EQUAL ENERGY LTD. - 40-F filing on 2012-03-21

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

Dear Equal Shareholders,

We set out to achieve several key goals in 2011. Among these were:

-	Restructuring our convertible debentures;

-	Resolving our dispute with our former partner in the US;

-	Embark on a strong drilling program, especially in Oklahoma Hunton; and

-	Rationalize non-core assets to improve financial flexibility.

I am pleased to report during 2011, Equal successfully executed on these key strategies, putting us in the best financial and operating shape we have seen in years. With a consolidated, high quality asset base, over eight years of identified drilling prospects and a restructured balance sheet that will provide secure, low cost financial flexibility, we are more optimistic than ever that we can effectively deliver on Equal’s exciting growth prospects.

Specifically over the course of 2011 our accomplishments include:

-	Completion of an acquisition of the working interests from a former joint venture partner adding approximately 3,100 boe/d of liquids-rich natural gas to our production base;

-	Consolidation of our land position in the emerging Mississippian light oil play which we plan to begin drilling during 2012;

-	Re-financing of $120 million of high cost convertible debentures with $45 million of lower cost convertible debentures and repaying the remainder with proceeds from non-core asset sales and low cost revolving bank debt;

-	Reduction of the Company’s annual interest burden by approximately $2.5 million;

-	The execution of a very successful 26 well drilling program; and

-	The sale of non-core assets totaling $40 million during 2011 with another $8.3 sold in early 2012, reducing our debt burden and consolidating our asset base.

In 2011, production volumes averaged 10,142 boe/d, an increase of 11 percent over 2010. We also were successful in increasing our total proved reserves by 35 percent and our proved and probable reserves by approximately 19 percent.

Operationally, we are pleased with our drilling program, which consisted of drilling 26 wells (22.8 net) with over a 96 percent success rate. Thirteen Hunton liquids-rich natural gas wells were drilled in Oklahoma with 12 wells successful in the Hunton and one well producing from the Mississippian. Seven of those wells also preserve additional Mississippian acreage. Three light oil wells were drilled in the Cardium play with very positive results. We increased the number of frac stages when compared to our 2010 wells and experienced consistently stronger results. Nine Viking wells were drilled in 2011 with the ninth Viking well utilizing a new monobore technology and a larger number of frac stages which not only resulted in very encouraging well performance but it was also our lowest cost well to date.

Looking Ahead

We enter 2012 well positioned as a consolidated and focused player with two light oil plays in the Cardium and Viking and our liquids-rich natural gas play in Oklahoma. Equal controls and operates all three resource plays so we can change the pace of drilling and allocate our capital to align with commodity pricing and cash flow. Equal’s drilling inventory has expanded to over 200 locations in these three areas.

Two rigs began drilling in the Oklahoma Hunton play in January 2012. The first is drilling a four well vertical program in the K-9/Puppy area in northern Oklahoma where the Company had considerable drilling success in 2011. This program will also preserve or hold three more net sections of Mississippian lands adjacent to existing Mississippian holdings. The second rig is drilling at Twin Cities Central Dolomite which has our best well economics in the Hunton and we expect to drill up to 9 wells in 2012. Cardium light oil drilling will commence in April in the Lochend area with the first of three wells planned for 2012. We plan to continue to complete the Cardium wells with increased density of frac stages and will also employ water based frac completions to lower costs and improve our well economics. Drilling in the light oil Viking play is planned to begin in July 2012 with up to six wells using monobore technology to reduce drilling costs and allow targeted frac spacing which we believe will optimize our economics to a manufacturing style of drilling program.

Equal Energy plans to realize value from our Mississippian lands by farming out up to 50% working interest. Farmout negotiations are currently ongoing with the initial two wells being prepared for drill ready state. If the lands are not farmed out, Equal Energy will move forward without a joint venture partner in Q3 2012 with the drilling rig and associated funds being re-allocated from the Twin Cities Central Dolomite program.

Capital spending in 2012, excluding our new program in the Oklahoma Mississippian play, is projected to be $64 million which approximates our 2012 funds from operations based on our base business plan assumptions. We are committed to keeping our capital spending limited to our funds from operations and we will adjust our spending accordingly based on various factors including production and commodity prices. Investors should note that Equal has significant volumes of oil and natural gas hedged for 2012 which acts as a stabilizing factor on our funds from operations in this volatile commodity price environment.

In summary, Equal Energy is an opportunity rich company with a proven multi-year inventory of drilling locations. With our three identified resource plays and the additional Mississippian oil play, it is our objective to effectively deliver on these exciting growth prospects. It is our intent to continue to grow our reserves base and underlying value just as we did in 2011. The depth and quality of our plays allows us to achieve this under our targeted budget, with the ability to report this year after year.

I would like to thank the Equal employees for their hard work and dedication, the Board of Directors for their guidance and our shareholders for their continued support. I am looking forward to an active 2012 where we will build on the momentum created in 2011 and work towards delivering value to our shareholders.

Sincerely,

Signed “Don Klapko”

President and Chief Executive Officer

March 20, 2012

2011 FINANCIAL REPORT

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

INTRODUCTION: The following is Management’s Discussion and Analysis (“MD&A”) of Equal Energy Ltd. (the “Company” or “Equal”) for the three months and year ended December 31, 2011. This MD&A should be read in conjunction with the consolidated financial statements and accompanying notes of the Company for the years ended December 31, 2011 and 2010. All amounts, unless otherwise noted, are stated in Canadian dollars and in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Prior to January 1, 2011, the Company prepared its consolidated financial statements in accordance with Canadian generally accepted accounting principles. This commentary is based on information available to, and is dated, March 20, 2012.

CONVERSION: Natural gas volumes recorded in thousand cubic feet (“mcf”) are converted to barrels of oil equivalent (“boe”) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (“bbl”). Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.

NON–GAAP TERMS: This document contains the terms “working capital” and “cash flow netback”, which do not have any standardized meaning as prescribed by IFRS and, therefore, are considered non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Equal to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to analyze profitability of its operations. The Company uses these measures to help evaluate its performance. The Company considers cash flow netback a key measure for the ability of the Company to analyze the profitability of its operations. The term should not be considered as an alternative to, or more meaningful indicator of performance than net income or loss as determined in accordance with IFRS. Working capital and cash flow netback, as determined by the Company may not be comparable to that reported by other companies. The reconciliation of cash flow netback to net income or loss can be found in the non-GAAP financial measures section of this MD&A. The working capital calculations can be found in the liquidity and capital resources section of the MD&A.

This MD&A also contains other terms such as working capital including long-term debt and operating netbacks which are not recognized measures under IFRS. Management believes these measures are useful supplemental measures of firstly, the total amount of current and long-term debt and secondly, the amount of revenues received after transportation, royalties and operating costs. Readers are cautioned, however that these measures should not be construed as an alternative measures of performance to other terms such as current and long-term debt or net income determined in accordance with IFRS. Equal’s method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other companies.

ADDITIONAL GAAP MEASURE: The Company considers “funds from operations” a key measure for the ability of the Company to repay debt and to fund future growth through capital investment. Funds from operations as determined by the Company may not be comparable to that reported by other companies.

FORWARD-LOOKING STATEMENTS: Certain information contained herein may contain forward-looking statements under applicable securities laws and necessarily involve risks including management’s assessment of future plans and operations, drilling plans and timing thereof, expected production increases from certain projects and the timing thereof, the effect of government announcements, proposals and legislation, plans regarding wells to be drilled, expected or anticipated production rates, expected exchange rates, anticipated borrowing base under the credit facility, maintenance of productive capacity and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof. All statements other than statements of historical facts contained in this MD&A are forward-looking statements. The words “believe”, “may”, “will”, “estimate”, “continue”, “anticipate,” “intend”, “should”, “plan”, “expect” and similar expressions, as they relate to the Company, are intended to identify forward-looking statements. The Company has based these forward-looking statements on the current expectations and projections about future events and financial trends that the Company believes may affect its financial condition, results of operations, business strategy and financial needs.

These forward-looking statements are subject to uncertainties, assumptions and a number of risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of Equal’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out herein and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the result of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisitions, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate reasonably priced transportation; future commodity oil and gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors could effect Equal’s operations and financial results are included in reports on file with the Canadian and United States regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or the EDGAR website (www.sec.gov/edgar.shtml), or at Equal’s website (www.equalenergy.ca). Furthermore, the forward-looking statements contained herein are made as at the date hereof and Equal does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of the new information, future events or otherwise, except as may be required by applicable securities law. The Company operates in a very competitive and rapidly changing business environment. New risk factors emerge from time to time and it is not possible for management to predict all risk factors, nor can the Company assess the result of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. The reader should not rely upon forward-looking statements as predictions of future events or performance. The Company cannot provide assurance that the events and circumstances reflected in the forward-looking statements will be achieved or occur. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, the Company cannot guarantee future results, levels of activity, performance or achievements.

The reader is further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on the financial status of the Company as further information becomes available, and as the economic environment changes.

CORPORATE PROFILE

Equal Energy Ltd. is an exploration and production oil and gas company based in Calgary, Alberta, Canada with its United States operations office located in Oklahoma City, Oklahoma. Equal’s shares are listed on the New York Stock Exchange (EQU) and Equal’s shares and convertible debentures are listed on the Toronto Stock Exchange (EQU and EQU.DB.B).

The Company’s portfolio of oil, NGL and natural gas properties is geographically diversified with producing properties located principally in Alberta and Oklahoma. Production is comprised of approximately 14% crude oil, 35% natural gas liquids (“NGLs”) and 51% natural gas.

	Three months ended December 31									Year ended December 30
Financial and Operations Summary (in thousands except for volumes, percentages and per share and boe amounts)	2011			2010			Change			2011			2010			Change
FINANCIAL
Oil, NGL and natural gas revenues including realized hedging		42,360			34,704			22	%		163,714			143,713			14	%
Funds from operations (1)		17,061			9,338			83	%		62,678			46,640			34	%
Per share – basic and diluted (2) (3) ($)		0.49			0.34			44	%		1.96			1.90			3	%
Net income/(loss)		(14,428	)		(38,556	)		(63	%)		(13,960	)		(42,652	)		(67	%)
Per share – basic and diluted (2) (3) ($)		(0.42	)		(1.39	)		(70	%)		(0.44	)		(1.73	)		(75	%)
Total assets		466,554			392,486						466,554			392,486
Working capital including long-term debt (4)		(123,719	)		(36,743	)					(123,719	)		(36,743	)
Convertible debentures		41,327			119,902						41,327			119,902
Shareholders’ equity		220,878			172,222						220,878			172,222
SHARES OUTSTANDING
Shares outstanding – basic and diluted(2) (3) (000s)		34,767			27,692						32,040			24,595
Shares outstanding at period end (3) (000s)		34,779			27,710						34,779			27,710
OPERATIONS
Average daily production
Oil (bbls per day)		1,961			2,501			(22	%)		2,343			2,481			(6	%)
NGL (bbls per day)		3,581			2,373			51	%		3,048			2,491			22	%
Natural gas (mcf per day)		33,669			22,529			49	%		28,507			24,878			15	%
Total (boe per day)		11,154			8,629			29	%		10,142			9,118			11	%
Average sales price
Oil ($ per bbl)		85.90			70.03			23	%		82.59			70.25			18	%
NGL ($ per bbl)		45.61			45.00			1	%		48.02			42.44			13	%
Gas ($ per mcf)		3.82			4.23			(10	%)		3.81			4.57			(17	%)
Cash flow netback (1) ($ per boe)
Revenue (5)		41.28			43.71			(6	%)		44.22			43.18			2	%
Royalties		8.29			8.77			(5	%)		8.93			8.81			1	%
Production expenses		10.17			10.67			(5	%)		11.22			10.76			4	%
Transportation expenses		0.33			0.79			(58	%)		0.45			0.71			(37	%)
Operating netback		22.49			23.48			(4	%)		23.62			22.90			3	%
General and administrative		3.13			7.93			(61	%)		3.49			5.78			(40	%)
Cash interest expense		2.72			3.56			(24	%)		3.05			3.40			(10	%)
Other cash costs (6)		0.00			0.23			(100	%)		0.15			(0.29	)		(148	%)
Cash flow netback		16.64			11.76			41	%		16.93			14.01			21	%

(1)	Funds from operations is an additional GAAP measure and cash flow netback is a non-GAAP financial measures. Please refer to “Additional GAAP Measures” and “Non-GAAP Financial Measures”.

