EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

Dear Equal Shareholders,

The year 2010 was one of transition and change for Equal.

We:

·   converted from a trust to a value oriented exploration and production corporation;

·   further de-levered the balance sheet with a well timed sale of sour gas assets and completed an equity issue;

·   invested over 20% of our capital budget on lands for our emerging light oil resource plays in the Halkirk/Alliance Viking and Lochend Cardium areas;

·   became very active with the drill bit in Canada in the second half of the year proving up our Viking and Cardium light oil resource plays;

·   increased our reserves booking year over year; and

·   executed efficiently on our capital program with proved plus probable reserves finding and development costs of $10.19/boe in 2010.

Since the end of 2010 we’ve had more positive announcements that further enhance our growth prospects.

We:

·   resolved our farm-out issues with our bankrupt partner in Oklahoma, freeing us to move forward on the Hunton liquids rich natural gas resource drilling play on our own; and

·   re-financed an $80 million debt maturity which was due at the end of 2011.

Our production volume averaged 9,118 boe/d for 2010, below our 2009 average of 9,878 boe/d because we sold sour gas assets of approximately 500 boe/d and our 2010 drilling program was heavily weighted to the second half of the year.  We also had plans to drill a number of wells in the Hunton play in Oklahoma which were pre-empted by JV Participant’s declaration of bankruptcy in May of 2010 limiting us to drill only one Hunton well in Oklahoma during 2010.  Significant legal fees were incurred dealing with the issues related to our bankrupt partner during 2010 which drove up our G&A costs.  I’m pleased to say that by the end of 2010 most of our legal issues were resolved or nearing their end in Oklahoma.

During 2010, of our 22 wells drilled, 6 wells were in our Alliance Viking play and 5 wells in the Lochend Cardium.  We are pleased with the performance of our new Viking and Cardium plays and their reserve bookings based on the average well performance to date.  We also had success in our Dina PPP pool and at our Princess Pekisko properties; however, our focus in Canada in 2011 will be in the Viking and Cardium light oil resource plays where we have the best well economics and most running room going forward.

In Oklahoma the one well drilled in our Hunton play during 2010 was brought on stream in November and had production ramping up to over 1.2 million cubic feet per day of natural gas with significant associated natural gas liquids by the end of the year.  In 2011, with the resolution of our farm-out issues behind us, we plan to drill four to six Hunton wells focusing in our Twin Cities Central Dolomite (TCCD) area which has the best economics of our four Hunton play areas.

We enter 2011 well positioned for cash flow growth with our two light oil resource plays in Canada and liquids rich natural gas resource play in the Hunton TCCD area in Oklahoma.  We control and operate all three of our resource plays so we can change the pace of our spending and allocate our capital as we see fit.  Equal Energy has a very extensive inventory of over 150 drilling locations in these three areas.  As an indication of our inventory quality in the Hunton TCCD area, we can replace our corporate reserves produced for the year by drilling only seven wells out of the 50+ identified locations.

We plan to hold our capital spending relatively close to our cash flow during 2011 as we continue to keep a close eye on the strength of our balance sheet and plan to retain the financial flexibility we worked so hard to achieve over the past couple of years.

I’d 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 2011 where we will begin to reap the benefits from the transitions the company has made during 2010 and continue to build value for our shareholders.

Sincerely,

Signed “Don Klapko”

President and Chief Executive Officer

March 22, 2011

2010 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, 2010.  This MD&A should be read in conjunction with the MD&A and consolidated financial statements, together with the accompanying notes, of the Company for the years ended December 31, 2010 and 2009.  All amounts are stated in Canadian dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) except where otherwise indicated.  This commentary is based on information available to, and is dated, March 22, 2011.

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 “funds from operations”, “working capital” and “cash flow netback”, which are non-GAAP terms.  The Company uses these measures to help evaluate its performance.  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.  The term should not be considered as an alternative to, or more meaningful indicator of performance than cash provided by operating activities as determined in accordance with GAAP.  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 GAAP.  Funds from operations, working capital and cash flow netback, as determined by the Company may not be comparable to that reported by other companies.  The reconciliation of funds from operations to cash provided by operating activities and 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 GAAP.  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 GAAP.  Equal’s method of calculating these measures may differ from other entities, and accordingly, may not be comparable measures used by other companies.

FORWARD-LOOKING STATEMENTS:  Certain information contained herein may contain forward-looking statements 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 credit facility, anticipated outcomes from legal proceedings, maintenance of productive capacity and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute forward-looking statements under applicable securities laws and necessarily involve risks.  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 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

2010 FINANCIAL REPORT 

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

impact 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 impact 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 GAAP 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 net earnings as further information becomes available, and as the economic environment changes.

CORPORATE PROFILE

Equal Energy Ltd. is a value oriented 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, EQU.DB.A and EQU.DB.B).

On May 31, 2010, Equal announced that Enterra Energy Trust had completed its previously announced Arrangement to convert from an income trust to a corporation through a business combination pursuant to an arrangement under the Business Corporations Act (Alberta).  Unitholders of the Trust received one Equal common share for every three Enterra Energy Trust units held.  Enterra’s Board of Directors and management team continued as the Equal’s Board of Directors and management team.  Immediately subsequent to the Arrangement, former Enterra unitholders held 100 percent of the equity in Equal and Equal effected an internal reorganization whereby, among other things, the Trust was dissolved and the Company received all of the assets and assumed all of the liabilities of the Trust.  Readers are referred to Enterra Energy Trust’s information circular dated April 13, 2010 for additional information in respect of the Arrangement.

The Company’s portfolio of oil and gas properties is geographically diversified with producing properties located principally in Alberta, British Columbia, Saskatchewan and Oklahoma.  Production is comprised of approximately 57% crude oil and natural gas liquids (“NGL”) and 43% natural gas.

