value are discussed in notes 4 and 18.

These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency.

(c) Basis of consolidation:

The consolidated financial statements comprise the financial statements of Corval Energy Ltd. and its inactive subsidiaries, Foundation Group Development Trust “FGDT” and 1688869 Alberta Ltd., which are wholly-owned by the Company. Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

3. Use of estimates and assumptions:

The preparation of consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses, and the accompanying disclosures. Estimates and underlying assumptions are reviewed on an ongoing basis and are based on management’s experience, expectations of future events, and other factors that are believed to be reasonable under the current circumstances. Uncertainty surrounding these assumptions and estimates could result in outcomes where the results may differ from these estimates and may require material adjustments to the carrying amount of the assets and liabilities into future periods.

In particular, the Company has identified the following areas where significant estimates and assumptions are required.

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3. Use of estimates and assumptions (continued):

i) Reserve and resource estimates

The process of estimating reserves is based on available geological, geophysical, engineering and economic data for the wells and reservoirs where the Company has a working interest. To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, many factors and assumptions are incorporated, including the estimates of oil and gas in place, expected reservoir characteristics and recovery rates, production techniques, futurecommodity prices, operating costs, and development costs, as well as assumed effects of regulation by governmental agencies. The Company estimates its reserves in accordance with National Instrument 51-101, and the Society of Petroleum Engineers’ rules in the Canadian Oil and Gas Evaluation Handbook (COGEH) through the services of an appropriately qualified firm, Sproule Associates Limited.

As at December 31, 2013, the Company used the following forward price estimates in estimating its reserves:

Crude OilWest Texas Intermediate

(US$/bbl)Edmonton Par

Price (Cdn$/bbl)2014 94.65 92.642015 88.37 89.312016 84.25 89.632017 95.52 101.622018 96.96 103.14

Thereafter +1.5%/yr +1.5%/yr

The value and life of the reserves are important in determining:

a) Depletion charges, and the useful life of certain related assets (Note 7), b) Provisions for decommissioning and estimates of when such activities could occur (Note 11), c) The economic feasibility and commercial viability of exploration and evaluation assets and potential related

impairment, d) The existence of impairment of the carrying value of oil properties, (Notes 7 and 8), and e) The recognition and carrying value of certain deferred tax assets and liabilities (Note 13).

As the economic assumptions used in determining reserves may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change resulting in potential material changes in the related financial information.

ii) Exploration and evaluation expenditures

The application of the Company’s accounting policy for exploration and evaluation expenditures requires judgment to determine whether it is likely that future economic benefits are likely, either from future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence and value of reserves. Management may use reserve estimates, as well as economic circumstances, to determine possible impairment of exploration and evaluation expenditures, the timing of when a project reaches economic feasibility and commercial viability, and the value with which a project and related expenses may be promoted to property, plant, and equipment. These assumptions may change as new information becomes available, and may impact the future carrying value of exploration and evaluation expenditures.

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iii) Units of production (“UOP”) and straight-line depreciation of oil and gas assets

Oil and gas property, plant, and equipment is depreciated by applying a ratio of production volumes over total proved and probable oil and gas reserves (the units of production (“UOP”) method) to the carrying value of each cash-generating unit (“CGU”). Specific, identifiable items of equipment may be depreciated separately using the straight-line method over its remaining useful life. These calculations require the use of estimates and assumptions, including the amount and duration of recoverable reserves, assessment of condition and life of the asset, and estimates of future capital expenditures. The calculation of the UOP rate of depreciation could be impacted by production fluctuations, changes to proved and/or probable reserves, changes in plans for future development, acquisitions or divestitures, or unforeseen operational issues.

Changes in estimates are accounted for prospectively.

iv) Recoverability of oil and gas assets

The Company assesses each asset or CGU each reporting period to determine whether any indication of impairment exists. Management must apply judgment to assess whether indicators of impairment exist and the amount of impairment to recognize. A formal estimate of the recoverable amount is made, which is considered to be the higher of the fair value less costs to sell and value in use. The assessment of recoverable amounts require the use of estimates and assumptions such as long-term oil prices (considering current and historical prices, price trends and related factors), discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves (see 3(i) Reserve and resource estimates above) and operating performance (which includes production and sales volumes).

Fair value is determined as the amount that would be obtained from the sale of the asset in an arm’s length transaction between knowledgeable and willing parties. Fair value for oil and gas assets is based on economically recoverable crude oil and natural gas reserves and the present value of estimated future cash flows arising from the continued use of the assets, which includes estimates such as the cost of future expansion plans and eventual disposal, using assumptions that an independent market participant may take into account. Cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset/CGU, resource type, and/or condition of entity compared to the market. Costs to sell are estimated, and usually determined to be negligible. Recent market transactions are also taken into account.

In assessing value in use, the estimated future cash flows are also used, and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use does not reflect future cash flows associated with improving or enhancing an asset’s performance.

These estimates and assumptions are subject to risk and uncertainty, therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs.

v) Decommissioning costs (Note 11)

Decommissioning costs are expenditures required to abandon wells and pipelines, retire equipment, and/or reclaim associated sites when an asset or property comes to the end of its operating life. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques, and/or experience at other production sites. The expected timing of expenditures can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. The Company assesses its decommissioning provision at each reporting date, and the provision at that date represents management’s best estimate of the present value of the future decommissioning costs required.