(2)	Weighted average shares outstanding. See Note 11 in Notes to Financial Statements.

(3)	Restated to reflect the three for one exchange of trust units for common shares.

(4)	Working capital including long-term debt is a non-GAAP term and includes total bank debt, current assets and current liabilities excluding unrealized gains/losses on commodity contracts and deferred revenues.

(5)	Price received includes realized commodity contract gains or losses and excludes unrealized mark-to-market gain or loss.

(6) Other cash costs include current taxes and realized foreign exhange gains and losses.

2011 FINANCIAL REPORT

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

QUARTERLY FINANCIAL INFORMATION (in thousands of Canadian dollars except for per share amounts)

	2011								2010
		Q4		Q3		Q2	Q1			Q4		Q3		Q2		Q1
Revenues including realized hedging		42,360		44,452		41,824	35,078			34,704		34,267		35,689		39,053
Funds from operations		17,061		17,435		16,602	11,580			9,338		11,402		11,357		14,543
Income/(loss) before taxes		(11,043	)	(514	)	8,651	(6,205	)		(35,510	)	(3,846	)	(2,967	)	2,009
Net income/(loss)		(14,428	)	(2,642	)	6,492	(3,382	)		(38,556	)	(3,111	)	2,720		(3,705	)
Net income/(loss) per share basic(1) ($)		(0.42	)	(0.08	)	0.21	(0.12	)		(1.39	)	(0.11	)	0.12		(0.17	)
Net income/(loss) per share diluted (1) ($)		(0.42	)	(0.08	)	0.19	(0.12	)		(1.39	)	(0.11	)	0.12		(0.17	)

(1) Restated to reflect the three for one exchange of trust units for common shares.

Q4, Q3 and Q2 2011 revenues including realized hedging and funds from operations are higher than the previous quarters due to the June 1, 2011 acquisition of working interests from a former joint venture partner in Oklahoma (the “Hunton acquisition”), higher prices received for oil and NGLs and Equal’s focus on light oil resource plays in Alberta and liquids-rich natural gas in Oklahoma. During Q4 2010 funds from operations were lower due to legal fees relating to legal proceedings against a joint venture partner in Oklahoma and the higher loss was due to an impairment in property, plant and equipment. The net losses in Q4 2011 and Q4 2010 are higher than the other quarters due to the impairment charges of $27.5 million and $31.1 million, respectively.

OVERALL PERFORMANCE

Average production in Q4 2011 was 11,154 boe per day, up 29% compared to Q4 2010 production of 8,629 boe per day, primarily due to the acquisition of Oklahoma Hunton assets in Q2 2011, Equal’s drilling program and well optimization projects which were partially offset by declines in a mature natural gas pool and heavy oil pool in Saskatchewan, Canada and the disposition of non-core properties in November 2011.

Overall, oil prices received in Q4 2011 increased 23% to $85.90 per barrel compared to $70.03 per barrel in Q4 2010. NGL prices received in Q4 2011 were relatively flat at $45.61 per bbl compared to $45.00 per bbl in Q4 2010. Natural gas prices received in Q4 2011 decreased 10% to $3.82 per mcf from $4.23 per mcf in Q4 2010. Royalties in Q4 2011 decreased 5% to $8.29 per boe compared to $8.77 per boe in Q4 2010 due to lower prices received for natural gas and the increased proportion of natural gas production. Production expenses in Q4 2011 decreased 5% to $10.17 per boe compared to $10.67 per boe in Q4 2010 due to the production from the Hunton acquisition having lower than average operating costs per boe and the disposition of non-core assets in Q4 2011 which had higher than Company average operating costs.

General and administrative (“G&A”) expenses in Q4 2011 decreased 61% to $3.13 per boe from $7.93 per boe in Q4 2010 due to higher production volumes and higher Q4 2010 expenses related to court proceedings involving a former joint venture partner that ended in Q2 2011. Cash interest expense decreased 24% to $2.72 per boe in Q4 2011 compared to $3.56 per boe in Q4 2010 due to the increase in production volumes and reasonably stable total debt levels.

The overall result was that funds from operations in Q4 2011 increased 83% to $17.1 million compared to $9.3 million in Q4 2010 and 41% on a cash flow netback basis to $16.64 per boe in Q4 2011 from $11.76 per boe in Q4 2010. The increase in funds from operations is mainly due to the increase in NGL and natural gas revenues from the additional production from the Hunton acquisition and the decrease in G&A expenses which are partially offset by the increase in royalties and production expenses. Q4 2011 included a gain on sale of assets of $16.8 million and an impairment of property, plant and equipment of $27.5 million which contributed to the loss of $14.4 million for the quarter compared to a loss of $38.6 million in Q4 2010 which included an impairment of property, plant and equipment of $31.1 million.

SUMMARY OF OPERATIONS

The following is a summary of Equal’s operations and cash flows for the three months and year ended December 31, 2011 and 2010 which are referenced throughout this MD&A.

	Three months ended						Year ended
(in thousands of Canadian dollars)	December 31						December 31
(in thousands of Canadian dollars)	2011			2010			2011			2010
Oil, NGL and natural gas revenues		41,228			33,268			161,494			137,675
Realized gain on commodity contracts		1,132			1,436			2,220			6,038
Unrealized gain/(loss) on commodity contracts		(2,868	)		(3,441	)		5,525			(1,013	)
Royalty expense		(8,505	)		(6,963	)		(33,054	)		(29,330	)
Revenues, net of royalty expense		30,987			24,300			136,185			113,370
Operating expenses
Production		(10,431	)		(8,469	)		(41,557	)		(35,826	)
Transportation		(343	)		(629	)		(1,665	)		(2,370	)
General and administrative		(3,217	)		(6,298	)		(12,914	)		(19,227	)
Share-based compensation expense		(1,234	)		(435	)		(3,968	)		(2,900	)
Depletion and depreciation		(17,046	)		(9,938	)		(53,229	)		(47,252	)
Impairment of property, plant and equipment		(27,486	)		(31,114	)		(27,486	)		(31,114	)
		(59,757	)		(56,883	)		(140,819	)		(138,689	)
Other income/(expenses)
Interest expense		(3,002	)		(2,798	)		(12,042	)		(11,226	)
Accretion of decommissioning provision		(199	)		(192	)		(727	)		(769	)
Gain on sale of assets		16,769			200			17,595			2,005
Transaction costs on asset acquisition		-			-			(1,767	)		-
Redemption premium on convertible debentures		(976	)		-			(2,880	)		-
Revaluation of convertible debentures		-			-			-			(5,295	)
Amortization of trust unit issue costs		-			-			-			(1,000	)
Realized foreign exchange loss		(42	)		(82	)		(240	)		1,674
Unrealized foreign exchange gain/(loss)		5,177			(55	)		(4,416	)		(384	)
		17,727			(2,927	)		(4,477	)		(14,995	)
Loss before income taxes		(11,043	)		(35,510	)		(9,111	)		(40,314	)

Income taxes
Current		(61	)		(95	)		(391	)		(694	)
Future taxes reduction		(3,324	)		(2,951	)		(4,458	)		(1,644	)
		(3,385	)		(3,046	)		(4,849	)		(2,338	)

Loss		(14,428	)		(38,556	)		(13,960	)		(42,652	)

	Three months ended						Year ended
	December 31						December 31
(in thousands of Canadian dollars)	2011			2010			2011			2010
Cash Flow from Operations
Loss		(14,428	)		(38,556	)		(13,960	)		(42,652	)
Share-based compensation		1,234			435			3,968			2,900
Depletion, depreciation and accretion		17,046			9,938			53,229			47,252
Impairment in property, plant and equipment		27,486			31,114			27,486			31,114
Non-cash interest expense on convertible debentures		207			(32	)		732			(74	)
Accretion of decommissioning provision		199			192			727			769
Unrealized commodity contracts (gain)/loss		2,868			3,441			(5,525	)		1,013
Gain on sale of assets		(16,769	)		(200	)		(17,595	)		(2,005	)
Transactions costs on asset acquisition		-			-			1,767			-
Redemption premium on convertible debentures		1,071			-			2,975			-
Revaluation of convertible debentures		-			-			-			5,295
Amortization of trust unit issue costs		-			-			-			1,000
Unrealized foreign exchange(gain)/ loss		(5,177	)		55			4,416			384
Deferred tax reduction		3,324			2,951			4,458			1,644
Funds from operations		17,061			9,338			62,678			46,640
Cash paid on decommissioning provision		(403	)		(299	)		(1,652	)		(1,589	)
Transaction costs on asset acquisition		-			-			(1,767	)		-
Changes in non-cash working capital items		(2,342	)		1,302			(2,980	)		(10,615	)
Cash from operating activities		14,316			10,341			56,279			34,436

SALES VOLUMES

Production
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Daily sales volumes – average
Oil (bbls per day)		1,961			2,501			(22	%)		2,343			2,481			(6	%)
NGL (bbls per day)		3,581			2,373			51	%		3,048			2,491			22	%
Natural gas (mcf per day)		33,669			22,529			49	%		28,507			24,878			15	%
Total (boe per day)		11,154			8,629			29	%		10,142			9,118			11	%

Sales volumes mix by product
Oil		18	%		29	%					23	%		27	%
NGL		32	%		28	%					30	%		27	%
Natural gas		50	%		43	%					47	%		46	%
		100	%		100	%					100	%		100	%

Average production for Q4 2011 of 11,154 boe per day was 29% higher than the Q4 2010 production of 8,629 boe per day mainly due to the Hunton acquisition on June 1, 2011, wells drilled and a reactivation and workover program which were partially offset by the disposition of non-core assets on November 15, 2011 totaling 1,750 boe per day and declines in a mature natural gas pool and heavy oil pool in Saskatchewan, Canada. Q4 2011 production remained relatively flat compared to Q3 2011 production of 11,263 boe per day due to Q4 2011 production benefitting from the wells drilled both partway through Q3 2011 and Q4 2011 being offset by the asset disposition in November 2011. For the three months ended December 31, 2011, average production consisted of 1,961 boe per day of oil, 3,581 boe per day of NGLs and 33,669 mcf per day of natural gas, resulting in a mix of 18% oil, 32% NGL and 50% natural gas compared to 29% oil, 28% NGL and 43% natural gas in Q4 2010.

For the year ended December 31, 2011, average production increased 11% to 10,142 boe per day compared to 9,118 boe per day in 2010 mainly due to the Hunton acquisition of 3,100 boe per day on June 1, 2011, wells drilled and a reactivation and workover program which were partially offset by the disposition of assets in November 2011 and declines in production in mature properties.

On January 31, 2012, the Company completed the sale of additional non-core assets in Saskatchewan, which produced approximately 300 boe per day, for proceeds of $8.3 million. Taking into account this asset disposition, the Company expects average production between 9,500 and 9,800 boe per day in 2012 and the sales volume mix is expected to be approximately 51% natural gas, 37% NGLs and 12% oil.