	Three months ended December 31									Year ended December 31
2010 Financial and Operations Summary (in thousands except for volumes, percentages and  per unit and boe amounts)	2010			2009			Change			2010			2009			Change
FINANCIAL
Revenue before mark-to-market adjustment (1)		34,704			37,055			(6	%)		143,713			140,506			2	%
Funds from operations (1)		9,338			11,803			(21	%)		46,640			46,645			0	%
Per share – basic (2) (3) ($)		0.34			0.55			(38	%)		1.90			2.22			(14	%)
Per share – diluted (2) (3) ($)		0.34			0.55			(38	%)		1.90			2.22			(14	%)
Net income (loss)		(19,557	)		(8,939	)		119	%		(34,536	)		(41,282	)		(16	%)
Per share – basic (2) (3) ($)		(0.71	)		(0.42	)		69	%		(1.40	)		(1.95	)		(28	%)
Per share – diluted (2) (3) ($)		(0.71	)		(0.42	)		69	%		(1.40	)		(1.95	)		(28	%)
Total assets		427,754			462,272						427,754			462,272
Working capital (deficit) including long-term debt (4)		(36,743	)		(52,642	)					(36,743	)		(52,642	)
Convertible debentures		117,019			114,863						117,019			114,863
Shareholders’ equity		213,512			219,046						213,512			219,046
SHARES OUTSTANDING
Shares outstanding – basic (2) (3) (000s)		27,692			21,610						24,595			21,119
Shares outstanding – diluted (2) (3) (000s)		27,692			21,610						24,595			21,119
Shares outstanding at period end (3) (000s)		27,710			21,701						27,710			21,701
OPERATIONS
Average daily production
Oil (bbls per day)		2,501			2,530			(1	%)		2,481			2,779			(11	%)
NGL (bbls per day)		2,373			2,749			(14	%)		2,491			2,156			16	%
Gas (mcf per day)		22,529			25,815			(13	%)		24,878			29,657			(16	%)
Total (boe per day)		8,629			9,582			(10	%)		9,118			9,878			(8	%)
Average sales price
Oil ($ per bbl)		70.03			70.83			(1	%)		70.25			62.86			12	%
NGL ($ per bbl)		45.00			41.63			8	%		42.44			32.17			32	%
Gas ($ per mcf)		4.23			4.23			0	%		4.57			4.75			(4	%)
Cash flow netback (1) ($ per boe)
Revenue (5)		43.71			42.04			4	%		43.18			38.97			11	%
Royalties		8.77			9.70			(10	%)		8.81			7.37			20	%
Production expenses		10.67			10.25			4	%		10.76			10.88			(1	%)
Transportation expenses		0.79			0.59			34	%		0.71			0.70			1	%
Operating netback		23.48			21.50			9	%		22.90			20.02			14	%
General and administrative		7.93			4.86			63	%		5.78			4.36			33	%
Cash interest expense		3.56			2.92			22	%		3.40			2.66			28	%
Other cash costs (6)		0.23			0.34			(32	%)		(0.29	)		0.06			(100	%)
Cash flow netback		11.76			13.38			(12	%)		14.01			12.94			8	%

(1) Revenues before mark-to-market adjustment, funds from operations and cash flow netback are non-GAAP financial measures.  Please refer to “Revenues” and “Non-GAAP Financial Measures”.

(2) Weighted average shares outstanding.  See Note 10 in Notes to Financial Statements.

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

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

(5) Price received excludes unrealized mark-to-market gain or loss.

(6)                                              Other cash costs include realized foreign exchange gains and losses.

2010 FINANCIAL REPORT 

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

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

	2010									2009
		Q4		Q3		Q2		Q1			Q4		Q3		Q2		Q1
Revenues before mark-to-market adjustments		34,704		34,267		35,689		39,053			37,055		30,354		31,208		41,889
Funds from operations		9,338		11,402		11,357		14,543			11,803		8,366		8,561		17,915
Loss before taxes		(10,808	)	(11,042	)	(11,352	)	(1,920	)		(8,930	)	(13,259	)	(23,823	)	(12,864	)
Loss		(19,557	)	(7,976	)	(4,066	)	(2,937	)		(8,939	)	(9,462	)	(14,383	)	(8,498	)
Loss per share basic(1) ($)		(0.71	)	(0.29	)	(0.19	)	(0.14	)		(0.42	)	(0.45	)	(0.69	)	(0.42	)
Loss per share diluted (1) ($)		(0.71	)	(0.29	)	(0.19	)	(0.14	)		(0.42	)	(0.45	)	(0.69	)	(0.42	)

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

During Q1 2009, Q4 2009 and Q1 2010, revenues before mark-to-market adjustments and funds from operations were higher than the other quarters due to the realized gains from the commodity contracts in place.  During Q2 2009 and Q3 2009, low natural gas prices led to lower revenues before mark-to-market adjustments, lower funds from operations and higher losses compared to the other quarters.  During Q4 2010 funds from operations were lower due to legal fees relating to claims made by a joint venture participant in Oklahoma and the Company reorganized its Canadian and U.S. operations which resulted in a future income tax expense which created a higher loss after taxes compared to the other quarters.

OVERALL PERFORMANCE

Average production decreased by 8% in 2010 to 9,118 boe per day when compared to 2009 production of 9,878 boe per day.  The decline in average production was due primarily to natural decline rates for Equal’s wells and the disposition of non-core sour gas assets which were partially offset by drilling, well optimization projects and minor acquisitions.

Overall, oil prices received in 2010 increased 12% to $70.25 per barrel from $62.86 per barrel in 2009 as overall world oil prices increased.  NGL prices received in 2010 increased 32% to $42.44 per bbl from $32.17 per bbl in 2009 due to oil price increases and reduced basis differentials between WTI and NGL’s in the Oklahoma market.  Gas prices received in 2010 decreased 4% to $4.57 per mcf from $4.75 per mcf in 2009.  Production expenses, excluding non-cash expenses, in 2010 remained relatively flat at $10.76 per boe compared to $10.88 per boe in 2009.

G&A expenses in 2010 increased 33% to $5.78 per boe from $4.36 per boe in 2009 which primarily relates to legal fees related to claims against Equal made by a joint venture participant in Oklahoma.  Cash interest expense increased 28% on a per boe basis to $3.40 per boe in 2010 compared to $2.66 per boe in 2009 mainly due to the lower production in 2010 and less interest income recorded which has been netted against interest expense which was offset partially by lower debt levels in 2010.

The overall impact was that funds from operations in 2010 was $46.6 million which was the same as in 2009.  The funds from operations benefitted in 2010 compared to 2009 from the higher prices received for oil and NGLs and lower production and transportation costs but were offset by lower production, lower prices received for natural gas, higher royalties and higher G&A costs.  The loss in 2010 decreased to $34.5 million compared to a loss of $41.3 million in 2009 due to higher oil and NGL prices and lower operating and depletion expenses which were partially offset by higher G&A expenses and lower future taxes reduction.

Equal has further reduced its long-term debt during the year to $24.9 million as at December 31, 2010 compared to $70.0 million at the beginning of the year mainly through the disposition of several non-core sour gas assets which had net proceeds of $26.3 million.  An equity offering which raised net proceeds of $35.6 million was used to support the ongoing capital program, freeing up cash flow to further reduce debt.  As a result of these transactions, the working capital deficit including long-term debt plus the convertible debentures totaled $153.8 million as at December 31, 2010 down from $167.5 million as at December 31, 2009.  The improved balance sheet has given Equal additional financial flexibility to fund its operations.

SUMMARY OF OPERATIONS

The following is a summary of Equal’s operations for the three months and years ended December 31, 2010 and 2009 which are referenced throughout this MD&A.