Significant estimates and assumptions are made in determining these inputs to the provision for decommissioning, and as a result, there could be significant adjustments to the provisions established which would affect future financial results.

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vi) Business combinations (Note 5)

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future depletion and depreciation and asset impairment.

vii) Share-based compensation (Note 12)

Share-based compensation calculations are subject to estimated stock volatility, forfeiture and exercise rates, and the future attainment of performance criteria. Future net earnings, contributed surplus, and shareholders’ equity can be affected through changes in these estimates.

4. Significant accounting policies:

The accounting policies set out below have been applied consistently to both years presented in these consolidated financial statements, and have been applied consistently by the Company and its subsidiaries.

(a) Business combinations:

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred and measured at fair value at the acquisition date, and the amount of any non-controlling interest (NCI), if any, in the acquiree. Acquisition related costs are expensed as incurred and included in general and administrative expenses.

When a business is acquired, the assets and liabilities assumed are assessed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. The acquired petroleum reserves and resources that are able to be reliably measured are recognized in the assessment of fair values upon acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognized.

The aggregate of the consideration transferred is compared to the fair value of the identifiable net assets acquired, net of liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred, a gain is recognized in profit or loss. If the consideration is greater than the fair value of the identifiable net assets, goodwill is recorded on the consolidated statement of financial position.

(b) Property, plant and equipment and intangible exploration assets:

(i) Recognition and measurement:

Pre-license costs:

Pre-license costs are recognized in the consolidated statements of loss and comprehensive loss as incurred.

Exploration and evaluation expenditures (“E&E”):

E&E costs include the costs of acquiring undeveloped land, geological and geophysical costs, sampling and appraisals, and drilling costs related to property previously unevaluated or outside the Company’s developed land base.

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E&E assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units.

The technical feasibility and commercial viability is considered to be determinable when proved and or probable reserves are determined to exist. A review is carried out, at least annually, to ascertain whether proved and or probable reserves have been discovered. Upon determination of proved and or probable reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within tangible assets referred to as property, plant and equipment.

Development and production assets (“D&P”):

“D&P” assets, classified on the consolidated statements of financial position as property, plant and equipment, include the cost of acquiring producing resource assets, geological and geophysical expenditures on developed lands and reservoirs, development drilling, equipping, and tie-ins, the installation or acquisition of facilities, and directly attributable overheads. D&P assets also include transfers from exploration and evaluation assets upon determination of technical feasibility and commercial viability.

D&P assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.

Subsequent costs:

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as additional D&P assets only when there are increased future economic benefits. All other expenditures are recognized in profit or loss as incurred. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

(ii) Depletion and depreciation:

D&P assets are grouped into CGUs for impairment testing and depletion calculations. CGUs are groups of assets that generate cash inflows largely independent of the cash inflows of other assets or groups of assets. The net carrying value of a CGU is depleted using the unit of production method by reference to the ratio of production in the year to the related proven and probable reserves, and taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

For other assets with useful lives shorter than the reserve life, or specific asset components, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of the item.

The estimated useful lives for other assets are as follows:

Computer hardware 2 – 3 years Office equipment and furniture 5 years

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

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4. Significant accounting policies (continued):

(i) Impairment of non-financial assets:

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting date to determine whether there are any indications of impairment. Impairment exists if there is objective evidence that the future cash flows of an asset have been negatively affected.

If any such indications exist, then the asset’s or CGU’s recoverable amount is estimated. The recoverable amount is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCS”). In determining FVLCS, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, independent evaluations, comparable industry transaction metrics, or other available fair value indicators. In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. The future cash flows for the VIU calculation are generally computed by reference to the cash flows expected from production of proven and probable reserves as assessed on the reserve report. VIU does not reflect future cash flows associated with improving or enhancing an asset’s performance, whereas anticipated enhancements to assets are included in FVLCS calculations.

An impairment loss is recognized in profit and loss if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are allocated first to reduce the carrying amount of any goodwill associated with the CGU and then to reduce the carrying amounts of the other assets within the CGU.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized.

(c) Financial instruments:

(i) Non-derivative financial instruments:

All financial assets and liabilities are recognized on the balance sheet initially at fair value when the Company becomes a party to the contractual provisions of the instrument. Subsequent measurement of the financial instruments is based on their classification. Financial instruments are classified into one of the following categories: financial assets and liabilities at fair value through profit or loss, loans and receivables, financial assets held to maturity, financial assets available for sale and other financial liabilities. The classification depends on the characteristics and the purpose for which the financial instruments were acquired. Except in limited circumstances, the classification of financial instruments is not subsequently changed.

The Company’s financial assets and financial liabilities are classified and measured as follows:

Financial instrument per balance sheet Classification Subsequent measurementCash Fair value through profit or loss Fair value

Commodity price contract Fair value through profit and loss Fair valueTrade and other receivables Loans and receivables Amortized cost using

effective interest methodAccounts payable Other financial liabilities Amortized cost using

effective interest methodBank loan Other financial liabilities Amortized cost using

effective interest methodPromissory notes Other financial liabilities Amortized cost using

effective interest method

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Realized and unrealized gains and losses from financial assets and liabilities carried at fair value are recognized in net income in the period such gains and losses arise. Gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in net income when these assets and liabilities are settled.