For the year ended December 31, 2011, Equal drilled the following 26 (22.8 net) wells with a 96% success rate:

·	9 (7.5 net) Alliance Viking horizontal oil wells in Alberta;

·	6 (5.3 net) Twin Cities / Central Dolomite Hunton liquids-rich natural gas wells in Oklahoma;

·	6 (5.2 net) Big Bird and K-9 Hunton vertical natural gas wells in Oklahoma;

·	3 (3.0 net) Cardium horizontal oil wells in Alberta;

·	1 (0.8 net) Mississippian well in Oklahoma currently awaiting a fracture stimulation; and

·	1 (1.0 net) dry hole located in Saskatchewan.

Production by Geographic Area
	Three months ended December 31, 2011
	Canada				U.S.				Total
Daily sales volumes – average
Oil (bbls per day)		1,694	65	%		267	3	%		1,961	18	%
NGL (bbls per day)		40	2	%		3,541	41	%		3,581	32	%
Natural gas (mcf per day)		5,218	33	%		28,451	56	%		33,669	50	%
Total (boe per day)		2,604	100	%		8,550	100	%		11,154	100	%

Production by Geographic Area
	Year ended December 31, 2011
	Canada				U.S.				Total
Daily sales volumes – average
Oil (bbls per day)		2,079	65	%		264	4	%		2,343	23	%
NGL (bbls per day)		50	1	%		2,998	43	%		3,048	30	%
Natural gas (mcf per day)		6,558	34	%		21,949	53	%		28,507	47	%
Total (boe per day)		3,222	100	%		6,920	100	%		10,142	100	%

Canadian Operations

In Q4 2011, production in Canada of 2,604 boe per day was down 27% compared to 3,557 boe per day during Q4 2010. The decrease is due to the disposition of non-core assets in November 2011 and higher than anticipated declines in a mature dry gas pool and heavy oil pool in Saskatchewan, Canada. Q4 2011 production was 17% lower than Q3 2011 production of 3,152 boe per day due to the disposition of non-core assets on November 15, 2011. The disposition of non-core assets decreased Q4 2011 production by approximately 875 boe per day.

For the year ended December 31, 2011, production in Canada of 3,222 boe per day was down 21% compared to 4,081 boe per day in 2010. The decrease is due to the disposition of non-core assets in November 2011 and higher than anticipated decline rates in mature properties in Saskatchewan. Delays in drilling and completions in Q4 2010 and Q1 2011 also resulted in lower average production than anticipated for the year.

U.S. Operations

In Q4 2011, production in the United States of 8,550 boe per day was 69% higher compared to 5,072 boe per day during Q4 2010. The increase in production is due to the Hunton acquisition on June 1, 2011 of 3,100 boe per day, wells drilled and a reactivation and workover program. Q4 2011 production increased 5% compared to Q3 2011 production of 8,111 boe per day due to the contribution of new wells drilled and completed over the period.

For the year ended December 31, 2011, production in the United States of 6,920 boe per day increased 37% compared to 5,037 boe per day during 2010. The increase in production is due to the Hunton acquisition, wells drilled during 2011 and a reactivation and workover program.

COMMODITY PRICING

Pricing Benchmarks
	Three months ended December 31							Year ended December 31
	2011		2010		Change			2011		2010		Change
WTI (US$ per bbl)		94.06		85.17		10	%		95.12		79.53		20	%
Average exchange rate: US$ to Cdn$1.00		0.98		0.99		(1	%)		1.01		0.97		4	%
WTI (Cdn$ per bbl)		95.94		86.02		12	%		94.17		81.92		15	%
Edmonton Light		97.35		80.33		21	%		94.83		77.48		22	%
Propane, Conway, Kansas (US$/bbl)		54.32		51.01		6	%		56.89		47.24		20	%
NYMEX (US$ per mmbtu)		3.61		3.81		(5	%)		4.08		4.42		(8	%)
NYMEX (US$ per mcf) (1)		3.74		3.94		(5	%)		4.22		4.57		(8	%)
AECO daily index (Cdn$ per GJ)		3.01		3.43		(12	%)		3.43		3.79		(9	%)
AECO daily index (Cdn$ per mcf) (2)		3.07		3.50		(12	%)		3.50		3.86		(9	%)

(1) Conversion rate of 1.0350 mmbtu per mcf.

(2) Conversion rate of 1.0194 GJ per mcf.

West Texas Intermediate (“WTI”) is a standard benchmark for the price of oil and is expressed in U.S. dollars per barrel. The propane price quoted at Conway, Kansas is the closest surrogate benchmark for the blended price Equal receives for its NGL produced in Oklahoma. The price variations at Conway, Kansas mirror Equal’s variations in NGL price but cannot be used to estimate Equal’s actual NGL mix due to variations in composition. In Western Canada the benchmark for natural gas is the price at the AECO hub (a storage and pricing hub for Canadian natural gas) and is priced in Canadian dollars per gigajoule (“GJ”). For the purposes of financial reporting, Equal expresses its realized prices for oil and gas in Canadian dollars.

Benchmark oil prices for Q4 2011 increased 10% to an average of US$94.06 per bbl WTI from US$85.17 per bbl WTI in Q4 2010. In Canadian dollars, the average price per bbl increased 12% to $95.94 per bbl WTI from $86.02 per bbl WTI. The price increase was partially enhanced by the weakening of the Canadian dollar which averaged US$0.98 per Canadian dollar during Q4 2011 compared to US$0.99 per Canadian dollar during Q4 2010.

Benchmark oil prices for the year ended December 31, 2011 increased 20% to an average of US$95.12 per bbl WTI from US$79.53 per bbl WTI in 2010. In Canadian dollars, the average price per bbl increased 15% to $94.17 per bbl WTI from $81.92 per bbl WTI. The price increase was partially off-set by the strengthening of the Canadian dollar which averaged US$1.01 per Canadian dollar during 2011 compared to US$0.97 per Canadian dollar during 2010.

Benchmark propane prices for Q4 2011 increased 6% to an average of US$54.32 per bbl from US$51.01 per bbl in Q4 2010 which was also partially enhanced, in Canadian dollar terms, by the weakening of the Canadian dollar compared to the U.S. dollar.

Benchmark propane prices for the year ended December 31, 2011 increased 20% to an average of US$56.89 per bbl from US$47.24 per bbl compared to 2010 which was also partially offset, in Canadian dollar terms, by the strengthening of the Canadian dollar compared to the U.S. dollar.

Benchmark natural gas prices for Q4 2011 on the NYMEX decreased 5% to an average of US$3.61 per mmbtu from US$3.81 per mmbtu in Q4 2010. In Canada, AECO pricing decreased 12% to $3.01 per GJ during Q4 2011 compared to $3.43 per GJ during Q4 2010.

Benchmark natural gas prices for the year ended December 31, 2011 on the NYMEX decreased 8% to an average of US$4.08 per mmbtu from US$4.42 per mmbtu compared 2010. In Canada, AECO pricing also decreased 9% to an average of $3.43 per GJ during the year ended December 31, 2011 compared to $3.79 per GJ during 2010.

Average Commodity Prices Received
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010		Change
Oil (Cdn$ per bbl)		87.37			70.07			25	%		82.89			68.82		20	%
Oil commodity contract settlements (Cdn$ per bbl)		(1.47	)		(0.04	)		1000	%		(0.30	)		1.43		(121	%)
Combined oil (Cdn$ per bbl)		85.90			70.03			23	%		82.59			70.25		18	%
NGL (Cdn$ per bbl)		45.61			45.00			1	%		48.02			42.44		13	%
Natural gas (Cdn$ per mcf)		3.37			3.53			(5	%)		3.57			4.05		(12	%)
Natural gas commodity contract settlements (Cdn$ per mcf)		0.45			0.70			(36	%)		0.24			0.52		(54	%)
Combined natural gas (Cdn$ per mcf)		3.82			4.23			(10	%)		3.81			4.57		(17	%)
Total (1) (Cdn$ per boe)		41.28			43.71			(6	%)		44.22			43.18		2	%

(1)	Price received excludes unrealized mark-to-market gain or loss on commodity contracts.

In Q4 2011, the average price received for oil by Equal, net of commodity contract settlements, increased 23% to $85.90 per bbl from $70.03 per bbl in Q4 2010. The average price received for NGLs in Q4 2011 was relatively flat at $45.61 per bbl compared to $45.00 per bbl in Q4 2010. The impact of a significant rise in U.S. dollar denominated WTI crude oil and related NGLs was muted by the strengthening of the Canadian dollar against the U.S. dollar. The average price received for natural gas in Q4 2011, net of commodity contract settlements, decreased 10% to $3.82 per mcf from $4.23 per mcf in Q4 2010.

For the year ended December 31, 2011, the average price received for oil by Equal, net of commodity contract settlements, increased 18% to $82.59 per bbl from $70.25 per bbl during 2010. The average price received for NGLs in 2011, increased 13% to $48.02 per bbl from $42.44 per bbl during 2010. The impact of a significant rise in U.S. dollar denominated WTI crude oil and related NGLs was strongly muted by the strength of the Canadian dollar against the U.S. currency. The average price received for natural gas in 2011, net of commodity contract settlements, decreased 17% to $3.81 per mcf from $4.57 per mcf during 2010.

REVENUES

Revenues (in thousands of Canadian dollars)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011		2010			Change
Oil revenues		15,766			16,124			(2	%)		70,900		62,305			14	%
NGL revenues		15,023			9,827			53	%		53,434		38,579			39	%
Natural gas revenues		10,439			7,317			43	%		37,160		36,790			1	%
Realized gain/(loss) on commodity contracts		1,132			1,436			(21	%)		2,220		6,038			(63	%)
Revenues including realized hedging		42,360			34,704			22	%		163,714		143,712			14	%
Unrealized mark-to-market gain (loss) on commodity contracts		(2,868	)		(3,441	)		(17	%)		5,525		(1,013	)		(645	%)
Revenues including commodity contracts		39,492			31,263			26	%		169,239		142,699			19	%

Revenues by Geographic Area (in thousands of Canadian dollars)
	Three months ended December 31, 2011								Year ended December 31, 2011
	Canada			U.S.		Total			Canada			U.S.		Total
Oil revenues		13,594			2,172		15,766			62,241			8,659		70,900
NGL revenues		303			14,720		15,023			1,512			51,922		53,434
Natural gas revenues		1,605			8,834		10,439			8,902			28,258		37,160
Realized gain/(loss) on commodity contracts		(266	)		1,398		1,132			(155	)		2,375		2,220
Revenues including realized hedging		15,236			27,124		42,360			72,500			91,214		163,714
Unrealized mark-to-market gain/(loss) on commodity contracts		(4,782	)		1,914		(2,868	)		881			4,644		5,525
Revenues including commodity contracts		10,454			29,038		39,492			73,381			95,858		169,239

In Q4 2011, revenues before unrealized mark-to-market gains on commodity contracts increased 22% to $42.4 million from $34.7 million in Q4 2010 due to increased NGL and natural gas revenues which were partially offset by a lower realized gain on commodity contracts and oil revenues.

Oil revenues for Q4 2011 decreased 2% to $15.8 million compared to $16.1 million in Q4 2010 which was the result of a 22% decrease in production volumes which was partially offset by a 25% increase in sales price received for oil. NGL revenues for Q4 2011 increased 53% to $15.0 million from $9.8 million in Q4 2010 which was the result of a 51% increase in production volumes. Natural gas revenues for Q4 2011 increased 43% to $10.4 million from $7.3 million in Q4 2010 which was the result of a 49% increase in production volumes partially offset by a 5% decrease in the sales price received for natural gas.