	Three months ended						Year ended
(in thousands of Canadian dollars)	December 31						December 31
	2010			2009			2010			2009
Revenues
Oil and natural gas		33,268			36,291			137,675			124,611
Realized gain on commodity contracts		1,436			764			6,038			15,895
Unrealized gain/(loss) on commodity contracts		(3,632	)		(1,271	)		(912	)		(13,678	)
Royalties		(6,963	)		(8,549	)		(29,330	)		(26,570	)
		24,109			27,235			113,471			100,258
Expenses
Production		8,469			8,948			35,826			39,659
Transportation		629			523			2,370			2,519
General and administrative		6,298			4,287			19,227			15,707
Recovery of receivables		-			(2,110	)		-			(2,110	)
Interest expense		3,393			3,099			13,538			11,461
Share-based compensation expense		602			689			3,636			3,580
Depletion, depreciation and accretion		15,389			19,597			75,286			86,877
Foreign exchange (gain) loss		137			1,132			(1,290	)		1,441
		34,917			36,165			148,593			159,134
Loss before income taxes		(10,808	)		(8,930	)		(35,122	)		(58,876	)
Income taxes
Current		95			-			693			-
Future taxes reduction		8,654			9			(1,279	)		(17,594	)
		8,749			9			(586	)		(17,594	)
Loss		(19,557	)		(8,939	)		(34,536	)		(41,282	)
Cash Flow from Operations
Loss		(19,557	)		(8,939	)		(34,536	)		(41,282	)
Depletion, depreciation and accretion		15,389			19,597			75,286			86,877
Future taxes (reduction)		8,654			9			(1,279	)		(17,594	)
Unrealized commodity contracts loss		3,632			1,182			912			14,127
Foreign exchange loss		54			850			383			1,159
Share-based compensation		602			689			3,636			3,580
Non-cash interest expense on convertible debentures		564			525			2,238			1,888
Cash paid on asset retirement obligations		(299	)		(1,576	)		(1,589	)		(2,533	)
		9,039			12,337			45,051			46,222
Changes in non-cash working capital items		1,302			6,348			(10,615	)		5,248
Cash from operating activities		10,341			18,685			34,436			51,470

SALES VOLUMES

Production
	Three months ended December 31									Year ended  December 31
	2010			2009			Change			2010			2009			Change
Daily sales volumes – average
Oil (bbls per day)		2,501			2,530			(1	%)		2,481			2,779			(11	%)
NGL (bbls per day)		2,373			2,749			(14	%)		2,491			2,156			16	%
Natural gas (mcf per day)		22,529			25,815			(13	%)		24,878			29,657			(16	%)
Total (boe per day)		8,629			9,582			(10	%)		9,118			9,878			(8	%)
Sales volumes mix by product
Oil		29	%		26	%					27	%		28	%
NGL		28	%		29	%					27	%		22	%
Natural gas		43	%		45	%					46	%		50	%
		100	%		100	%					100	%		100	%

Average production for Q4 2010 decreased 10% to 8,629 boe per day compared to 9,582 boe per day in Q4 2009 due to the disposition of non-core assets in west central Alberta during 2010 and natural decline rates for Equal’s wells which were partially offset by the drilling, well optimization projects and minor acquisitions.  Q4 2010 production also decreased 2% compared to Q3 2010 production of 8,777 boe per day mainly due to the natural decline rates for Equal’s wells which was partially offset by production increases from new wells brought on stream during the quarter.

Average production during Q4 2010 consisted of 2,501 boe per day of oil, 2,373 boe per day of NGL and 22,529 mcf per day of natural gas, resulting in a mix of 29% oil, 28% NGL and 43% natural gas.

Average production for the year ended December 31, 2010 was 9,118 boe per day which is a decrease of 8% compared to 9,878 boe per day during the same period in 2009.  The decrease is mainly due to the disposition of non-core sour gas assets in west central Alberta and the natural decline rates for Equal’s wells which were partially offset by the drilling, well optimization projects and minor acquisitions.

Equal did not accelerate its drilling program until the second half of 2010 after greater financial flexibility was achieved through the sales of non-core assets and an equity offering.  Additionally, only one well was drilled in the prolific Hunton play in Oklahoma during 2010 due to the bankruptcy filings and legal issues related to an Oklahoma joint venture participant.

Production in 2011 is expected to remain relatively flat compared to 2010 as the Company plans a capital spending program that is approximately the same as expected funds from operations.

For the year ended December 31, 2010, Equal drilled the following 22 (18.8 net) wells with a 91% success rate:

·   6 (5.6 net) Alliance horizontal oil wells;

·   5 (4.3 net) Cardium horizontal oil wells;

·   3 (2.3 net) Provost Dina PPP horizontal oil wells;

·   2 (2.0 net) Princess horizontal oil wells;

·   2 (0.8 net) Circus Viola horizontal oil wells;

·   1 (1.0 net) Primate oil well;

·   1 (0.8 net) Twin Cities/Central Dolomite liquids-rich natural gas well; and

·   2 (2.0 net) dry holes.

Production by Geographic Area
	Three months ended December 31, 2010								Year ended December 31, 2010
	Canada			U.S.			Total		Canada			U.S.			Total
Daily sales volumes – average
Oil (bbls per day)		2,223			278			2,501		2,201			280			2,481
NGL (bbls per day)		70			2,303			2,373		224			2,267			2,491
Natural gas (mcf per day)		7,583			14,946			22,529		9,936			14,942			24,878
Total (boe per day)		3,557			5,072			8,629		4,081			5,037			9,118
Sales volumes mix by product
Oil		62	%		5	%				54	%		6	%
NGL		2	%		46	%				5	%		45	%
Natural gas		36	%		49	%				41	%		49	%
		100	%		100	%				100	%		100	%

Canadian Operations

In Q4 2010, production in Canada of 3,557 boe per day was down 9% compared to 3,909 boe per day during the Q4 2009.  The decrease is due to the disposition of non-core assets in west central Alberta during 2010 and natural decline rates for Equal’s wells which were partially offset by the drilling, well optimization projects and minor acquisitions.  Q4 2010 production decreased 7% from Q3 2010 production of 3,833 boe per day mainly due to the natural decline rate of Equal's wells and operational issues in Saskatchewan and Desan that are being addressed. 

For 2010, production in Canada of 4,081 boe per day was down 8% compared to 2009 production of 4,415 boe per day due to the natural decline rates on Equal’s wells and dispositions of non-core assets that contributed approximately 265 annualized boe per day in 2009.  These decreases in production were partially offset by the wells drilled during 2010 which contributed 183 annualized boe per day.  The capital program in Canada was accelerated in the second half of 2010 by drilling 13 of the 19 wells for the year.

U.S. Operations

In Q4 2010, production in the United States of 5,072 boe per day was down 11% compared to 5,673 boe per day during Q4 2009.  The decrease is due to the natural decline rates on Equal’s wells which was partially offset by acquisitions and new wells drilled.  Two wells were drilled in the Circus Viola play and only one well was drilled in the Hunton play due to the uncertainties surrounding a joint venture participant’s claim for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  Q4 2010 production was 3% higher than Q3 2010 production of 4,944 boe per day due to a reactivation and workover program and the drilling of one well in the Hunton play which started producing in November 2010.   

For 2010, production in the United States of 5,037 boe per day was down 8% compared to 2009 production of 5,463 boe per day due to the natural decline rates on Equal’s wells which was partially offset by acquisitions and new wells drilled.  Three wells were drilled in Oklahoma during 2010.  Two wells were drilled in the Circus Viola play and only one well was drilled in the Hunton play due to the uncertainties surrounding a joint venture participant’s claim for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.