Financial assets and financial liabilities are offset and the net amount reported in the consolidated statements of financial position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, or to realize the assets and settle the liabilities simultaneously.

(ii) Impairment of financial instruments:

The Company assesses at each reporting date whether there is objective evidence that a financial asset or a group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if there is objective evidence of impairment, such as the debtor is experiencing significant financial difficulty, or has lodged a formal complaint disputing the amounts expected to be received by the Company. If evidence of impairment exists, the carrying amount of the asset is reduced through the use of an allowance account and the loss is recognized in profit or loss. If, in a subsequent year, the amount of the estimated impairment loss changes, the previously recognized impairment loss is increased or reduced by adjusting the allowance account. Financial assets, together with the associated allowance, are written off when there is no realistic prospect of future recovery. If a write-off is later recovered, the recovery is credited to profit or loss.

(iii) Derivative financial instruments:

The Company has entered into certain financial derivative contracts, recorded as Commodity Price Contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified at fair value through profit or loss and are recorded on the balance sheet at fair value. Transaction costs are recognized in earnings when incurred.

(d) Provisions:

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

(i) Decommissioning obligations:

The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. When the liability is initially recognized, the present value of the estimated costs is capitalized by increasing the carrying amount of the related oil and gas assets to the extent that it was incurred by the development/construction of the field.

Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established.

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(e) Income tax:

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, or for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(f) Revenue:

Revenue from the sale of oil is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer which is usually when legal title passes to the external party. Revenue is measured net of discounts, customs, and duties.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.

(g) Share based payments:

The grant date fair value of options and warrants granted to employees is recognized as stock-based compensation expense, with a corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. As the options or warrants are exercised, the proportionate fair value is also recognized in share capital from contributed surplus.

(h) New accounting policies:

The following new accounting standards and amendments to existing standards, as issued by the IASB have been adopted by the Company effective January 1, 2013.

IFRS 10, “Consolidated Financial Statements” provides a single control model to be applied in the assessment of control for all entities in which the Company has an investment. The adoption of the standard had no impact on the Company’s consolidated financial statements.

IFRS 11, “Joint Arrangements” classifies joint arrangements as either joints operations or joint ventures. Parties to a joint operation retain the rights and obligations to individual assets and liabilities of the operations and apply proportionate consolidation, while parties to joint ventures have the rights to the nets assets of the venture and apply equity accounting. The adoption of the standard had no impact on the Company’s consolidated financial statements.

IFRS 12, “Disclosure of Interests in Other Entities” contains new annual disclosure requirements for interests in subsidiaries, joint arrangements and associated and unassociated structured entities. The adoption of this standard had no impact on the Company’s consolidated financial statements.

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IFRS 13, “Fair Value Measurement” establishes a single source of guidance for fair value measurement and disclosure of financial and non-financial items under IFRS. The adoption of this standard had no material impact on the Company’s consolidated financial statements.

Amendments to IFRS 7, “Financial Instruments Disclosure” require additional disclosures regarding the Company’s financial assets and liabilities that are subject to set-off rights. Refer to note 18 for the additional disclosures.

(i) Standards issued but not yet effective:

The standards and interpretations that are issued but not yet effective up to the date of issuance of the Company’s financial statements listed below, are those that the Company reasonably expects will have an impact on disclosures, financial position or performance when applied at a future date. The Company intends to adopt these standards and interpretations, if applicable when they become effective.

(i) IFRS 9, “Financial Instruments”

As of January 1, 2018, Corval will be required to adopt IFRS 9 “Financial Instruments”, which is the result ofthe first phase of the IASB project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. Portions of the standard remain in development and the full impact of the standard on Corval’s Financial Statements will not be known until the project is complete.

(ii) IAS 36, “Impairment of Assets” – Amendments of IAS 36.

In May 2013, the IASB issued amendments to IAS 36 "Impairment of Assets" which reduce the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments are required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. These amendments will be applied on January 1, 2014 and the adoption will only impact disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

5. Business combinations:

On October 17, 2012, Corval acquired 100% of the units of Foundation Group Development Trust (“FGDT”), a wholly-owned subsidiary of Foundation Group Capital Trust, through an Arrangement Agreement in exchange for common shares and common share purchase warrants of Corval. FGDT was the business trust managing two wholly-owned subsidiaries, Foundation Resources Limited Partnership and White North Energy Corporation, that owned producing oil properties predominately in Manitoba, Canada. FGDT was acquired by Corval as an initial acquisition of producing properties that made Corval an active entity.

The steps of the Arrangement Agreement were as follows:

1) Corval exchanged 20,803,286 common shares and 5,200,821 common share purchase warrants for all of the outstanding trust units of FGDT held by Foundation Group Capital Trust;

2) The resource properties and net debt held in the subsidiaries of FGDT were distributed to Corval; 3) The subsidiaries under FGDT were wound up or dissolved; 4) Foundation Group Capital Trust distributed the Corval common shares and common share purchase warrants to its

unitholders at a ratio of 3.25659 Corval shares and 0.814148 Corval common share warrant to one Foundation Group Capital Trust unit, resulting in a conversion price of $0.80 per Corval common share.