In Q4 2011, there was a lower realized gain on commodity contracts of $1.1 million compared to a $1.4 million realized gain in Q4 2010 due to higher Q4 2011 oil prices and a lower price hedged for natural gas prices compared to Q4 2010. The unrealized mark-to-market loss on commodity contracts in Q4 2011 was to $2.9 million compared to a loss of $3.4 million during Q4 2010. The unrealized mark-to-market loss on commodity contracts in Q4 2011 was due to the increase in the price for oil at December 31, 2011 compared to September 30, 2011.

For the year ended December 31, 2011, revenues before unrealized mark-to-market losses on commodity contracts increased 14% to $163.7 million from $143.7 million in 2010 as increases in revenues from oil, NGLs and natural gas sales were partially offset by a lower realized gain from commodity contracts.

For the year ended December 31, 2011, oil revenues increased 14% to $70.9 million compared to $62.3 million in 2010 which was the result of a 20% increase in sales price received for oil which was partially offset by a 6% decrease in oil volumes produced. For 2011, NGL revenues increased 39% to $53.4 million from $38.6 million in 2010 which was the result of a 13% increase in sales price received for NGLs and a 22% increase in production volumes. For 2011, natural gas revenues remained relatively flat at $37.2 million compared to $36.8 million in 2010 which was the result of a 15% increase in production volumes offset by a 12% decrease in the sales price received for natural gas.

For the year ended December 31, 2011, the realized gain on commodity contracts was $2.2 million compared to a gain of $6.0 million in 2010 mainly due to higher 2011 oil prices and a lower price hedged for natural gas during 2011 compared to 2010. For 2011, the unrealized mark-to-market gain on commodity contracts was to $5.5 million compared to a loss of $1.0 million in 2010. The unrealized mark-to-market gain on commodity contracts in 2011 is mainly due to the natural gas commodity contracts entered into during Q1 2011 combined with the subsequent decrease in natural gas prices.

For 2012 planning purposes, the Company uses US$90.00 per bbl for WTI, US$4.00 per mmbtu for NYMEX natural gas, $3.50 per mcf for AECO natural gas, an exchange rate of CAD$1.000:US$0.975 and a discount of 47% from US$ WTI for US NGL pricing. The Company constantly monitors actual prices against plan prices and adjusts its operational plans to address variations.

COMMODITY CONTRACTS

The Company has a formal risk management policy which permits management to use specified price risk management strategies for up to 50% of its projected gross crude oil, natural gas and NGL production including fixed price contracts, costless collars and the purchase of floor price options and other derivative instruments to reduce the impact of price volatility and ensure minimum prices for a maximum of 24 months beyond the current date. The program is designed to provide price protection on a portion of Equal’s future production in the event of adverse commodity price movement, while retaining exposure to upside price movements. By doing this, Equal seeks to provide a measure of stability and predictability of cash inflows to enable it to carry out its planned capital spending programs. As of the date of this MD&A for 2012, Equal has the equivalent of 800 bbls per day of oil production hedged at an average price CAD$101.50 per bbl and 10,333 mmbtu per day of natural gas at an average price of USD$4.45 per mmbtu. Based on Q4 2011 average production, the Company has 41% of its oil hedged and 31% of its natural gas which is equivalent to 23% of the Company’s total production.

The mark-to-market value of the commodity contracts is determined based on the estimated fair value as at December 31, 2011 that was obtained from the counterparties to the economic hedges. Equal then evaluates the reasonableness of the valuations in comparison to the value of other commodity contracts it currently owns as well as recently quoted prices received from other counterparties for various commodity contracts. The Company deals with large, credit-worthy financial institutions to diversify its counterparty risk. The credit worthiness of each counterparty is assessed at the time of purchase of each financial instrument and is regularly assessed based on any new information regarding the counterparty.

At December 31, 2011, Equal had the following financial derivatives and fixed price contracts outstanding:

Derivative Instrument	Commodity	Price (2)	Volume per day (2)	Period
Fixed	Gas	4.50 (US$/mmbtu) (4.66 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – March 31, 2012
Fixed	Gas	4.83 (US$/mmbtu) (5.00 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – March 31, 2012
Fixed	Gas	4.95 (US$/mmbtu) (5.12 US$/mcf)	2,000 mmbtu (1,932 mcf)	January 1, 2012 – December 31, 2012
Fixed	Gas	5.00 (US$/mmbtu) (5.18 US$/mcf)	5,000 mmbtu (4,831 mcf)	January 1, 2012 – December 31, 2012

Fixed Basis Differential (1)	Gas	Differential Fixed @ $0.35 US$/mmbtu ($0.36 US$/mcf)	7,000 mmbtu (6,763 mcf)	January 1, 2012 – December 31, 2012

Fixed	Oil	100.00 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012
Fixed	Oil	101.05 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012
Fixed	Oil	101.95 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012
Fixed	Oil	103.00 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012

(1)	NYMEX / Southern Star (Oklahoma) basis differential.

(2)	Conversion rates of 1.0350 mmbtu per mcf.

As at December 31, 2011 the above commodity contracts had a net mark-to-market asset position of $4.8 million compared to a net liability balance of $0.8 million on December 31, 2010. This mark-to-market asset position at December 31, 2011 relates primarily to the natural gas contracts which have hedged prices higher than the market prices at December 31, 2011.

Subsequent to December 31, 2011, Equal entered into the following commodity contracts:

Derivative Instrument	Commodity	Price (2)	Volume per day (2)	Period
Collar	Gas	Floor: 2.50 (US$/mmbtu) (2.59 US$/mcf) Ceiling: 3.45 (US$/mmbtu) (3.57 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2012 – October 31, 2012
Fixed	Gas	3.00 (US$/mmbtu) (3.11 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2012 – October 31, 2012

Fixed Basis Differential (1)	Gas	Differential Fixed @ $0.21 US$/mmbtu ($0.22 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2012 – October 31, 2012

Fixed	Oil	101.00 ($/bbl)	200 bbl	January 1, 2013 – December 31, 2013
Fixed	Oil	101.50 ($/bbl)	200 bbl	January 1, 2013 – December 31, 2013
Fixed	Oil	102.50 ($/bbl)	200 bbl	January 1, 2013 – December 31, 2013

(1)	NYMEX / Southern Star (Oklahoma) basis differential.

(2)	Conversion rates of 1.0350 mmbtu per mcf.

ROYALTIES

Royalties include crown, freehold and overriding royalties, production taxes and wellhead taxes. Royalties vary depending on the jurisdiction, volumes that are produced, total volumes sold and the price received.

Royalties (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Royalties		8,505			6,963			22	%		33,054			29,330			13	%
As a percentage of revenues before commodity contracts		21	%		21	%					20	%		21	%
Royalties per boe ($)		8.29			8.77			(5	%)		8.93			8.81			1	%

Royalties by Geographic Area (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31, 2011						Year ended December 31, 2011
	Canada			U.S.			Canada			U.S.
Royalties		2,028			6,477			11,416			21,638
As a percentage of revenues before commodity contracts		13	%		25	%		16	%		24	%
Royalties per boe ($)		8.47			8.23			9.71			8.57

In Q4 2011, royalties increased 22% to $8.5 million from $7.0 million in Q4 2010 primarily due to higher NGL and natural gas production and higher oil prices received. As a percentage of revenues before commodity contracts, royalties in Q4 2011 were consistent with Q4 2010 due to lower royalties on new horizontal oil wells drilled in Alberta being offset by higher royalties in Oklahoma as a result of increased production. Q4 2011 royalties were 7% lower compared to Q3 2011 royalties of $9.1 million due to lower oil and NGL revenues in Q4 2011.

During the year ended December 31, 2011, royalties increased 13% to $33.1 million from $29.3 million from 2010 primarily as a result of higher oil and NGL revenues.

Royalty rates in 2012 are expected to slightly decrease compared to 2011 due to the planned drilling of horizontal wells in Canada which incur a reduced royalty of 5% for up to 36 months and the drilling of horizontal Hunton wells which receive a 6% production tax rebate for the first 48 months resulting in approximately 20% royalties on new wells in Oklahoma.

PRODUCTION EXPENSE

Production Expense (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended December 31
	2011		2010		Change			2011		2010		Change
Production expense		10,431		8,469		23	%		41,557		35,826		16	%
Production expense per boe ($)		10.17		10.67		(5	%)		11.22		10.76		4	%

In Q4 2011, production expenses increased 23% to $10.4 million from $8.5 million in Q4 2010 due to higher production volumes. Production expense on a per boe basis decreased 5% to $10.17 per boe in Q4 2011 compared to $10.67 per boe in Q4 2010 mainly due to the production from the Hunton acquisition in Q2 2011 having lower than Company average operating costs per boe and the disposition of non-core properties in Canada with higher than Company average production costs which was partially offset by the unexpected production declines in mature natural gas and heavy oil properties in Saskatchewan, Canada with a high proportion of fixed costs. Q4 2011 production costs decreased 8% compared to $11.11 per boe in Q3 2011 primarily due to the disposition of non-core properties in Canada with higher than Company average production costs.

For the year ended December 31, 2011, production costs increased 16% to $41.6 million from $35.8 million in 2010 due to higher production volumes. For 2011, production expense on a per boe basis increased 4% to $11.22 per boe from $10.76 per boe in 2010 mainly due to production declines in mature properties with a high proportion of fixed costs which was partially offset by the production from the Hunton acquisition in Q2 2011 having lower than Company average operating costs per boe and the disposition of non-core properties in Canada with higher than Company average production costs.

Production Expense by Geographic Area (in thousands except for per boe amounts)
	Three months ended December 31, 2011				Year ended December 31, 2011
	Canada		U.S.		Canada		U.S.
Production expenses		5,113		5,318		24,649		16,908
Production expenses per boe ($)		21.34		6.76		20.96		6.69

Canadian Operations

In Canada for Q4 2011, production expenses were $5.1 million which was 11% lower than $5.7 million in Q4 2010. On a per boe basis, production expenses increased 23% to $21.34 per boe in Q4 2011 compared to $17.32 per boe in Q4 2010 due to production declines in mature properties with a high proportion of fixed costs, increased workovers to optimize and maintain production and the increase of the oil weighting of the total production which was partially offset by the disposition of non-core properties in Canada with higher than Company average production costs. Q4 2011 production costs per boe decreased 9% compared to $23.50 per boe in Q3 2011 mainly due to the disposition of non-core properties in Canada with higher than Company average production costs, the downtime in Q3 2011 associated with a third party processor’s turnaround and additional power and workover costs incurred in Q3 2011.

In Canada for the year ended December 31, 2011, production expenses decreased to $24.6 million compared to $25.4 million in 2010. On a per boe basis, production expenses increased 23% to $20.96 per boe compared to $17.03 per boe in 2010 mainly due to additional costs from an extremely wet first 6 months of the year (maintenance and labour), production declines in mature properties with a high proportion of fixed costs and the sale of natural gas weighted properties in 2010 having lower production costs per boe which were partially offset by the disposition of non-core properties with higher than Company average production costs.

U.S. Operations

In the U.S. for Q4 2011, overall production expenses increased by 89% to $5.3 million from $2.8 million mainly due to the increased volumes from the Hunton acquisition in Q2 2011 and the addition of new wells drilled during the year. On a per boe basis, production expense increased 13% to $6.76 per boe from $6.00 per boe in Q4 2010 mainly due to the initial high water volumes from newly completed wells during their early producing phase and the increased utilization of rental pumps in the older producing wells. Q4 2011 production expenses per boe increased by 7% compared to Q3 2011 production expenses of $6.30 per boe due to the initial high water volumes from newly completed wells during their early producing phase.