COMMODITY PRICING

Pricing Benchmarks
	Three months ended December 31							Year ended December 31
	2010		2009		Change			2010		2009		Change
WTI (US$ per bbl)		85.17		76.19		12	%		79.53		61.80		29	%
Average exchange rate: US$ to Cdn$1.00		0.99		0.94		5	%		0.97		0.88		10	%
WTI (Cdn$ per bbl)		86.02		80.76		7	%		81.92		70.45		16	%
Edmonton Light		80.33		76.56		5	%		77.48		65.98		17	%
Propane, Conway, KS (US$/bbl)		51.01		45.94		11	%		47.24		33.90		39	%
NYMEX (US$ per mmbtu)		3.81		4.27		(11	%)		4.42		4.04		9	%
NYMEX (US$ per mcf) (1)		3.94		4.42		(11	%)		4.57		4.18		9	%
AECO daily index (Cdn$ per GJ)		3.43		4.26		(19	%)		3.79		3.74		1	%
AECO daily index (Cdn$ per mcf) (2)		3.50		4.34		(19	%)		3.86		3.81		1	%

(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, KS is the closest surrogate benchmark for the blended price Equal receives for its NGL produced in Oklahoma.  The price variations at Conway, KS 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 is the price at the AECO hub (a storage and pricing hub for Canadian natural gas market) 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 2010 increased 12% to an average of US$85.17 per bbl WTI from US$76.19 per bbl WTI in Q4 2009.  The price increase was partially off-set by the strengthening of the Canadian dollar which averaged US$0.99 per Canadian dollar during Q4 2010 compared to US$0.94 per Canadian dollar during Q4 2009.

Benchmark oil prices for 2010 increased 29% to an average of US$79.53 per bbl WTI from US$61.80 per bbl WTI in 2009.  The price increase was partially off-set by the strengthening of the Canadian dollar which averaged US$0.97 per Canadian dollar during 2010 compared to US$0.88 per Canadian dollar during 2009.

Benchmark propane prices for Q4 2010 increased 11% to an average of US$51.01 per bbl from US$45.94 per bbl in Q4 2009.  Benchmark propane prices for 2010 increased 39% to an average of US$47.24 per bbl from US$33.90 per bbl in 2009 as the basis differential between Conway and WTI was lower during the year.

Benchmark natural gas prices for Q4 2010 on the NYMEX decreased 11% to an average of US$3.81 per mmbtu from US$4.27 per mmbtu in Q4 2009.  In Canada, AECO pricing decreased 19% averaging $3.43 per GJ during Q4 2010 compared to $4.26 during Q4 2009.

Benchmark natural gas prices for 2010 on the NYMEX increased 9% to an average of US$4.42 per mmbtu from US$4.04 per mmbtu in 2009.  In Canada, AECO pricing increased 1% averaging $3.79 per GJ during 2010 compared to $3.74 during 2009.

Average Commodity Prices Received
	Three months ended December 31								Year ended December 31
	2010			2009		Change			2010		2009		Change
Oil (1) (Cdn$ per bbl)		70.07			69.81		0	%		68.82		58.47		18	%
Oil commodity contract settlements (Cdn$ per bbl)		(0.04	)		1.02		(104	%)		1.43		4.39		(67	%)
Combined oil (1) (Cdn$ per bbl)		70.03			70.83		(1	%)		70.25		62.86		12	%
NGL (Cdn$ per bbl)		45.00			41.63		8	%		42.44		32.17		32	%
Natural gas (Cdn$ per mcf)		3.53			4.01		(12	%)		4.05		3.69		10	%
Natural gas commodity contract settlements  (Cdn$ per mcf)		0.70			0.22		218	%		0.52		1.06		(51	%)
Combined natural gas (Cdn$ per mcf)		4.23			4.23		0	%		4.57		4.75		(4	%)
Total (2) (Cdn$ per boe)		43.71			42.04		4	%		43.18		38.97		11	%

(1) Includes sulphur revenue.

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

For the three months ended December 31, 2010, the average price received for oil by Equal, net of commodity contract settlements, decreased 1% to $70.03 per bbl from $70.83 per bbl during the same period in 2009.  The average price received for NGLs for the three months ended December 31, 2010, increased 8% to $45.00 per bbl from $41.63 per bbl during the same period in 2009.  The average price received for natural gas for the three months ended December 31, 2010, net of commodity contract settlements, remained relatively flat at $4.23 per mcf compared to the same period in 2009.

For 2010, the average price received for oil by Equal, net of commodity contract settlements, increased 12% to $70.25 per bbl from $62.86 per bbl in 2009.  The average price received for NGLs in 2010 increased 32% to $42.44 per bbl from $32.17 per bbl during 2009.  The average price received for natural gas in 2010, net of commodity contract settlements, decreased 4% to $4.57 per mcf from $4.75 per mcf during 2009.

REVENUES

Revenues (in thousands of Canadian dollars except for percentages)
	Three months ended December 31									Year ended  December 31
	2010			2009			Change			2010			2009			Change
Oil		16,124			16,248			(1	%)		62,306			59,307			5	%
NGL		9,827			10,528			(7	%)		38,579			25,313			52	%
Natural gas		7,317			9,515			(23	%)		36,790			39,991			(8	%)
Realized gain on commodity contracts		1,436			764			88	%		6,038			15,895			(62	%)
Revenue before mark-to-market adjustments (1)		34,704			37,055			(6	%)		143,713			140,506			2	%
Unrealized mark-to-market gain (loss) on commodity contracts		(3,632	)		(1,271	)		186	%		(912	)		(13,678	)		(93	%)
Oil and natural gas revenues		31,072			35,784			(13	%)		142,801			126,828			13	%

(1) Non–GAAP measure.

Revenues by Geographic Area (in thousands of Canadian dollars)
	Three months ended December 31, 2010								Year ended December 31, 2010
	Canada			U.S.		Total			Canada			U.S.		Total
Oil		13,989			2,135		16,124			54,267			8,039		62,306
NGL		49			9,778		9,827			4,053			34,526		38,579
Natural gas		2,726			4,591		7,317			15,347			21,443		36,790
Realized gain on commodity contracts		180			1,256		1,436			1,917			4,121		6,038
Revenue before unrealized mark-to-market adjustments (1)		16,944			17,760		34,704			75,584			68,129		143,713
Unrealized mark-to-market gain (loss) on commodity contracts		(3,808	)		176		(3,632	)		(1,635	)		723		(912	)
Oil and natural gas revenues		13,136			17,936		31,072			73,949			68,852		142,801

(1)    Non–GAAP measure.

For the three months ended December 31, 2010, total oil and natural gas revenues before unrealized mark-to-market losses on commodity contracts decreased 6% percent to $34.7 million from $37.1 million during the same period in 2009 due to the decrease in price for natural gas and the decrease in production.  For the year ended December 31, 2010, total oil and natural gas revenues before unrealized mark-to-market losses on commodity contracts increased 2% percent to $143.7 million from $140.5 million during 2009 primarily due to the increase in NGL production and the increase in prices received for oil, natural gas and NGLs which were partially offset by decrease in production of oil and natural gas.

Oil revenues for Q4 2010 were relatively flat at $16.1 million compared to $16.2 million in Q4 2009.  NGL revenues for Q4 2010 decreased 7% to $9.8 million from $10.5 million when compared to Q4 2009 due natural production declines offset by an increase in sales price received for NGLs.  Natural gas revenues for Q4 2010 decreased 23% to $7.3 million from $9.5 million when compared to Q4 2009 which was the result of a 13% decrease in production volumes and a 12% decrease in the sales price received for natural gas.

The realized gain on commodity contracts for Q4 2010 increased 88% to $1.4 million compared to $0.8 million in Q4 2009 due to the lower 2010 natural gas prices causing greater benefits from the Company’s hedging program.  The unrealized mark-to-market loss on commodity contracts in Q4 2010 was to $3.6 million compared to a loss of $1.3 million during Q4 2009.  The unrealized mark-to-market loss on commodity contracts in Q4 2010 was due to the increase in the price for oil.