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5. Business combinations (continued):

The Corval common share warrants were exercisable at $0.80 per common share, vested immediately, and expired on November 30, 2012. Of the total 5,200,821 warrants issued, 268,375 were exercised for proceeds of $214,700 (Note 12(a)(ii)).

The fair values of the identifiable assets and liabilities of FGDT as at the date of acquisition were as follows:

Assets acquired:CashTrade and other receivablesPrepaid expensesFair value of resource properties

$ 400,9021,162,884

174,32030,013,43631,751,542

Liabilities assumed:Accounts payable and accrued liabilitiesBank loanPromissory notesDecommissioning obligationsObligation to payout dissenting unitholders

(1,413,876)(6,900,000)(5,044,719)(1,637,000)

(113,318)(15,108,913)

Net identifiable assets at fair value $16,642,629

Consideration:Common shares (20,803,286 common shares @ $0.80 per share) $16,642,629

Transaction costs and attributable costs of the issuance of the shares were borne by the unitholders of FGDT.

From the date of acquisition, FGDT has contributed all of the revenue, royalties, and operating costs in the year ending December 31, 2012. If the acquisition of FGDT had been completed on the first day of the financial year, the consolidated statements of loss and comprehensive loss would have included additional revenue and net income of $7.1 million and $4.2 million, respectively.

6. Exploration and evaluation assets:

Cost or deemed cost TotalBalance at December 31, 2012 $ - Additions 2,558,131

Transfer to property, plant and equipment -Balance at December 31, 2013 $ 2,558,131

Exploration and evaluation (“E&E”) assets consist of the Company’s undeveloped land and exploration projects which are pending the determination of technical feasibility. For the year ended December 31, 2013, E&E assets are comprised of $1,422,500 of undeveloped land, $1,027,279 of drilling costs on an exploration well and $108,352 of capitalized general and administrative costs. There were no indicators of impairment as at December 31, 2013.

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7. Property, plant and equipment:

Cost or deemed cost TotalOpening balanceAcquisition of FGDT (note 5)AdditionsChanges in decommissioning liability

$ -30,013,436

1,357,855135,214

Balance at December 31, 2012 31,506,505Additions 24,397,259Property acquisitions 3,291,910Divestitures (1,874,318)Change in decommissioning liability (7,458)Balance at December 31, 2013 $57,313,898

Accumulated depletion, depreciation, and impairmentOpening balance $ -Depletion and depreciation 691,374Impairments (note 8) 7,287,000Balance at December 31, 2012 7,978,374Depletion and depreciation 6,703,366Balance at December 31, 2013 $ 14,681,740

Net book valueBalance at December 31, 2012 $ 23,528,131Balance at December 31, 2013 $ 42,632,158

All of the Company’s development and production assets are located within Canada. The bank loan is secured by a general security agreement including a floating charge on all lands (Note 9). Future development costs of $13,631,000 have been included in the depletable balance as at December 31, 2013 (December 31, 2012 - $16,422,500). Depletion has been calculated using proved and probable reserves. The Company has not recognized any individual components that are depreciated separately.

During the year ended December 31, 2013 the Company capitalized general and administrative expense in the amount of $74,372 (December 31, 2012 - $34,369) consisting predominately of overhead. Please refer to Note 8 for the details on impairment testing of oil and gas properties.

8. Impairment losses:

a) As at December 31, 2013 there were no indicators that would imply the producing oil and gas properties required additional impairment testing, therefore no impairment was applied

b) As at December 31, 2012 total impairment losses of $7,287,000 were recognized in respect of producing oil and gas properties. The recoverable amounts of the Company’s CGU’s were estimated at fair value less costs to sell, based on the net present value of the after-tax cash flows from oil reserves, using reserves estimated by independent reserve evaluators.

The two major elements of impairment in 2012 were $945,000 of the Crossfield, Alberta CGU, and $6,342,000 million primarily relating to reduced estimates of market prices at year end for light oil reserves transactions. The market prices and recoverable amounts declined due to lower future oil prices because of reduced pipeline capacity to U.S. refineries. The recoverable amount was based on management’s estimate of fair value less costs to sell.

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8. Impairment (continued):

The net present values of the cash flows from oil reserves at December 31, 2012 were calculated using a post-tax discount rate of 9% and forward commodity price estimates.

9. Bank loan:

As at December 31, 2012, the Company had a bank loan with an outstanding balance of $7,450,000. During 2013, the Company repaid the $7,450,000 balance of the loan, and secured new lending arrangements with another Canadian financial institution. The new bank loan is a revolving operating demand loan that had an initial borrowing base of $9 million, which through additional drilling and increased reserves, the line was increased to $15.0 million as at December 31, 2013. The revolving operating demand loan bears an interest rate of the Bank’s Prime Rate plus 0.75% and a standby fee of 0.25% on the undrawn portion. The new bank loan is covered by a fixed and floating $50 million demand debenture over all of the assets of the Company. The Company is required to comply with a working capital financial covenant. The next review date is June 1, 2014. As December 31, 2013, the credit line was undrawn.

As at December 31, 2013, the Company was compliant with the working capital financial covenant.