In the U.S. for the year ended December 31, 2011, production expenses increased by 61% to $16.9 million from $10.5 million in 2010 mainly due to the Hunton acquisition in Q2 2011 and the addition of new wells drilled during the year. On a per boe basis, production expense increased by 18% to $6.69 per boe versus $5.69 per boe in 2010 due to the initial high water volumes from newly completed wells during their early producing phase and the increased utilization of rental pumps in the older producing wells.

TRANSPORTATION EXPENSE

Transportation expense is a function of the point of legal transfer of the product and is dependent upon where the product is sold, production split, location of properties as well as industry transportation rates that are driven by supply and demand of available transport capacity.

Transportation Expense (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended December 31
	2011		2010		Change			2011		2010		Change
Transportation expense		343		629		(45	%)		1,665		2,370		(30	%)
Transportation expense per boe ($)		0.33		0.79		(58	%)		0.45		0.71		(37	%)

In Q4 2011, transportation costs decreased 58% to $0.33 per boe from $0.79 per boe in Q4 2010 and decreased 15% compared to $0.39 per boe in Q3 2011. The decrease in transportation expense is due to the re-allocation of certain costs against revenues.

For the year ended December 31, 2011, transportation costs decreased 37% to $0.45 per boe from $0.71 per boe in 2010. The decrease in transportation expense is due to the re-allocation of certain costs against revenues.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expense (“G&A”) decreased by 49% in Q4 2011 compared to Q4 2010 on a total dollar basis and decreased by 61% on a per boe basis.

General and Administrative Expense (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Gross G&A expense		4,220			7,693			(45	%)		17,162			24,392			(30	%)
Capitalized		(327	)		(95	)		244	%		(1,588	)		(1,530	)		4	%
Recoveries		(676	)		(1,300	)		(48	%)		(2,660	)		(3,635	)		(27	%)
G&A expense		3,217			6,298			(49	%)		12,914			19,227			(33	%)
G&A expense per boe ($)		3.13			7.93			(61	%)		3.49			5.78			(40	%)

In Q4 2011, G&A costs were $3.2 million ($3.13 per boe) compared to $6.3 million ($7.93 per boe) in Q4 2010. The decrease in G&A is due to legal fees in Q4 2010 related to court proceedings involving a former joint venture participant that ended in Q2 2011. Q4 2011 G&A costs increased by 14% compared to $2.8 million in Q3 2011.

For the year ended December 31, 2011, G&A costs were $12.9 million ($3.49 per boe) compared to $19.2 million ($5.78 per boe) in 2010. The decrease in G&A is mainly due to higher costs in 2010 for professional fees incurred for the Plan of Arrangement and legal fees related to court proceedings involving a former joint venture participant that ended during Q2 2011.

SHARE-BASED COMPENSATION EXPENSE

Share-Based Compensation Expense (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Gross share-based compensation expense		1,368			498			175	%		4,284			3,205			34	%
Capitalized		(134	)		(63	)		113	%		(316	)		(305	)		4	%
Share-based compensation expense		1,234			435			184	%		3,968			2,900			37	%
Share-based compensation expense per boe ($)		1.20			0.55			118	%		1.07			0.87			23	%

In Q4 2011, non-cash share-based compensation expense was $1.2 million compared to $0.4 million in Q4 2010 and $1.4 million in Q3 2011. The Q4 2011 increase in the share-based compensation expense is due to the higher number of restricted shares and options outstanding during the period that were issued in May 2011 which is in advance of the normal issuance of the last quarter of each year as part of the employee retention initiative.

For the year ended December 31, 2011, non-cash share-based compensation expense was $4.0 million compared to $2.9 million in 2010. The increase in the share-based compensation expense is due to the higher number of restricted shares and options outstanding during the period that were issued in May 2011 which is in advance of the normal issuance of the last quarter of each year as part of the employee retention initiative.

DEPLETION AND DEPRECIATION (“D&D”)

Depletion and Depreciation (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended December 31
	2011		2010		Change			2011		2010		Change
D&D		17,046		9,938		72	%		53,229		47,252		13	%
D&D per boe ($)		16.61		12.52		33	%		14.38		14.20		1	%

In Q4 2011, D&D expenses increased 72% to $17.0 million ($16.61 per boe) compared to $9.9 million ($12.52 per boe) in Q4 2010. The increase in D&D expenses in Q4 2011 compared to Q4 2010 is mainly due to the 29% increase in production and negative revisions to the December 31, 2011 reserves. Q4 2011 D&D expenses increased 22% compared to $13.9 million in Q3 2011 due to the negative revisions to the December 31, 2011 reserves. The negative reserve revisions were due to the decrease in forecasted prices for natural gas and performance of wells in certain areas.

For the year ended December 31, 2011, D&D expenses increased 13% to $53.2 million ($14.38 per boe) compared to $47.3 million ($14.20 per boe) in 2010. The increase in D&D expenses is mainly due to the 11% increase in production and negative revisions to the December 31, 2011 reserves. The negative reserve revisions were due to the decrease in forecasted prices for natural gas and performance of wells in certain areas.

IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT

For the three and twelve months ended December 31, 2011, the impairment in property, plant and equipment was $27.5 million compared to $31.1 million in the same periods in 2010. The impairment in 2011 is due to cost overruns in certain wells drilled, the decrease in forecasted prices for natural gas, the performance of wells in certain areas and the write-down of certain underperforming assets that were sold in January 2012. The impairment in 2010 was the result of the decrease in forecasted prices for natural gas.

INTEREST EXPENSE

The cash portion of interest expense in Q4 2011 was $2.8 million which was comprised of interest on long-term debt of $1.3 million and interest on convertible debentures of $1.5 million. The non-cash portion of interest expense in Q4 2011 was $0.2 million for the accretion of convertible debentures.

Interest Expense (in thousands of Canadian except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Cash interest expense on long-term debt		1,341			461			191	%		4,250			2,364			80	%
Cash interest expense on convertible debentures		1,455			2,398			(39	%)		7,088			9,684			(27	%)
Cash interest income		(1	)		(29	)		(97	%)		(28	)		(748	)		(96	%)
Subtotal cash interest expense		2,795			2,830			(1	%)		11,310			11,300			0	%
Non-cash amortization of premium on convertible debentures		-			(32	)		(100	%)		(21	)		(74	)		(72	%)
Non-cash accretion on convertible debentures		207			-			100	%		753			-			100	%
Total interest expense		3,002			2,798			7	%		12,042			11,226			7	%
Cash interest expense per boe on long-term debt ($)		1.30			0.58			124	%		1.15			0.71			62	%
Cash interest expense per boe on convertible debentures ($)		1.42			3.02			(53	%)		1.91			2.91			(34	%)
Cash interest income per boe ($)		-			(0.04	)		(100	%)		(0.01	)		(0.22	)		(95	%)
Total cash interest expense per boe ($)		2.72			3.56			(24	%)		3.05			3.40			(10	%)

In Q4 2011, cash interest expense was relatively flat at $2.8 million compared to Q4 2010 due to the increase in the amount borrowed on the credit facility which was offset by lower interest paid on the convertible debentures. The amount borrowed from the bank credit facility was used for the Hunton acquisition in June 2011 and the lower interest on convertible debentures is due to a lower amount of debentures outstanding and lower interest rates on the remaining convertible debentures. Q4 2011 cash interest expense was consistent with the $2.9 million cash interest expense in Q3 2011.

For the year ended December 31, 2011, cash interest expense was $11.3 million which is consistent with 2010. The lower cash interest expense on convertible debentures was offset by higher interest on the long-term debt due to a greater outstanding balance and lower interest income.

Equal’s long-term debt balance at December 31, 2011 was $138.8 million compared to $24.9 million at December 31, 2010. The increase is due to use of the credit facility to redeem part of the 8.0% convertible debentures in March 2011, the Hunton acquisition in June 2011 and capital spending in excess of cash flows for the year. The average interest rate on long-term debt for 2011 was 3.8% and the rate as of March 20, 2012 is approximately 3.2%.

ACCRETION OF DECOMMISSIONING PROVISION

In Q4 2011 and Q4 2010, the accretion of the decommissioning provision was $0.2 million.

For the years ended December 31, 2011 and 2010, the accretion of the decommissioning provision was $0.7 million.

GAIN/LOSS ON DISPOSAL OF ASSETS

In Q4 2011, there was a gain on disposal of assets of $16.8 million compared to a gain of $0.2 million in Q4 2010. The gain in Q4 2011 was the result of the sale of non-core assets in British Columbia and Alberta which predominately produced natural gas.

For the year ended December 31, 2011, the gain on disposal of assets was $17.6 million compared to a gain of $2.0 million during 2010. The gain in Q4 2011 is mainly due to the sale of non-core assets in British Columbia and Alberta which predominately produced natural gas.

TRANSACTION COSTS FOR ASSET ACQUISITION

In June 2011, transaction costs for the Hunton acquisition related to legal and financial advisory fees were $1.8 million.

REDEMPTION PREMIUM ON CONVERTIBLE DEBENTURES

In Q4 2011, the remaining 8.25% convertible debentures with a face value of $39.2 million were cancelled pursuant to the normal course issuer bid which resulted in a payment of a redemption premium of $1.0 million.

For the year ended December 31, 2011, the redemption premium on convertible debentures was $2.9 million which is mainly the result of Equal’s 8% convertible debentures redeemed in Q1 2011 and the 8.25% convertible debentures in Q4 2011.

FOREIGN EXCHANGE

In Q4 2011, there was a foreign exchange gain of $5.1 million compared to a loss of $0.1 million in Q4 2010.

For the year ended December 31, 2011, the foreign exchange loss was $4.7 million compared to a gain of $1.3 million 2010. The foreign exchange gains and losses are mainly a result of the long-term debt balance at each period end being revalued at the closing exchange rate and will fluctuate with the exchange rate until it is settled.

TAXES

In Q4 2011, the deferred income tax expense is $3.3 million compared to the deferred income tax expense of $3.0 million in Q4 2010.

For the year ended December 31, 2011, the deferred income tax expense is $4.5 million compared to a deferred income tax expense of $1.6 million during 2010.

NET INCOME

Q4 2011 had a loss of $14.4 million (loss of $0.42 per share) compared to a loss of $38.6 million (loss of $1.39 per share) in Q4 2010. The decrease in the loss in Q4 2011 compared to Q4 2010 was mainly the result of increased revenues from NGLs and natural gas, a $16.8 million gain on sale of assets, a $5.2 million unrealized gain on foreign exchange and lower G&A expenses which were partially offset by higher royalties, production expenses, share-based compensation, depletion and impairment of property, plant and equipment.

For the year ended December 31, 2011, there was a loss of $14.0 million (loss of $0.44 per share) compared to a loss of $42.7 million (loss of $1.73 per share) during 2010. The decrease in loss was mainly the result of increased revenues from oil and NGLs, a $17.6 million gain on sale of assets, an unrealized gain on commodity contracts of $5.5 million and lower G&A expenses which were partially offset by a lower realized gain on commodity contracts, higher royalties, production expenses, foreign exchange loss and impairment of property, plant and equipment.

ADDITIONAL GAAP MEASURES

Equal uses certain additional GAAP measures that are not defined terms under IFRS to assess performance. Management believes these measures provide useful supplemental information to investors. The following are the measures Equal uses in assessing performance.