Oil revenues for 2010 increased 5% to $62.3 million from $59.3 million in 2009 which was the result of an 18% increase in sales price received for oil which was partially offset by an 11% decrease in production volumes when compared to 2009.  NGL revenues for 2010 increased 52% to $38.6 million from $25.3 million in 2009 due to a 32% increase in sales price received for NGLs and a 16% increase in production when compared to 2009.  Natural gas revenues for 2010 decreased 8% to $36.8 million from $40.0 million in 2009 due to a 16% decrease in production volumes which was partially offset by a 10% increase in sales price received for natural gas compared to 2009.

The realized gain on commodity contracts in 2010 decreased 62% to $6.0 million compared to $15.9 million in 2009 due to the higher natural gas prices embedded in the hedging program in 2009 and the subsequent overall decline in natural gas prices.  The unrealized mark-to-market loss on commodity contracts in 2010 was $0.9 million compared to a loss of $13.7 million during 2009.  The unrealized mark-to-market losses on commodity contracts are the result of the increases in price for oil.

For 2011 planning purposes, the Company uses US$80.00 per bbl for WTI, US$4.25 per mmbtu for NYMEX natural gas, $3.50 per mcf for AECO natural gas, an exchange rate of CAD$1.00:US$1.00 and a discount of 53% for U.S. NGL pricing.

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.

The mark-to-market value of the commodity contracts is determined based on the estimated fair value as at December 31, 2010 that was obtained from the counterparties to the economic hedges.  Equal then evaluates the reasonability 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, 2010, the following financial derivatives and fixed price contracts were outstanding:

Derivative Instrument	Commodity	Price (2)	Volume per day (2)	Period
Fixed	Gas	5.45 ($/GJ) (5.56 ($/mcf))	1,000 GJ (981 mcf)	March 1, 2010 – February 28, 2011
Fixed	Gas	4.48 (US$/mmbtu) (4.64 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – October 31, 2011
Fixed	Gas	4.53 (US$/mmbtu) (4.69 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – October 31, 2011
Fixed	Gas	4.50 (US$/mmbtu) (4.66 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – March 31, 2012
Fixed Basis Differential (1)	Gas	Differential Fixed @  $0.33 US$/mmbtu ($0.34 US$/mcf)	5,000 mmbtu (4,831 mcf)	April 1, 2011 – October 31, 2011
Fixed	Oil	89.66 ($/bbl)	200 bbl	January 1, 2011 – December 31, 2011
Fixed	Oil	90.00 ($/bbl)	200 bbl	January 1, 2011 – December 31, 2011
Fixed	Oil	93.00 ($/bbl)	200 bbl	January 1, 2011 – December 31, 2011
Fixed	Oil	94.00 ($/bbl)	200 bbl	January 1, 2011 – December 31, 2011
Fixed	Oil	94.60 ($/bbl)	200 bbl	January 1, 2011 – December 31, 2011

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

(2)        Conversion rates of 1.0350 mmbtu per mcf and 1.0194 GJ per mcf.

At December 31, 2010, the following physical sales contract was outstanding:

Type of contract	Commodity	Price (1)	Volume per day (1)	Period
Fixed Sale	Gas	5.48 ($/GJ) (5.59 ($/mcf))	1,000 GJ (981 mcf)	March 1, 2010 – February 28, 2011

(1)   Conversion rates of 1.0194 GJ per mcf.

As at December 31, 2010 the above commodity contracts had a net mark-to-market liability position of $0.7 million compared to a net asset balance of $0.2 million on December 31, 2009.  This change relates primarily to the increase in the price for natural gas and oil during the year.

Equal entered into the following commodity contracts after December 31, 2010:

Type of contract	Commodity	Price (1)	Volume per day (1)	Period
Fixed	Gas	4.60 (US$/mmbtu) (4.76 US$/mcf)	2,000 mmbtu (1,932 mcf)	April 1, 2011 – October 31, 2011
Fixed	Gas	4.75 (US$/mmbtu) (4.92 US$/mcf)	2,000 mmbtu (1,932 mcf)	February 1, 2011 – December 31, 2011
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	Oil	98.40 ($/bbl)	200 bbl	April 1, 2011 – December 31, 2011
Fixed	Oil	100.00 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012
Fixed	Oil	101.05 ($/bbl)	200 bbl	January 1, 2012 – December 31, 2012

(1)   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.  On an overall basis, royalties increased in 2010 compared to 2009 due to higher commodity prices for both oil and natural gas.  As a percentage of revenue before mark-to-market adjustments, royalties were 20% for 2010 compared to 19% for 2009.

Royalties (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2010			2009			Change			2010			2009			Change
Royalties		6,963			8,549			(19	%)		29,330			26,570			10	%
As a percentage of revenues before mark-to-market adjustments		20	%		23	%					20	%		19	%
Royalties per boe ($)		8.77			9.70			(10	%)		8.81			7.37			20	%

Royalties by Geographic Area (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31, 2010						Year ended December 31, 2010
	Canada			U.S.			Canada			U.S.
Royalties		2,989			3,974			13,890			15,440
As a percentage of revenues before mark-to-market adjustments		17	%		22	%		18	%		23	%
Royalties per boe ($)		9.13			8.52			9.32			8.40

During the three months ended December 31, 2010, royalties decreased 19% to $7.0 million from $8.5 million from the same period in 2009 primarily as a result of a 10% decrease in production and lower royalty rates on horizontal oil wells drilled in Canada during 2010.  The horizontal oil wells are charged a 5% Alberta Crown royalty for the first 18-36 months depending on their total depth.  Q4 2010 royalties increased 5% compared to Q3 2010 royalties of $6.6 million due to higher oil and NGL revenues in Q4 2010.

During 2010, royalties increased 10% to $29.3 million from $26.6 million in 2009 primarily as a result of the higher prices received for oil, NGLs and natural gas during 2010 compared to 2009 which was partially offset by the lower royalty rates on the horizontal oil wells drilled in Canada during 2010.

During 2011, royalty rates as a percentage of revenues are expected to slightly decrease compared to 2010 due to the planned drilling of horizontal wells in Canada.

PRODUCTION EXPENSE

Production Expense (in thousands Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended December 31
	2010		2009		Change			2010		2009			Change
Production expense		8,469		8,948		(5	%)		35,826		39,659			(10	%)
Non-cash gain (loss) from power contracts		-		89		(100	%)		-		(449	)		(100	%)
Cash production costs		8,469		9,037		(6	%)		35,826		39,210			(9	%)
Production expense per boe ($)		10.67		10.15		5	%		10.76		11.00			(2	%)
Non-cash gain (loss) from power contracts per boe ($)		-		0.10		(100	%)		-		(0.12	)		(100	%)
Cash production costs per boe ($)		10.67		10.25		4	%		10.76		10.88			(1	%)

For the three months ended December 31, 2010, cash production costs decreased 6% to $8.5 million from $9.0 million from the same period in 2009 primarily due to the decrease in production.  Cash production costs on a per boe basis increased 4% to $10.67 per boe compared to $10.25 per boe for the same period in 2009 and decreased 14% compared to $11.88 per boe in Q3 2010.