10. Promissory Notes:

The Company assumed $5,044,719 in promissory notes and accumulated interest as part of the acquisition of FGDT (Note 5). These notes bear a simple interest rate of 3%. Subsequent to the financing on December 17, 2012 (Note 12), an offer was made to the promissory note holders that the Company would repay the notes plus accrued interest upon presentation of the original note. The Company paid $4,506,515 during 2012, and $545,193 during 2013. The notes are due in 2014 and therefore have been classified as a current liability.

Value of promissory notes assumed on acquisition of FGDT (Note 5) $ 5,044,719Additional interest accrued 30,624Notes repaid during the year ($4,479,821 plus additional interest of $26,694) (4,506,515)Balance at December 31, 2012 568,828Additional interest accrued 1,657Notes repaid during the year ($540,485 plus additional interest of $4,708) (545,193)Balance at December 31, 2013 25,292

11. Decommissioning obligations:

The decommissioning provision represents the present value of decommissioning costs relating to the Company’s interest in oil and gas properties, which are expected to be incurred up to the time when the properties are expected to cease operations. These provisions have been created based on the Company’s internal estimates and external engineering reports. The Company has estimated the net present value of the decommissioning obligations to be $1,962,138 as at December 31, 2013 (December 31, 2012 - $1,807,338) based on an undiscounted total future liability of $5,116,942 (December 31, 2012 - $4,015,000), with payments expected to be made over the next 16 years (December 31, 2012 – 13years). Changes in estimates occurred as both management and our external reserve engineers estimated that the producing assets had a longer reserve life. The discount factor, being the credit-adjusted rate, is 8% (December 31, 2012 – 8%).



Beginning of year $ 1,807,338 $ -Obligations incurred 334,457 -Obligations acquired 34,641 1,637,000Obligations disposed (16,361) -Change in estimates (360,197) 135,215Accretion expense 162,260 35,123End of year 1,962,138 $ 1,807,338

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11. Decommissioning obligations (continued):

These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend on future market prices for the necessary decommissioning work required that will reflect economic conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the oil fields cease to produce at economically viable rates. This will, in turn, depend on future oil prices and reserves, which are inherently uncertain.

12. Share capital:

At December 31, 2013, the Company was authorized to issue an unlimited number of common shares.

a) Share issues:

(i) In October 2012, the Company raised funds through several private placements for 1,299,999 common shares at $0.60 per common share and 395,000 common shares at $0.80 per common share for total cash proceeds of $1,096,001.

(ii) As part of the acquisition of FGDT (Note 5), the Company issued 20,803,286 common shares valued at $0.80 per common share and 5,200,821 warrants exercisable at $0.80 per common share warrant which expires on November 30, 2012 in exchange for the resource assets less debt of FGDT. Of the 5,200,821 warrants, 268,375 were exercised for cash proceeds of $214,700.

(iii) The Company participated in a private placement financing on December 17, 2012 with two brokerage firms for a total equity commitment of $31.0 million. The structure of the investment is similar to industry standard equity lines of credit pursuant to which a portion of their commitment will be funded on the closing date of the Offering, while the balance thereof will be funded over time as funds are required and called by the Company. On December 17, 2012, the first call on this equity line was for 19,928,570 shares at $0.70 per common share for cash proceeds of $13,950,000 with issue costs of $1,165,451, for net proceeds of $12,784,549. In addition to the line of equity, the Company raised an additional $2,191,469 through a private placement for 3,130,671 shares at $0.70 per common share.

(iv) On February 6, 2013, the Company raised funds through a private placement for 208,000 common shares at $0.70 per common share for total cash proceeds of $145,600.

(v) On April 5, 2013, the Company made a call on its equity line for 11,428,571 shares at $0.70 per common share for cash proceeds of $8,000,000 with issue costs of $489,563, for net proceeds of $7,510,437.

(vi) On September 23, 2013, the Company made a final call on its equity line for 12,928,572 common shares at $0.70 per common share for cash proceeds of $9,050,001 with issue costs of $543,000, for net proceeds of $8,507,001.

b) Common share options:

The Company has an option plan (the “Option Plan”) that entitles officers, directors, employees, and certain consultants to purchase common shares in the Company. The Option Plan allows the Company to issue common share options not exceeding 10% of the common shares outstanding and is administered by the Board of Directors. The common share options are non-transferable, have a five-year life, and vest at one third one each for the first, second, and third anniversaryof the common share option grant date. Vested common share options are exercisable at any time prior to expiry date by the option holder.

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12. Share capital (continued):

The number and weighted average exercise prices of common share options are as follows:

Number of options

Weighted average exercise

price

Weighted average

remaining life (years)

Balance December 31, 2011 - $ - -Granted 5,455,000 0.70 3.96Balance December 31, 2012 5,455,000 0.70 3.96Granted 1,270,000 0.73 4.34Forfeited (610,000) 0.70 4.23Balance December 31, 2013 6,115,000 $ 0.71 4.02

As at December 31, 2013, 1,715,000 options at an exercise price of $0.70 were exercisable.