Funds from Operations

The Company considers funds from operations a key measure for the ability of the Company to repay debt and to fund future growth through capital investment. Funds from operations, as presented, is not intended to represent cash provided by operating activities nor should it be viewed as an alternative to cash provided by operating activities or other measures of financial performance calculated in accordance with GAAP. All references to funds from operations throughout this MD&A are based on cash provided by operating activities as reconciled in the table below:

Funds from Operations (in thousands of Canadian dollars)
	Three months ended December 31					Year ended December 31
	2011		2010			2011		2010
Cash provided by operating activities		14,316		10,341			56,279		34,436
Changes in non-cash working capital items		2,342		(1,302	)		2,980		10,615
Decommissioning provision costs incurred		403		299			1,652		1,589
Transaction costs for asset acquisition		-		-			1,767		-
Funds from operations		17,061		9,338			62,678		46,640

In Q4 2011, funds from operations increased by 83% to $17.1 million from $9.3 million in Q4 2010. The increase in funds from operations is mainly due to the increase in commodity prices for oil, the increase in production of NGLs and natural gas and the decrease in G&A expenses which were partially offset by the increase in production expenses and royalties.

For the year ended December 31, 2011, funds from operations increased 34% to $62.7 million from $46.6 million in 2010 primarily due to the increase in commodity prices for oil and NGLs, the increase in production of NGLs and natural gas and the decrease in G&A expenses which were partially offset by the lower realized gain on commodity contracts, higher production expenses and higher royalties.

NON-GAAP FINANCIAL MEASURES

Management uses certain key performance indicators (“KPIs”) and industry benchmarks such as cash flow netback, funds from operations and working capital including long-term debt to analyze financial performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for Equal. These KPIs and benchmarks as presented do not have any standardized meanings prescribed by IFRS and previous Canadian GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities.

Cash Flow Netback

Management uses cash flow netback to analyze the profitability of its operations. Cash flow netback, as presented, is not intended to represent an alternative to net income (loss) or other measures of financial performance calculated in accordance with GAAP. All references to cash flow netback throughout this MD&A are based on the reconciliation in the following table:

Cash Flow Netback (in thousand of Canadian dollars, except for per share and per boe amounts)
	Three months ended December 31						Year ended December 31
	2011			2010			2011			2010
Net income/(loss)		(14,428	)		(38,556	)		(13,960	)		(42,652	)
Share-based compensation		1,234			435			3,968			2,900
Depletion and depreciation		17,046			9,938			53,229			47,252
Impairment in property, plant and equipment		27,486			31,114			27,486			31,114
Non-cash interest on convertible debentures		207			(32	)		732			(74	)
Accretion of decommissioning provision		199			192			727			769
Unrealized commodity contracts (gain)/loss		2,868			3,441			(5,525	)		1,013
Gain on sale of assets		(16,769	)		(200	)		(17,595	)		(2,005	)
Transaction costs on asset acquisition		-			-			1,767			-
Redemption premium on convertible debentures		1,071			-			2,975			-
Revaluation of convertible debentures		-			-			-			5,295
Amortization of trust unit issue costs		-			-			-			1,000
Unrealized foreign exchange (gain)/loss		(5,177	)		55			4,416			384
Deferred tax (reduction)/expense		3,324			2,951			4,458			1,644
Funds from operations		17,061			9,338			62,678			46,640
Total volume (mboe)		1,025			794			3,702			3,328
Cash flow netback (non-GAAP) ($ per boe)		16.64			11.76			16.93			14.01

CAPITAL EXPENDITURES

Capital Expenditures (in thousands of Canadian dollars except for percentages)
	Three months ended December 31									Year ended December 31
	2011			2010			Change			2011			2010			Change
Property, plant and equipment expenditures		7,969			14,406			(45	%)		69,800			60,053			16	%
Exploration and evaluation expenditures		320			11,047			(97	%)		11,791			17,625			(33	%)
Hunton asset acquisition (1)		-			-			0	%		91,656			-			100	%
Amounts recovered under agreement		-			-			0	%		-			(3,503	)		(100	%)
Dispositions		(38,939	)		(40	)		1000	%		(41,144	)		(26,272	)		57	%
Total		(30,650	)		25,413			(221	%)		132,103			47,903			176	%

(1) Includes the settlement of $5.6 million (US$5.8 million) in receivables from JV Participant.

During the year ended December 31, 2011, Equal’s net capital expenditures were $132.1 million, of which Equal spent $173.2 million in total capital expenditures and received $41.1 million from dispositions of non-core properties.

Expenditures in Canada for the year ended December 31, 2011, totaled $47.3 million and dispositions totaled $41.1 million. The major components of these expenditures include:

·	$33.1 million on wells, drilling and workovers;

·	$10.0 million on facilities and other equipment maintenance;

$3.0 million on land and seismic acquisition; and

$1.2 million related to the capitalization of certain G&A costs attributable to exploration and development activities.

Expenditures in the U.S. for the year ended December 31, 2011, totaled $125.9 million. The major components of these expenditures include:

·	$91.7 million to acquire the working interests in shared wells from a former joint venture participant (US$95.0 million at $0.965 CAD/USD);

·	$23.5 million related to wells, drilling and workovers;

·	$2.6 million on acquisitions of land for future development in Oklahoma;

·	$7.6 million on capital enhancements; and

·	$0.5 million related to the capitalization of certain G&A costs attributable to exploration and development activities.

During 2011, the Company drilled 13 wells in Canada and 13 wells in Oklahoma. The wells drilled in Canada focused on the light oil plays in the Alberta-based Cardium and Viking resources plays. The wells drilled in Oklahoma focused on the liquids-rich natural gas Hunton play while at the same time preserving rights in the Mississippian play.

Equal’s near term drilling will continue to be focused on light oil targets and liquids-rich gas targets. The Alberta-based Cardium and Viking resource plays have operating margins significantly higher than the Company’s current average Canadian production and will be pursued throughout 2012. In Oklahoma, management expects a minimum ten well drilling program in the Hunton in 2012. With this focus on light oil and liquids-rich natural gas, Equal expects its cash flow netback to improve over time.

Equal operates all of its drilling and can dictate the pace and targets of its drilling programs; therefore, the Company can adjust quickly to the changes in commodity prices if necessary. Equal has an extensive drilling inventory so it can increase capital spending in a higher commodity price environment and has the financial flexibility to do so with its credit facility.

The Company plans in 2012 include up to six light oil Viking wells at Alliance (Alberta), three Cardium light oil wells at Lochend (Alberta), four liquids-rich natural gas wells at K-9 (Oklahoma) and up to nine liquids-rich natural gas wells at Twin Cities Central Dolomite (Oklahoma).

BUSINESS RISKS

The disclosures under this heading should be read in conjunction with Note 12 to the consolidated financial statements.

In the current volatile economic and financial market conditions, Equal continually assesses its risks and manages those risks to the best of its abilities. Equal is exposed to normal market risks inherent in the oil and natural gas business, including commodity prices, credit risk, financing risk, reserve estimates, foreign currency rates, acquisitions and environmental risk. From time to time, Equal attempts to mitigate its exposure to these risks by using commodity hedging contracts and by other means. These risks are described in more detail in Equal’s annual filings with securities regulatory authorities.

Commodity Prices

Commodity price fluctuations are among Equal’s most significant exposures. Crude oil prices are influenced by worldwide factors such as supply and demand fundamentals, OPEC actions and political events. Natural gas prices are influenced by oil prices, North American natural gas supply and demand factors including weather, storage levels and LNG imports. NGL prices are dictated by a combination of supply versus demand related to industrial activity, oil prices and heating requirements. In accordance with policies approved by the Board of Directors, Equal, from time to time, manages these risks through the use of fixed physical contracts, swaps, collars or other commodity contracts. For a summary of outstanding oil and natural gas contracts, please refer to “Commodity Contracts” in this MD&A and in Note 12 to the consolidated financial statements.

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. The receivables are principally with customers in the oil and gas industry and are subject to normal industry credit risk. The Company continues to assess the strength of its counterparties and tries to do business with high quality companies with substantial assets. The counterparties on the commodity contracts are large well financed entities. Management continuously monitors credit risk and credit policies to ensure exposures to customers are limited.

Financing Risk

Equal currently maintains a portion of its debt in floating-rate bank facilities which results in exposure to fluctuations in short-term interest rates which have, for a number of years, been lower than longer-term rates. In June 2011, Equal’s Bank Syndicate completed a borrowing base review and increased the borrowing base to $200.0 million. The borrowing base was set based on Equal’s oil, NGL and natural gas reserves using the Bank Syndicate’s future commodity price deck at the time of review.

The next review of the bank credit facility is expected to be completed in May 2012.

Reserve Estimates

The reserves information contained in Equal’s independent reserve evaluations are estimates. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserve evaluators. The reserve reports were prepared using certain commodity price assumptions. If lower prices for oil, NGLs and natural gas are realized by Equal and substituted for the price assumptions utilized in those reserve reports, the present value of estimated future net cash flows for Equal’s reserves as well as the amount of Equal’s reserves would be reduced and the reduction could be significant.

Foreign Currency Rates

Equal’s U.S. operations accounted for 77% of Equal’s total 2011 production; therefore, fluctuations in the U.S. dollar to Canadian dollar exchange rate will impact the Company’s revenues due to the Company translating the revenues from the U.S. operations into Canadian dollars. The Company also has commodity contracts denominated and settled in U.S. dollars.

Interest Rates

Interest rate risk arises from changes in market interest rates that may affect the fair value of future cash flows from the Company’s financial instruments. Equal has a floating interest rate for its long-term debt and fixed interest rate for its convertible debentures.

Acquisitions

The price paid for acquisitions is based on engineering and economic estimates of the potential reserves made by independent engineers modified to reflect the technical views of management. These assessments include a number

of material assumptions regarding such factors as recoverability and marketability of oil, NGLs and natural gas, future prices of oil, NGLs and natural gas and operating costs, future capital expenditures and royalties and other government levies that will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and Equal. In particular, changes in the prices of and markets for oil, NGLs and natural gas from those anticipated at the time of making such assessments will affect the value of the shares. In addition, all such estimates involve a measure of geological and engineering uncertainty that could result in lower production and reserves than attributed to the working interests. Actual reserves could vary materially from these estimates. Consequently, the reserves acquired may be less than expected, which could adversely impact cash flows and distributions to shareholders.

Environmental

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of Equal or its working interests. Such legislation may be changed to impose higher standards and potentially more costly obligations on Equal. There is uncertainty regarding the Federal Government’s Regulatory Framework for Air Emissions (“Framework”), as issued under the Canadian Environmental Protection Act. Additionally, the potential impact on the Company’s operations and business of the Framework, with respect to instituting reductions of greenhouse gases, is not possible to quantify at this time as specific measures for meeting Canada’s commitments have not been developed.

Liquidity Risk

Liquidity risk is the risk that Equal is unable to meet its financial liabilities as they come due. Management utilizes a long-term financial and capital forecasting program that includes continuous review of debt forecasts to ensure credit facilities are sufficient relative to forecast debt levels, capital program levels are appropriate and financial covenants will be met. In the short term, liquidity is managed through daily cash management activities, short-term financing strategies and the use of commodity hedging contracts to increase the predictability of cash flow from operating activities. Additional information on specific instruments is discussed in the “Commodity Contracts” section, “Liquidity and Capital Resources” section and in Note 12 to the consolidated financial statements.

As of December 31, 2011, Equal has commitments for the following payments over the next five years:

Commitments
(in thousands of Canadian dollars)	2012		2013		2014		2015 – 2016	Total
Long-term debt (1)		-		138,820		-	-		138,820
Interest on long-term debt (2)		4,539		2,176		-	-		6,715
Convertible debentures (3)		-		-		-	45,000		45,000
Interest on convertible debentures (3)		3,038		3,038		3,038	3,798		12,912
Accounts payable & accrued liabilities		24,239		-		-	-		24,239
Decommissioning provision		557		-		-	-		557
Office leases (4)		1,211		1,169		1,178	1,472		5,030
Vehicle and other operating leases		168		101		76	-		345
Total obligations		33,752		145,304		4,292	50,270		233,618

(1) Assumes the credit facilities are not renewed on June 24, 2012. As at December 31, 2011, the long-term debt balance consisted of US$136.5 million converted at the closing exchange rate of CDN$1.017 per US$1.00.