For 2010, cash production costs decreased 9% to $35.8 million from $39.2 million in 2009 primarily due to the decrease in production.  Cash production costs per boe were flat at $10.76 per boe compared to $10.88 per boe in 2009 as the Company maintains a disciplined approach to cost management.  

Production Expense by Geographic Area (in thousands except for per boe amounts)
	Three months ended December 31, 2010				Year ended December 31, 2010
	Canada		U.S.		Canada		U.S.
Cash production costs		5,669		2,800		25,364		10,462
Cash production costs per boe ($)		17.32		6.00		17.03		5.69

Canadian Operations

In Canada for the three months ended December 31, 2010, cash production costs decreased by 8% to $5.7 million from $6.2 million during the same period in 2009 which is mainly due to the 9% decrease in production in Q4 2010 compared to Q4 2009.  On a per boe basis, cash production costs remained relatively flat at $17.32 per boe versus $17.17 per boe in Q4 2009 and decreased 10% compared to $19.16 per boe in Q3 2010 due to the Cardium and Viking light oil resource plays that have operating costs in the $10.00 to $15.00 per boe range.  Continued new volumes coming on stream from production additions in the Cardium and Viking resource plays should continue to improve the overall per boe operating costs in the future.

On an overall cost basis, 2010 cash production costs increased by 4% to $25.4 million compared to $24.3 million in 2009 which is primarily due to the 2009 production costs being reduced by a $1.1 million insurance settlement dating back to a claim from 2007.  On a per boe basis they increased by 13% to $17.03 per boe versus $15.09 per boe in 2009 primarily due to the insurance settlement and the 8% decrease in production in 2010 compared to 2009.

U.S. Operations

In the U.S. for the three months ended December 31, 2010, cash production costs decreased by 3% to $2.8 million from $2.9 million and on a per boe basis they increased by 9% to $6.00 per boe versus $5.48 per boe during the same period in 2009.  The increase on a per boe basis is mainly due to 11% decrease in production.  The Q4 2010 production costs per boe decreased by 4% compared to Q3 2010 production costs of $6.23 per boe mainly due to a 3% increase in production. 

In the U.S. for 2010 cash production costs decreased by 30% to $10.5 million from $14.9 million during 2009 and on a per boe basis they decreased 24% to $5.69 per boe versus $7.47 per boe during 2009 primarily due to decreasing water disposal volumes.  Total water disposal volumes decreased by 37% from 2009 to 2010.

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 of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended December 31
	2010		2009		Change			2010		2009		Change
Transportation expense		629		523		20	%		2,370		2,519		(6	%)
Transportation expense per boe ($)		0.79		0.59		34	%		0.71		0.70		1	%

For the three months ended December 31, 2010, transportation costs increased 34% to $0.79 per boe from $0.59 per boe in Q4 2009 and increased 27% from $0.62 per boe in Q3 2010.  The increase in transportation expense is due to the production from Equal’s new oil wells drilled in 2010 being transported by truck.

For 2010, transportation costs were flat at $0.71 per boe from $0.70 per boe in 2009.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expense (“G&A”) increased by 22% in 2010 compared to 2009 on a total dollar basis and increased by 33% on a per boe basis.

General and Administrative Expense (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2010			2009			Change			2010			2009			Change
Gross G&A expense		7,693			5,137			50	%		24,392			20,103			21	%
Capitalized		(95	)		(299	)		(68	%)		(1,530	)		(1,153	)		33	%
Recoveries		(1,300	)		(551	)		136	%		(3,635	)		(3,243	)		12	%
G&A expense		6,298			4,287			47	%		19,227			15,707			22	%
G&A expense per boe ($)		7.93			4.86			63	%		5.78			4.36			33	%

For the three months ended December 31, 2010, G&A costs were $7.93 per boe compared to $4.86 per boe during the same period in 2009.  The increase in G&A is primarily due to legal fees related to the claims against Equal made by a joint venture participant in Oklahoma which totalled $4.4 million ($5.56 per boe) during the quarter which were partially offset by cost reduction in other areas.

For 2010, G&A costs were $5.78 per boe compared to $4.36 per boe in 2009.  The increase in G&A is primarily due to the legal fees related to defending claims made against Equal by a joint venture participant in Oklahoma which totalled $6.0 million ($1.81 per boe) and the costs associated with the Plan of Arrangement which totalled $0.9 million ($0.28 per boe) during the year which were partially offset by Equal’s focus on G&A cost reduction.

Equal anticipates that the G&A costs will decrease on an overall and per boe basis since the legal proceedings with the joint venture participant are expected to be completed in the first half of 2011 and the Plan of Arrangement was a one-time cost.

INTEREST EXPENSE

Interest expense for 2010 was $13.5 million which was comprised of interest on long-term debt of $2.4 million and interest on convertible debentures of $11.9 million less interest income of $0.7 million.  The increase in interest expense in 2010 compared to 2009 is primarily due to the decrease in interest income which is offset against the total expense.

Interest Expense (in thousands of Canadian except for percentages and per boe amounts)
	Three months ended December 31									Year ended December 31
	2010			2009			Change			2010			2009			Change
Cash interest expense on long-term debt		461			713			(35	%)		2,364			2,814			(16	%)
Cash interest expense on convertible debentures		2,398			2,403			0	%		9,684			9,719			0	%
Cash interest income		(30	)		(542	)		(94	%)		(748	)		(2,960	)		(75	%)
Subtotal cash interest expense		2,829			2,574			10	%		11,300			9,573			18	%
Non-cash interest expense on convertible debentures		564			525			7	%		2,238			1,888			19	%
Total interest expense		3,393			3,099			9	%		13,538			11,461			18	%
Cash interest expense per boe on long-term debt ($)		0.58			0.81			(28	%)		0.71			0.78			(9	%)
Cash interest expense per boe on convertible debentures ($)		3.02			2.73			11	%		2.91			2.70			8	%
Cash interest income per boe ($)		(0.04	)		(0.62	)		(94	%)		(0.22	)		(0.82	)		(73	%)
Total cash interest expense per boe ($)		3.56			2.92			22	%		3.40			2.66			28	%

For the three months ended December 31, 2010, interest expense on long-term debt decreased 35% to $0.5 million from $0.7 million in Q4 2009 due to lower debt levels and was relatively consistent compared to $0.5 million in Q3 2010.

For 2010, interest expense on long-term debt decreased 16% to $2.4 million from $2.8 million in 2009 due to lower debt levels and lower borrowing rates on the bank credit facility.

Equal’s long-term debt balance at December 31, 2010 was $24.9 million compared to $70.0 million at the end of 2009.  The average interest rate on long-term debt for 2010 was 4.83% and the rate as of March 22, 2011 is approximately 3.78%.

The cash interest expense on convertible debentures for the three months and year ended December 31, 2010 were comparable to the same periods in 2009.

Interest income for the Q4 2010 decreased 94% to $30 thousand from $0.5 million for the same period in 2009.  Interest income for 2010 decreased 75% to $0.7 million from $3.0 million in 2009 and decreased 85% compared to $0.2 million during Q3 2010.  The decreases for the three months and year ended December 31, 2010 compared to the same periods in 2009 are due to uncertainty of the collectability of the interest component on a long-term receivable from a joint venture participant who filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in May 2010.  Due to this uncertainty, no interest income was accrued after May 2010 on amounts owing from the joint venture participant.