Subsequent to year-end 335,000 options were issued at an exercise price of $0.90.

c) Performance Warrants:

The Company has a performance warrant plan (the “Warrant Plan”) that entitles officers, directors, and employees to purchase shares in the Company. The Warrant Plan is administered by the Board of Directors and allows the Company to issue up to 7,018,305 performance warrants. The performance warrants are non-transferable, have a five-year life, and vest upon the sale of substantially all of the Company’s assets, a corporate merger or sale where the common shareholders receive cash or publicly-traded shares, or the Company is listed on a public stock exchange, and the value attributed to each common share of the Company upon such event exceeds the vesting price as stipulated in the Warrant Plan. The performance warrant vesting prices are described in the table below:

Performance warrant series

Portion of performance warrant issue

Vesting price

Series 1Series 2Series 3Series 4

25%25%25%25%

$1.05$1.40$1.75$2.10

100%

The number and weighted average exercise prices of performance warrants are as follows:

Number of options

Weighted average exercise

price

Weighted average

remaining life (years)

Balance December 31, 2011 - $ - -Granted 6,750,000 0.70 3.96Balance December 31, 2012 6,750,000 0.70 3.96Granted 210,000 0.70 4.07Forfeited (220,000) 0.70 4.05Balance December 31, 2013 6,740,000 $ 0.70 3.97

Subsequent to year-end 278,305 performance warrants were issued with the same conditions and terms as described under the Warrant Plan.

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12. Share capital (continued):

d) Acquisition Warrants:

Pursuant to the Arrangement Agreement (Note 5), the Company issued 5,200,821 common share purchase warrants (“acquisition warrants”) as part of the consideration for the acquisition of FGDT on October 17, 2012, which were distributed with the common shares issued to the former unitholders of Foundation Group Capital Trust. These acquisition warrants had an exercise price of $0.80 per warrant and an expiry of November 30, 2012. On November 30, 2012, 268,375 acquisition warrants were exercised, resulting in the issue of 268,375 for proceeds of $214,700. The remaining outstanding acquisition warrants expired on that day.

e) Contributed surplus:

The fair values of the common share options, performance warrants, and acquisition warrants were estimated using Black Scholes model. Volatility was estimated using the average of the volatilities of three publicly-traded entities that are peerswith the Company.

Inputs for calculating the share-based compensation for each type is summarized below:

Year end December 31, 2013Common share

optionsPerformance

WarrantsExercise priceVolatilityOption/warrant lifeDividendsRisk free rateForfeiture rate

$0.70-$0.80106%

5 yearsNil

1.37%Nil

-Nil*

5 yearsNil

1.37%Nil

Weighted average fair value per option $0.57 -

Year end December 31, 2012Common

share optionsPerformance

WarrantsAcquisition Warrants

Exercise PriceVolatilityOption/warrant lifeDividendsRisk free rateForfeiture rate

$0.70106%

5 yearsNil

1.37%Nil

$0.70Nil*

5 yearsNil

1.37%Nil

$0.800%**

0.1 yearsNil

1.37%95%

Weighted average fair value per option $0.54 - -*Due to the uncertainty surrounding the future events that must happen before the performance warrants vest, the fair value of the performance warrants was recorded at nil. ** Due to the short exercise period of the acquisition warrants, the volatility was assumed to be 0%. Due to the large forfeiture rate, the fair value of the acquisition warrants were deemed zero, and the acquisition warrants exercised were recorded in share capital at a value equal to the proceeds of exercise.

The fair value at grant date is recorded as stock based compensation in profit and loss, and in shareholders’ equity as contributed surplus, over the period of time required for the options or warrants to vest. Stock based compensation of $1,879,247 was expensed during 2013 (2012 - $68,537).

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13. Income tax:

The following table reconciles the expected income tax expense at the Canadian federal and provincial statutory income tax rates to the amounts recognized in the consolidated statements of loss, and comprehensive loss for the year ended December 31, 2013.

2013 2012Loss before income taxes $(766,698) $(8,474,535)Statutory income tax rate 26.00% 26.00%Expected income tax recovery $(199,341) $(2,203,379)

Increase (decrease) in taxes resulting from:Non-deductible expenses 2,077 (16,993)Share issuance costs (114,297) (303,018)Share-based compensation 488,604 17,820Unrealized loss on commodity contracts 48,713Change in deferred tax not recognized (225,756) 2,505,570Income tax expense $ - $ -

Details of deferred income tax assets are as follows:

2013 2012Deferred income tax assets

Non-capital loss carry forwards $2,596,678 $ 776,511Tax value of share issuance costs in excess of book value 444,192 290,066Tax value of oil and gas properties in excess of book value 2,457,004 4,543,131Asset retirement obligations 510,156 469,908Unrealized loss on commodity contracts 48,713 -Total gross deferred income tax assets 6,056,743 6,079,616Less: deferred tax asset not recognized (6,056,743) (6,079,616)

Net deferred tax asset $ - $ -

Based upon predicted operations and capital expenditures, it is more likely than not that the Company will not realize the benefits from deferred income tax assets.

As at December 31, 2013, the Company has non-capital losses of approximately $10.0 million (2012 - $3.0 million) which may be carried forward to apply against future years’ taxable income for Canadian tax purposes, subject to final determination by taxation authorities and expiring as follows:

2027 $ 1,256,2832028 110,8432029 5,1882030 529,8922032 1,069,5532033 7,015,464

$9,987,223

The tax losses expire up to 2033, and do not include approximately $5.7 million of losses determined to be non-accessible at this time. As at December 31, 2013, the Company also has approximately $54.6 million (2012 - $41.0 million) in oil and gas tax pools available for deduction against future income. The Company also has a capital loss of $15.9 million also considered non-accessible at this time. The deductible temporary differences do not expire under current tax legislation. Deferred tax assets have not been recognized in respect of these items because it is not probable that future taxable profit will be available against which the Company can utilize the benefits.