(2) Assumes an interest rate of 3.27% (the rate on December 31, 2011).

(3) The 6.75% convertible debentures with an outstanding face value of $45.0 million mature on March 31, 2016.

(4) Future office lease commitments may be reduced by sublease recoveries totaling $0.1 million.

LIQUIDITY & CAPITAL RESOURCES

On February 9, 2011, Equal issued $45.0 million of convertible unsecured junior subordinated debentures with a face value of $1,000 per debenture that mature on March 31, 2016 and bear interest at 6.75% per annum paid semi-annually on March 31 and December 31 of each year. The 6.75% convertible debentures are convertible at the option of the holder into shares at any time prior to the maturity date at a conversion price of $9.00 per share.

Also on February 9, 2011, Equal issued a redemption notice to fully redeem its outstanding 8% convertible debentures whereby the outstanding principal amount $79.9 million was redeemed on March 14, 2011. The proceeds from the 6.75% convertible debentures, in addition to the credit facility, were used to redeem the outstanding 8% convertible debentures. The issue of new 5-year convertible debentures and the redemption of the 8% convertible debentures which was due December 31, 2011 significantly extended the overall term of the Company’s outstanding debt and reduced borrowing costs.

On May 19, 2011, Equal completed a $50.3 million bought deal financing of 6,850,000 common shares at a price of $7.35 per common share. Proceeds from the bought deal were used to acquire Petroflow’s interests in assets developed pursuant to the now terminated farmout agreement between the Company and Petroflow/NAPCUS, and settle all outstanding legal matters and other claims between the Company and Petroflow, Compass and Texas Capital.

On November 16, 2011, Equal issued a redemption notice to fully redeem its outstanding 8.25% convertible debentures whereby the outstanding principal amount $39.1 million was redeemed on December 15, 2011. The proceeds from the November 15, 2011 asset sale were used to redeem the outstanding 8.25% convertible debentures. The redemption of the 8.25% convertible debentures significantly decreases the Company’s outstanding debt and reduces borrowing costs.

Development activities and acquisitions may be funded internally through cash flow or through external sources such as debt or the issuance of equity. The Company finances its operations and capital activities primarily with funds generated from operating activities, but also through the issuance of shares, debentures and borrowing from its credit facility. The amount of equity Equal may raise through the issuance of shares depends on many factors including projected cash needs, availability of funding through other sources, share price and the state of the capital markets. The Company believes its sources of cash, including bank debt and funds from operations, will be sufficient to fund its operations and anticipated capital expenditure program in 2012. Equal’s ability to fund its operations will also depend on operating performance and is subject to commodity prices and other economic conditions which may be beyond its control. The Company will monitor commodity prices and adjust the 2012 capital expenditure program to stay within its means. The Company operates all of its drilling programs and as a result, can control the pace and targets of its capital spending to react quickly to changes in cash flow to ensure ongoing financial flexibility.

Equal’s capital structure at December 31, 2011 is as follows:

	December 31, 2011						December 31, 2010
Capitalization (in thousand of Canadian dollars except percentages)	Amount			%			Amount		%
Long-term debt (1)		138,820			43	%		24,865		8	%
Working capital deficit (surplus)(2) excluding long-term debt		(15,101	)		(5	%)		11,878		3	%
Working capital deficit (surplus)(2) including long-term debt		123,719			38	%		36,743		11	%
Convertible debentures		41,327			13	%		119,902		37	%
Shares issued, at market (3)		159,638			49	%		169,584		52	%
Total capitalization		324,684			100	%		326,229		100	%

(1)	As at December 31, 2011, the long-term debt balance consisted of US$136.5 million converted at the closing exchange rate of CDN$1.017 per US$1.00.

(2)	Working capital excludes deferred revenues and unrealized gains and losses on commodity contracts.

(3)	The market price of Equal’s shares on December 31, 2011 was $4.59 per share (December 31, 2010 – $6.12 per share).

Long-term Debt

Long-term debt is represented by the amounts drawn on the bank credit facility. At December 31, 2011, Equal’s long-term debt consisted of US$136.5 million which was the equivalent of CDN$138.8 million converted at the closing exchange rate of CDN$1.017 per US$1.00. This increase of $113.9 million from $24.9 million at December 31, 2010 is mainly due to the use of the credit facility for a portion of the early redemption of the 8% convertible debentures and the Hunton acquisition in Oklahoma. Equal has credit facilities with its banking syndicate that includes revolving and operating credit facilities which have a borrowing capacity of $200.0 million.

Equal monitors capital using an interest coverage ratio that has been externally imposed as part of the credit agreement. Equal is required to maintain an interest coverage ratio greater than 3.00 to 1.00; this ratio is calculated as follows:

	As at December 31
(in thousands of Canadian dollars except for ratios)	2011		2010
Interest coverage (1):
Cash flow over the prior four quarters		69,246		58,688
Interest expenses over the prior four quarters		11,338		12,048
Interest coverage ratio	6.11 : 1.00		4.87 : 1.00

(1)	These amounts are defined terms within the credit agreements.

Working Capital

The working capital at December 31, 2011 was $15.1 million compared to a working capital deficit at December 31, 2010 of $11.9 million due to the assets and associated liabilities held for sale of $8.3 million (net), an increase of $10.0 million in working capital from a settlement agreement with JV Participant, an increase in cash of $3.0 million, an increase in accounts receivable of $0.3 million and a decrease in accounts payable of $7.1 million partially offset with a decrease in prepaid expenses of $1.2 million and an increase of $0.6 million for the current portion of decommissioning provision.

	As at December 31
Working Capital (in thousands of Canadian dollars)	2011			2010
Cash		5,553			2,505
Accounts receivable		25,174			24,891
Prepaid expenses, deposits and other		870			2,093
Assets held for sale		9,678			-
Accounts payable and accrued liabilities		(24,239	)		(31,321	)
Liabilities associated with assets held for sale		(1,378	)		-
Current portion of decommissioning provision		(557	)		-
Due to JV Participant		-			(10,046	)
Working capital (deficit)		15,101			(11,878	)
Long-term debt		(138,820	)		(24,865	)
Working capital (deficit) including long-term debt		(123,719	)		(36,743	)

Convertible Debentures

As at December 31, 2011, Equal had $41.3 million of 6.75% convertible debentures (EQU.DB.B) outstanding with a face value of $45.0 million. The 6.75% convertible debentures have the conversion price of $9.00 per share. Each $1,000 principal amount of EQU.DB.B debentures is convertible into approximately 111.11 Equal shares and mature on March 31, 2016.

During 2011, Equal redeemed its 8% and 8.25% convertible debentures pursuant to normal course issuer bid and issued early redemption notices for the remaining 8% and 8.25% convertible debentures.

SUBSEQUENT EVENT

On January 31, 2012, Equal closed the sale of non-core assets in Primate, Saskatchewan for proceeds of $8.3 million.

RESERVES AND PRESENT VALUE SUMMARY

Equal complies with the National Instrument 51-101, issued by the Canadian Securities Administrators, in all its reserves related disclosures. The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of accountability.

Proved Reserves (P90) - For reported reserves this means there must be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

Proved plus Probable (P50) - For reported reserves there must be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable reserves.

Reserve volumes and values at December 31, 2011 and 2010 are based on the interest in total proved and probable reserves prior to royalties as defined in NI 51-101. Under NI 51-101 reserves definitions, estimates are prepared such that the full proved and probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a "most likely case"). As such, the probable reserves reported are already "risked."

The reserves have been evaluated by independent engineers each year. McDaniel and Associates Consultants Ltd. ("McDaniel") independently evaluated the Canadian reserves as at December 31, 2011 and 2010 and Haas Petroleum Engineering Services, Inc. (“Haas”) evaluated the Oklahoma reserves as at December 31, 2011 and 2010. The reserve engineers evaluated 100% of the Company’s December 31, 2011 reserves. The independent engineers used the following future price forecasts in order to evaluate Equal’s reserves as of December 31, 2011.

Year	WTI Oil ($U.S./bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	AECO Gas ($Cdn/MMBtu)	Henry Hub ($U.S./Mmbtu)	Foreign Exchange Rate (US$/CAD)
2012	97.50	99.00	3.50	3.75	0.975
2013	97.50	99.00	4.20	4.50	0.975
2014	100.00	101.50	4.70	5.05	0.975
2015	100.80	102.30	5.10	5.50	0.975
2016	101.70	103.20	5.55	5.95	0.975
2017	102.70	104.20	5.90	6.35	0.975
Escalate Thereafter	Average 2% per year	Average 2% per year	Average 2% per year	Average 2% per year	0.975

Reserve Continuity – Oil, NGLs and Natural Gas (mboe)

	Proved			Probable			Total
December 31, 2009		22,338			8,908			31,246
Discoveries and extensions		2,166			1,002			3,168
Acquisitions		682			243			925
Dispositions		(803	)		(623	)		(1,426	)
Production		(3,328	)		-			(3,328	)
Revision of prior estimates		4,802			(3,467	)		1,335
December 31, 2010		25,857			6,063			31,920
Discoveries and extensions		5,409			1,246			6,655
Acquisitions		8,409			1,177			9,586
Dispositions		(1,695	)		(1,790	)		(3,485	)
Production		(3,702	)		-			(3,702	)
Revision of prior estimates		576			(3,386	)		(2,810	)
December 31, 2011		34,854			3,310			38,164

During 2011, proved reserves and total reserves increased by 35% and 20%, respectively. Proved reserves increased from 25,857 mboe to 34,854 mboe and total reserves increased from 31,920 mboe to 38,164 mboe. The increase in the reserves is mainly due to the Hunton acquisition and the new wells drilled in the Oklahoma, Lochend and Viking resource plays which were partially offset by dispositions in non-core properties, production and revisions to prior estimates. The revisions were the result of higher than anticipated declines in mature properties in Saskatchewan and revised reserve estimates for wells drilled in Alberta and Oklahoma in 2010 and 2011.

Finding and development (“F&D”) costs incurred over the last three years are highlighted below, along with the recycle ratios for each year. Management uses the recycle ratio as a performance measure. It is calculated by dividing the operating netback per boe of production by the cost per boe of finding and developing reserves. A recycle ratio of one is considered a “break-even point”, indicating that the cash flow from a unit of production is equal to the cost of finding and developing a unit of reserves.

Under NI 51-101, the methodology to be used to calculate F&D costs, includes incorporating changes in future development costs (“FDC”) required to bring the proved undeveloped and probable reserves to production. For continuity the Company has presented F&D costs calculated both excluding and including changes in FDC.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Finding & Development Costs and Recycle Ratio

(in thousands of Canadian dollars except for ratios and amounts in $/boe)	Years Ended December 31			3-Year
	2011	2010	2009		Total
Capital expenditures (1)	81,591	54,522	16,445		152,558
Future Development Costs Proved	97,720	63,094	64,811		225,625
Proved plus probable	109,114	87,762	100,678		297,554
Reserves (2)
Proved reserves added in the year (mboe)	5,985	6,963	5,447		18,395
Probable reserves added in the year (mboe)	(2,139)	(2,465)	1,599		(3,005)
Proved plus probable reserves added in the year (mboe)	3,846	4,498	7,046		15,390

F&D costs (excluding changes in FDC)
Proved reserves ($/boe)	13.63	7.83	3.02		8.29
Proved plus probable reserves ($/boe)	21.21	12.12	2.33		9.91

F&D costs (including changes in FDC)
Proved reserves ($/boe)	19.29	8.03	9.17		10.18
Proved plus probable reserves ($/boe) (5)	29.46	10.19	10.21		12.79

Recycle ratios
Operating netbacks ($/boe) (3)	23.62	22.90	20.02		22.17
Operating recycle ratio (based on proved reserves including FDC) (5)	1.2	2.9	2.2		2.2
Operating recycle ratio (based on proved plus probable reserves including FDC) (5)	0.8	2.2	2.0		1.7
Corporate netbacks ($/boe) (4)	16.93	14.01	12.94		14.66
Corporate recycle ratio (based on proved reserves including FDC) (5)	0.9	1.7	1.4		1.4
Corporate recycle ratio (based on proved plus probable reserves including FDC) (5)	0.6	1.4	1.3		1.1

(1)	Excludes acquisitions.