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
	2010			2009			Change			2010			2009			Change
Gross share-based compensation expense		675			690			(2	%)		3,934			3,843			2	%
Capitalized		(73	)		(1	)		100	%		(298	)		(263	)		13	%
Share-based compensation expense		602			689			(13	%)		3,636			3,580			2	%
Share-based compensation expense per boe ($)		0.76			0.78			(3	%)		1.09			0.99			10	%

For the three months ended December 31, 2010, non-cash share-based compensation expense was $0.6 million compared to $0.7 million for the same period in 2009 and $0.7 million in Q3 2010.

For 2010, non-cash share-based compensation expense was $3.6 million which is unchanged from $3.6 million in 2009.

DEPLETION, DEPRECIATION AND ACCRETION (“DD&A”)

Depletion, Depreciation and Accretion (in thousands of Canadian dollars except for percentages and per boe amounts)
	Three months ended December 31							Year ended  December 31
	2010		2009		Change			2010		2009		Change
DD&A		15,389		19,597		(21	%)		75,286		86,877		(13	%)
DD&A per boe ($)		19.38		22.23		(13	%)		22.62		24.10		(6	%)

For the three months ended December 31, 2010, DD&A expenses decreased 21% to $15.4 million compared to $19.6 million in both Q4 2009 and Q3 2010.  The decrease in DD&A expenses in Q4 2010 compared to Q4 2009 is mainly due to the decrease in production and increase in proved reserves at low finding and development costs from the Cardium, Viking and Hunton resource plays.  DD&A expenses on a per boe basis decreased 13% to $19.38 per boe during Q4 2010 compared to $22.23 per boe in Q4 2009 due to the increase in proved reserves at low finding and development costs from the Cardium, Viking and Hunton resource plays.

For 2010, DD&A expenses decreased by 13% to $75.3 million compared to $86.9 million in 2009.  The decrease in DD&A expenses in 2010 compared to 2009 is mainly due to the decrease in production during the year.  DD&A expenses on a boe basis decreased 6% to $22.62 in 2010 from $24.10 per boe in 2009 due to the increase in proved reserves at low finding and development costs from the Cardium, Viking and Hunton resource plays.

Ceiling Test

Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets.  The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties, and the cost of major development projects exceeds the carrying value.  When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties, and the cost of major development projects.  When required the cash flows are estimated using expected future product prices and costs which are discounted using a risk-free interest rate.

Equal completed ceiling test calculations for the Canadian and U.S. cost centers as at December 31, 2010 to assess the recoverability of costs recorded in respect of the petroleum and natural gas properties.  The ceiling test calculations did not result in an impairment of the Canadian cost center or the U.S. cost center.

FOREIGN EXCHANGE

For 2010, there was a foreign exchange gain of $1.3 million compared to a loss of $1.4 million in 2009.

TAXES

For the year ended December 31, 2010, the future income tax reduction was $1.3 million compared to the future income tax reduction of $17.6 million in the same period in 2009.  The federal and provincial statutory rate was 28.2% at December 31, 2010 compared to an effective tax rate of 1.7%.  The primary reason for the variance in the effective tax rate and the statutory tax rate is the result of the non-deductible share-based compensation, the difference between the U.S. and Canadian tax rates, foreign exchange rate differences and the Company reorganized its Canadian and U.S. operations.

LOSS

For 2010, the loss was $34.5 million (loss of $1.40 per share) compared to a loss of $41.3 million (loss of $1.95 per share) in 2009.  The decrease in the loss in 2010 compared to 2009 was the result of an increase in the price for oil and NGLs, decrease in DD&A and production costs which were partially offset by lower production and higher royalties and G&A costs.

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 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 table below:

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
	2010			2009			2010			2009
Loss		(19,557	)		(8,939	)		(34,536	)		(41,282	)
Future income taxes (reduction)		8,654			9			(1,279	)		(17,594	)
Foreign exchange loss		54			850			383			1,159
Depletion, depreciation and accretion		15,389			19,597			75,286			86,877
Non-cash interest expense		564			525			2,238			1,888
Share based compensation expense		602			689			3,636			3,580
Unrealized mark-to-market loss (gain) on commodity contracts		3,632			1,182			912			14,127
Provision for non-recoverable receivables		-			(2,110	)		-			(2,110	)
Funds from operations		9,338			11,803			46,640			46,645
Total volume (mboe)		794			882			3,328			3,605
Cash flow netback (non-GAAP) ($ per boe)		11.76			13.38			14.01			12.94

Funds from Operations

Management uses funds from operations to analyze operating performance and leverage.  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, before changes in non-cash working capital, as reconciled in the table below:

Funds from Operations (in thousands of Canadian dollars)
	Three months ended December 31						Year ended December 31
	2010			2009			2010		2009
Cash provided by operating activities		10,341			22,853			34,436		51,470
Changes in non-cash working capital items		(1,302	)		(10,516	)		10,615		(5,248	)
Asset retirement costs incurred		299			1,576			1,589		2,533
Provision for non-recoverable receivables		-			(2,110	)		-		(2,110	)
Funds from operations		9,338			11,803			46,640		46,645

For the three months ended December 31, 2010, funds from operations decreased by 21% to $9.3 million from $11.8 million in Q4 2009.  The decrease in funds from operations is primarily the result of legal fees related to the claims made against Equal by a joint venture participant in Oklahoma which totalled $4.4 million during the quarter which were partially offset by Equal’s focus on cost reduction and lower production costs.

In 2010, funds from operations were $46.6 million which was the same as in 2009.  The higher prices received for oil, NGLs and natural gas and lower production costs were partially offset by higher royalties, higher legal fees and lower interest income.

CAPITAL EXPENDITURES

Capital Expenditures (in thousands of Canadian dollars except for percentages)
	Three months ended December 31									Year ended December 31
	2010			2009			Change			2010			2009			Change
Capital expenditures		25,453			4,815			100	%		77,678			22,206			250	%
Acquisition funded by trust unit issuance		-			-			-			-			2,720			(100	%)
Capital expenditures to be recovered		-			103			(100	%)		-			1,744			(100	%)
Amounts recovered under agreement		-			(2,592	)		(100	%)		(3,503	)		(11,004	)		(68	%)
Dispositions		(40	)		-			100	%		(26,272	)		-			100	%
Total		25,413			2,326			100	%		47,903			15,666			206	%

During 2010, Equal’s net capital expenditures were $47.9 million, of which Equal spent $77.7 million in total capital expenditures, recovered $3.5 million from a capital recovery agreement and received $26.3 million from dispositions of non-core properties.

Expenditures in Canada for 2010 totaled $63.8 million and net proceeds from dispositions totaled $26.3 million.  The major components of these expenditures include:

·   $17.8 million on property and facility acquisitions;

·   $30.6 million on wells, drilling and workovers;

· $9.7 million on land and seismic acquisition;

· $4.3 million facilities and other equipment maintenance; and

· $1.4 million related to the capitalization of certain G&A costs identified as attributable to exploration and development activities.