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14. Finance expenses:

2013 2012Interest on bank loan $ 39,253 $ 73,244Interest on promissory notes (note 10) 1,655 30,624

Accretion of decommissioning liabilities (note 11) 162,260 35,123Finance expenses total $203,168 $138,991

15. Supplemented cash flow information:

Changes in non-cash working capital is comprised of:

2013 2012Changes in:

Trade and other receivables $(1,601,955) $ 401,215Prepaid expenses (22,068) (10,881)

Accounts payable and accrued liabilities 3,772,148 761,976$ 2,148,125 $1,152,310

Allocated to:Operating $ (861,411) $ 600,633Investing 3,009,536 551,677

$ 2,148,125 $1,152,310

16. Related party:

The corporate secretary is a partner in a law firm that provides legal services to the Company. For the year ended December 31, 2013, the Company recorded $168,003 (2012 - $230,642) in general and administrative expenses related to this law firm. As at December 31, 2013, $20,363 (2012 - $48,655) remained in accounts payable and accrued liabilities.

17. Capital management:

The Company considers its capital structure to include share capital, and working capital, including the bank loan. The objectives of the Company are to maintain a strong balance sheet affording the Company financial flexibility to achieve goals of continued growth, access to capital, and maximization of shareholder value. In order to maintain or adjust the capital structure, the Company may issue new common shares, acquire new debt, or adjust exploration and development capital expenditures.

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17. Capital management (continued):

The Company monitors its capital program based on available funds, which is the combination of working capital and remaining unused line of credit, as calculated below:

December 31, 2013 December 31, 2012Current assets $ 4,731,446 $ 12,997,246Accounts payable and accrued liabilities(2) (5,947,999) (2,175,851)Promissory notes (25,292) (568,828)Net working capital (1,241,845) 10,252,567

Maximum value of bank loan (note 9) 15,000,000 8,000,000Amount drawn - (7,450,000)Unutilized bank loan 15,000,000 550,000

Total available line of equity (Note 12) 31,000,000 31,000,000Amount drawn (31,000,000) (13,950,000)Unutilized line of equity - 17,050,000Net available funds $ 13,758,155 $ 27,852,567

Net debt (1,241,845) -Annualized cash flow (1) 12,465,140 -Net debt to annualized cash flow 0.1 -

(1) Based on the last quarter’s cash flow from operations annualized (2) Excludes non-cash Commodity Price Contracts

The Company’s approach to capital management is to present to the Board of Directors a two-year capital program and financial budget and requesting funding and approval. Under this program, the Company plans to maintain a debt to equity ratio of less than 1:1 and to maintain a debt to cash flow ratio of less than 1:1. The Company’s 2014 capital program was presented to the Board of Directors, and a capital program of $34.7 million was approved in January 2014. The Company expects that with the bank loan and anticipated cash flow that it will be able to fund its full 2014 capital program and maintain a debt to cash flow ratio of less than 1:1. The Company operates most of its operations and can therefore remain flexible to reduce or increase its capital program as required.

The amount of the bank loan is based on petroleum and natural gas reserves with certain financial covenants. The bank loan also contains a financial covenant that requires the Company to maintain a certain minimum working capital ratio. The Company is compliant with all covenants. The credit facility is subject to a periodic review, the next of which isscheduled for June 1, 2014 (note 9).

18. Financial risk management:

The Company’s financial assets and liabilities are comprised of cash, trade and other receivables, accounts payable, commodity price contracts, promissory notes and the bank loan. The fair values of financial assets and liabilities that are included in the balance sheet approximate their carrying amounts except certain of these financial instruments including commodity price contracts are measured in the financial statements at fair value. These financial instruments require disclosure about how fair value was determined based on significant levels of inputs described in the following hierarchy:

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

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18. Financial risk management (continued):

• 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 commodity price contracts as presented on the balance sheet is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted oil and natural gas volumes and are considered Level 2.

The Company is exposed to a variety of financial risks arising from its exploration, development, production, and financing activities such as:

credit risk; liquidity risk; and market risk.

Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meetits contractual obligations, and arises principally from the Company’s receivables from joint venture partners and oil and natural gas marketers.

December 31, 2013 December 31, 2012Amounts due from marketersJoint ventureGST receivable

$2,114,153150,248

99,233

$505,004192,409

64,266Total $2,363,634 $761,679

The Company’s exposure to credit risk is influenced mainly by the individual characteristics of each customer. Receivables from oil and natural gas marketers are normally collected on the 25th day of the month following production. The Company historically has not experienced any collection issues with its oil and natural gas marketers. At 31 December 2013, the Company markets approximately 95% of its production through one marketer accounting for 87% of total accounts receivable.

Receivables from joint venture partners are typically collected within one to three months of the joint venture invoice being issued. The Company attempts to mitigate the risk from joint venture receivables by obtaining venturer pre-approval of significant capital expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. The Company currently operates a large percentage of its property ownership and takes its revenue in kind on the properties it does not operate, so its exposure to non-collection of amounts receivable from joint venture partners is minimal.