(2)	Includes revisions and excludes acquisitions.

(3)	Operating netbacks are production revenue less royalties and operating expenses.

(4)	Corporate netbacks are production revenue less royalties, operating expenses, G&A, interest expense and other cash costs.

(5)	Canadian 2011 change in FDC adjusted by $11.2 million to reflect disposition of assets on November 15, 2011.

Finding and development costs and recycle ratios are non-GAAP financial measures that may not be comparable to similar measures presented by other entities.

The operating and corporate recycle ratios decreased below 1.0 during 2011 due to the negative reserve revisions from the decrease in forecasted prices for natural gas and the performance of wells in certain areas.

During 2011, the Company acquired the working interest from a former joint venture partner in Oklahoma for proceeds of $91.7 million and disposed non-core assets in Canada for proceeds of $41.1 million. Taking into account these transactions, the Company’s F&D costs and recycle ratios are summarized in the following table.

Finding & Development Costs and Recycle Ratio including Acquisitions and Dispositions

(in thousands of Canadian dollars except for ratios and amounts in $/boe)	For the year ended December 31, 2011
Capital expenditures including acquisitions and dispositions	132,103

Change in FDC
Proved	34,625
Proved plus probable	21,353

Reserves (mboe)
Proved reserves – additions, revisions and A&D	12,699
Probable reserves – additions, revisions and A&D	(2,752)
Proved plus probable reserves (mboe)	9,947

F&D costs (excluding changes in FDC)
Proved reserves ($/boe)	10.40
Proved plus probable reserves ($/boe)	13.28

F&D costs (including changes in FDC)
Proved reserves ($/boe)	13.13
Proved plus probable reserves ($/boe)	15.43

Recycle ratios
Operating netbacks ($/boe) (1)	23.62
Operating recycle ratio (based on proved reserves including FDC)	1.8
Operating recycle ratio (based on proved plus probable reserves including FDC)	1.5
Corporate netbacks ($/boe) (2)	16.93
Corporate recycle ratio (based on proved reserves including FDC)	1.3
Corporate recycle ratio (based on proved plus probable reserves including FDC)	1.1

(1)	Operating netbacks are production revenue less royalties and operating expenses.

(2)	Corporate netbacks are production revenue less royalties, operating expenses, G&A, interest expense and other cash costs.

Equal Energy - Estimated Petroleum and Natural Gas Reserves and Net Present Value

December 31, 2011 (NPV in thousands of Canadian dollars)

	Light/										Net Present Value
	Medium		Heavy				Natural				Before Income Tax ($)
	Oil		Oil		NGL		Gas		Total
	(mbbl)		(mbbl)		(mbbl)		(mmcf)		(mboe)			0	%	5	%	10	%
Canadian Assets
Proved Producing		1,551		357		53		3,022		2,465		98,823		81,786		70,460
Proved Non-Producing		-		-		4		203		38		(3,031	)	(2,573	)	(2,221	)
Proved Undeveloped		1,011		120		33		1,613		1,433		28,137		16,789		9,386
Total Proved		2,562		477		90		4,838		3,935		123,929		96,002		77,625
Total Probable		1,105		297		40		2,218		1,812		75,197		44,729		30,280
Total Proved & Probable		3,667		774		130		7,056		5,747		199,126		140,731		107,905
United States Assets
Proved Producing		498		-		9,820		75,097		22,834		602,074		432,976		333,895
Proved Non-Producing		-		-		-		-		-		-		-		-
Proved Undeveloped		-		-		3,506		27,467		8,084		166,948		87,075		45,116
Total Proved		498		-		13,326		102,564		30,918		769,022		520,051		379,011
Total Probable		1		-		603		5,367		1,499		36,144		23,384		16,368
Total Proved & Probable		499		-		13,929		107,931		32,417		805,166		543,435		395,379
Consolidated Assets
Proved Producing		2,049		357		9,873		78,119		25,299		700,897		514,762		404,355
Proved Non-Producing		-		-		4		203		38		(3,031	)	(2,573	)	(2,221	)
Proved Undeveloped		1,011		120		3,539		29,080		9,517		195,085		103,864		54,502
Total Proved		3,060		477		13,416		107,402		34,854		892,951		616,053		456,636
Total Probable		1,106		297		643		7,585		3,310		111,341		68,113		46,648
Total Proved & Probable		4,166		774		14,059		114,987		38,164		1,004,292		684,166		503,284

(1)	The U.S. reserve report was converted to Canadian dollars using the Bank of Canada close rate on December 31, 2011 of CAD$1.017 per US$1.00.

EQUITY INFORMATION

Equal is capitalized through a combination of shares and convertible debt. Equal also has a share option plan and restricted share plan. The following table outlines the outstanding equity instruments:

Outstanding Equity Data as at	March 20, 2012		December 31, 2011		December 31, 2010
Shares		34,989,069		34,779,435		27,709,859
Share options		1,257,312		1,303,495		1,058,152
Restricted shares		1,523,665		946,285		507,759
6.75% Convertible debentures ($1,000 per debenture)		45,000		45,000		-
8.0% Convertible debentures ($1,000 per debenture)		-		-		80,127
8.25% Convertible debentures ($1,000 per debenture)		-		-		39,648

OUTLOOK

In 2011, Equal took many important steps to improve the financial position and operating structure of the Company. Convertible debt in the amount of $120 million, with maturities at the end of 2011 and June 30, 2012, were refinanced with lower cost and longer term debt or repaid with the proceeds of asset sales. The completion of the financially accretive June 1, 2011 acquisition of the former JV participant’s working interests in Oklahoma has imparted numerous benefits on the Company including the elimination of financially burdensome legal proceedings and management distraction and financial position improvement by eliminating pending financial settlements with the former JV participant. A common share issue which funded a portion of the acquisition also improved the Company’s financial position. Non-core Canadian asset dispositions near the end of 2011 and in early 2012 totaling $49 million repaid expensive convertible debt with a near term maturity and further consolidated and improved the Company’s asset base.

The Company enters 2012 with a consolidated, high working interest and Company operated asset base with approximately eight years of drilling inventory on low risk, oil and liquids rich resource plays based on spending funds from operations. The debt structure is low cost with no large immediate repayment obligations and there remains significant borrowing capacity available in the Company’s bank credit facility.

Two rigs began drilling in the Oklahoma Hunton play in January 2012. The first is drilling a four well program in the K-9/Puppy area in northern Oklahoma where the Company had considerable drilling success in 2011. This program will also add approximately three more net sections of Mississippian lands adjacent to existing Mississippian holdings. The second rig is drilling at Twin Cities Central Dolomite and is expected to drill up to nine wells on a continuous basis. Cardium light oil drilling commenced in early March 2012 in the Lochend area with the first of three wells planned for 2012. Drilling in the light oil Viking play is planned to begin in July 2012 up to a six well program using monobore technology to reduce drilling costs.

ENVIRONMENTAL AND CLIMATE CHANGE RISK

The oil and gas industry has a number of environmental risks and hazards and is subject to regulation by all levels of government. Environmental legislation includes, but is not limited to, operational controls, final site restoration requirements and increasing restrictions on emissions of various substances produced in association with oil and natural gas operations. Compliance with such legislation could require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate, become material.

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2011, an internal evaluation was carried out of the effectiveness of Equal’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that Equal files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by Equal in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to Equal’s management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of Equal’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management concluded that Equal’s internal control over financial reporting was effective as of December 31, 2011. The effectiveness of Equal’s internal control over financial reporting as of December 31, 2011 has been audited by KPMG LLP, an independent registered public accounting firm. No changes were made to Equal’s internal control over financial reporting during the year ending December 31, 2011, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, Equal adopted International Financial Reporting Standards (“IFRS”) for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2011, including required comparative information, have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB"). Previously, the Company prepared its interim and annual Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles. Unless otherwise noted, 2010 comparative information has been prepared in accordance with IFRS.

The adoption of IFRS has not affected the Company’s operations, strategic decisions and cash flow. Further information on the IFRS changes are provided in Note 21 in the Notes to the Financial Statements.

CRITICAL ACCOUNTING ESTIMATES

Equal has continuously evolved and documented its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.

Equal’s financial and operating results incorporate certain estimates including:

·	estimated depletion and depreciation that are based on estimates of oil, NGL and natural gas reserves and useful lives of equipment;

·	property, plant and equipment is aggregated into cash-generating units based on management’s judgment of their ability to generate largely independent cash flows;

·	estimated future recoverable value of property, plant and equipment that are based on estimates of oil, NGL and natural gas reserves that Equal expects to recover in the future;

·	estimated future recoverable value of assets that are transferred from E&E to property, plant and equipment based on oil, NGL and natural gas reserves;

·	estimated value of decommissioning provision obligations that are dependent upon estimates of future costs and timing of expenditures;

·	estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices;

·	estimated expenses from Equal’s share-based compensation plans that are based on pricing models such as the Black-Scholes model; and

·	estimated deferred income taxes which are dependent upon tax interpretations, regulations and legislation in various jurisdictions in which the Company operates that are subject to change.

Equal has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

The Equal leadership team’s mandate includes ongoing development of procedures, standards and systems to allow Equal staff to make the best decisions possible and ensuring those decisions are in compliance with Equal’s environmental, health and safety policies.

ADDITIONAL INFORMATION

Additional information relating to Equal Energy Ltd. can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the website at www.equalenergy.ca.

2011 FINANCIAL REPORT

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

GLOSSARY

AECO	a storage and pricing hub for Canadian natural gas market	mcf	thousand cubic feet of natural gas
bbl or bbls	barrels of oil	mcf per day	thousands of cubic feet of natural gas per day
bbls per day	barrels of oil per day	mmbtu	millions of British Thermal Units
boe	barrels of oil equivalent (6 mcf equivalent to 1 bbl)	mmbtu per day	millions of British Thermal Units per day
boe per day	barrels of oil equivalent per day	mmcf	millions of cubic feet of natural gas
Cdn$	Canadian dollars	Mwh	megawatt-hour
FD&A	Finding Development & Acquisition Costs	NGL	natural gas liquids (ethane, propane, butane and condensate)
FDC	Future Development Costs	NI 51-101	National Instrument 51-101
GAAP	Canadian Generally Accepted Accounting Principles	NYMEX	New York Mercantile Exchange
GJ	Gigajoule	Q1	first quarter of the year - January 1 to March 31
GORR	Gross overriding royalty	Q2	second quarter of the year - April 1 to June 30
IFRS	International Financial Reporting Standards	Q4	third quarter of the year - July 1 to September 30
LNG	Liquefied Natural Gas	Q4	fourth quarter of the year - October 1 to December 31
mbbl	thousand barrels of oil	US$	United States dollars
mboe	thousands of barrels of oil equivalent	WTI	West Texas Intermediate (oil reference price)

2011 FINANCIAL REPORT