The need for impairment of receivables is analyzed at each reporting date on an individual basis for major clients. At December 31, 2013, no impairment was deemed necessary, so no allowance for doubtful accounts was recognized. As at December 31, 2013, the Company’s trade and other receivables are aged as follows:

Current 30 – 60 days60 – 90 daysOver 90

$2,339,9106,149

-17,575

Total $2,363,634

Subsequent to year-end, a significant portion of the receivables over 90 days were collected.

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Liquidity risk:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due. As disclosed in Note 17, the Company manages its liquidity by monitoring its capital program and comparing that to its available funds. This excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. In addition, the Company maintains a $15 million credit facility (Note 9) to provide capital when needed.

Market risk:

Market risk is the risk that changes in market prices will affect the Company’s income or the value of the financial instruments. Market risk is comprised of three types of risk: commodity price risk, interest rate risk, and currency risk.

Commodity price risk:

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by not only the relationship between the Canadian and United States dollar, but also world economic events that dictate the levels of supply and demand. In addition, crude oil pricing has been volatile due to bottlenecks in North American transportation from producing areas to refining areas. These factors have resulted in wider differentials between prices on the world market based on Brent pricing index, West Texas Intermediate “WTI”, which is the North American benchmark and Edmonton Par Prices, the Canadian benchmark for light sweet crude oil. The Company’s production is usually sold using “spot” or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price.

As at December 31, 2013, the Company had three crude oil swaps in-place fixing the price of future production for a specific period of time. For the year ended December 31, 2013, the Company recorded a realized commodity contract loss of $192,717 (2012 - $nil) and an unrealized commodity contract loss of $187,359 (2012 - $nil).

The Company had the following risk management contracts outstanding as at December 31, 2013:

Commodity Volume Sold TermPricing WTI

$Cdn.Fair Value Liability

Oil 100 bbl per day Jan 1, 2014 –July 31, 2014 $101.35 $52,102Oil 200 bbl per day Jan 1, 2014 –Dec 31, 2014 $100.80 $95,484Oil 100 bbl per day Jan 1, 2014 –Dec 31, 2014 $101.02 $39,773

$187,359

On February 12, 2014, the Company entered into a crude oil commodity price contract to sell 100 barrels of production per day from August 1, 2014 until December 31, 2014 at a price of $103.14 WTI Cdn. per barrel.

Commodity price sensitivityRemaining oil production under commodity contract 130,700Price change $1.00Unrealized change before income tax $130,700

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Offsetting financial assets and liabilities

The following table shows the Company’s net commodity price contract assets and liabilities:

December 31, 2013 December 31, 2012Gross

amount Offset Net amountGross

amount OffsetNet

amountCommodity price contract asset $ 53,044 $(53,044) $ - $ - $ - $ -Commodity price contract liability (240,403) 53,044 (187,359) - - -Net commodity price contract asset (liability) $(187,359) $ - $(187,359) $ - $ - $ -

Interest rate risk:

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates, and relatesprimarily to the Company’s outstanding line of credit. The Company has not entered into any mitigating interest rate hedges or swaps. Had the borrowing rate been 1% higher (or lower) throughout the year ended December 31, 2013, cash flow would have been affected by $37,250 based on the average debt balance outstanding during the year.

Currency risk:

Prices for oil are determined in global markets and generally denominated in United States dollars. The exchange rate effect cannot be quantified but generally an increase in the value of the $CDN as compared to the $US will reduce the prices received by the Company for its petroleum and natural gas sales. The Company has no financial instruments denominated in a foreign currency, and no contracts in place to reduce the foreign exchange risk.

19. Commitments:

The Company is carrying a lease on its office space and office equipment:

December 31, 201320142015-20192020-2022

$ 150,337809,150334,265

Total $1,293,752

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GENERAL INFORMATION

Corval Energy Ltd. Notes to the Consolidated Financial StatementsFor the years ended December 31, 2013 and 2012

Directors

Jody Forsyth (2)(3) - Chairman Larry Evans (1)(2)

Brian Frank (1)(3)

Ron McIntosh (2)(3)

David Eastham (1)

Thomas Stan (1) Audit committee (2) Reserves, health, safety and environment committee (3) Corporate governance and compensation committee

Officers

Thomas Stan President, and Chief Executive Officer

James Screaton, CA Vice President, Finance and Chief Financial Officer

Lavern Rankin Vice-President, Engineering and Operations

Dale Timmons Vice-President, Exploration

Richard Press Vice-President, Land and Business Development

Shannon Gangl Burnet, Duckworth, and Palmer LLP Corporate secretary

Head Office

Suite 2400, 500 – 4th Avenue SW Calgary, Alberta, Canada T2P 2V6 Telephone: 403-252-7671 Website: www.corvalenergyltd.com

Solicitor

Burnet, Duckworth, & Palmer LLP2400, 525 – 8th Avenue SW Calgary, Alberta, Canada T2P 1G1

Bankers

National Bank of Canada 311 – 6 Avenue SW Calgary, Alberta, Canada T2P 3H2

Auditor

Ernst & Young Canada 1000, 440 – 2nd Street SW Calgary, Alberta, Canada T2P 5E9

Reserve Engineers

Sproule Associates Limited 900, 140 – 4th Avenue SW Calgary, Alberta, Canada T2P 3N3

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Documents

Annual report 2013