Expenditures in the U.S. for 2010 totaled $13.9 million of which the major expenditures include:

·   $5.6 million on acquiring additional working interest in wells from non-operated working interest partners;

·   $4.2 million related to wells, drilling and workovers;

·   $1.3 million on acquisitions of land for future development in Oklahoma;

·   $1.7 million on capital enhancements;

·   $0.6 million on inventory and other assets; and

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

During 2010, Equal received a total of $3.5 million of principal repayments under a capital recovery agreement.

Equal’s near term drilling will be focused on light oil targets in Alberta-based Cardium and Viking resource plays which have operating margins significantly higher than its current average Canadian production.  With this focus on light oil, Equal expects its cash flow netback to improve as each well is drilled and brought online.  Drilling has also commenced in Oklahoma in Q1 2011 as Equal and a joint venture participant in Oklahoma have agreed that a farm-out agreement was terminated prior to the joint venture participant filing for bankruptcy protection, freeing the Company to resume drilling in the Hunton play without a partner.

During 2011, capital expenditures are expected to approximate funds from operations.  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.

Equal accounts for its investment in its U.S. operations as a self-sustaining operation which means the capital assets associated with the U.S. operations (as well as all other balance sheet accounts for the U.S. operations) are subject to revaluation to the current exchange rate at each balance sheet date.  The result of this revaluation is a change in the carrying value of the U.S. assets from period to period.

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.  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 natural 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 2010, Equal’s Bank Syndicate completed a borrowing base review and increased the borrowing base to $125.0 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.  Equal’s syndicate of lenders, consisting of Bank of Nova Scotia, HSBC Bank Canada and Union Bank, has confirmed their $125.0 million credit facility commitment to Equal.

The next review of the bank credit facility is expected to be completed in June 2011 based on December 31, 2010 reserves.  Management does not expect any significant changes from this review.

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 55% of Equal’s total 2010 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.

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 units.  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 unitholders.

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, 2010, Equal has commitments for the following payments over the next five years:

Financial Instrument – Liability
(in thousands of Canadian dollars)	2011		2012		2013		2014 – 2015	Total
Long-term debt (1)		-		24,865		-	-		24,865
Interest on long-term debt (2)		748		374		-	-		1,122
Convertible debentures		80,127		39,648		-	-		119,775
Interest on convertible debentures (3)		9,681		1,635		-	-		11,316
Accounts payable & accrued liabilities		31,321		-		-	-		31,321
Due to JV Participant		10,046		-		-	-		10,046
Commodity contracts		743		-		-	-		743
Office leases (4)		1,787		1,232		1,188	2,190		6,397
Vehicle and other operating leases		250		71		10	4		335
Total obligations		134,703		67,825		1,198	2,194		205,920

(1)  Assumes the credit facilities are not renewed on June 24, 2011.

(2)  Assumes an interest rate of 3.01% (the rate on December 31, 2010).

(3)  Does not reflect the early redemption of the 8% convertible debentures subsequent to December 31, 2010

(4)  Future office lease commitments may be reduced by sublease recoveries totaling $0.7 million.

LIQUIDITY & CAPITAL RESOURCES

During 2010, Equal closed the sale of non-core sour gas assets which had net proceeds of $26.3 million and completed a bought deal equity offering which raised net proceeds of $35.6 million.  The proceeds from the sale of the non-core assets were used to pay down the bank debt and the proceeds from the equity offering were used to support the ongoing capital program; both of which give Equal additional financial flexibility.

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 September 30 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 were 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.

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 2011.  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 2011 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, 2010 is as follows:

	December 31, 2010					December 31, 2009
Capitalization (in thousand of Canadian dollars except percentages)	Amount		%			Amount			%
Long-term debt		24,865		8	%		70,000			24	%
Working capital deficit (surplus)(1) excluding long-term debt		11,878		4	%		(28,554	)		(10	%)
Working capital deficit (1) including long-term debt		36,743		12	%		41,446			14	%
Convertible debentures		117,019		36	%		114,863			39	%
Shares issued, at market (2)		169,584		52	%		141,499			47	%
Total capitalization		323,347		100	%		297,808			100	%

(1) Working capital excludes deferred revenues, unrealized gains and losses on commodity contracts and future income taxes.

(2) The market price of Equal’s shares on December 31, 2010 was $6.12 per share (December 31, 2009 – $6.54 per share per share restated for the three trust unit for one share exchange).

Long-term Debt

Long-term debt is represented by the amounts drawn on the Bank Credit Facility.  At December 31, 2010, Equal’s long-term debt was $24.9 million, a decrease of $45.1 million from $70.0 million at December 31, 2009.  Equal has credit facilities with its banking syndicate that includes revolving and operating credit facilities which have a borrowing capacity of $125.0 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
(in thousands of Canadian dollars except for ratios)	December 31, 2010		December 31, 2009
Interest coverage (1):
Cash flow over the prior four quarters		58,688		61,288
Interest expenses over the prior four quarters		12,048		12,533
Interest coverage ratio	4.87 : 1.00		4.89 : 1.00

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

Working Capital

Working capital decreased by $40.4 million from December 31, 2009 mainly due to a decrease in cash of $17.2 million, an increase in accounts payable of $3.3 million, the recognition of a payable to a joint venture participant pursuant to a court order (see “Subsequent Events”) of $10.0 million and a transfer to fixed assets of the current portion of long-term receivable ($11.2 million at December 31, 2009 due from a joint venture participant in Oklahoma) due to the uncertainty of its collection which were partially offset by an increase in accounts receivable of $1.2 million.

	As at
Working Capital (in thousands of Canadian dollars)	December 31, 2010			December 31, 2009
Working capital (deficit) (1)		(11,878	)		28,544

(1) Working capital excludes deferred revenues, commodity contracts and future income taxes.

Long-term Receivable

In 2006 Equal entered into a farm-out agreement with Petroflow Energy Ltd. and its subsidiaries (“JV Participant”), a public oil and gas company, to fund the drilling and completion costs of the undeveloped lands in Oklahoma.  Per the agreement, JV Participant paid 100% of the drilling and completion costs to earn 70% of Equal’s interest in each well.  Equal was required to build the infrastructure to support these wells, such as pipelines and salt water disposal wells.  The infrastructure costs incurred by Equal were recoverable from JV Participant over three years with interest charged at a rate of 12% per annum.  Infrastructure costs incurred by Equal were accounted for as a finance lease; therefore, the capital costs incurred were not included in property, plant and equipment but were recorded as current and long-term receivables.  The interest income on the long-term receivable was recorded as a reduction in interest expense.

In December 2009 Equal delivered a notice of termination for non-performance under the terms of the farm-out agreement with JV Participant.  JV Participant was required to maintain a certain pace of drilling to continue its right to drill on lands owned by Equal but ceased drilling in February 2009 and had not indicated that it will be able to continue drilling with any certainty.  Final notice of termination of the farm-out agreement was delivered in January 2010.

In April 2010, a notice of default was sent to JV Participant which accelerated the capital recovery amortization payments such that the entire receivable amount is due and payable.

In May 2010, JV Participant filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code; at which time, the Company stopped recording interest income on the long-term receivable.

In January 2011, Equal and JV Participant agreed that the farm-out agreement was terminated prior to JV Participant filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  The termination of the farm-out agreement allows Equal to pursue drilling in the Hunton resource play which was previously restricted by a bankruptcy court.  In March 2011, the bankruptcy court concluded that Equal retains ownership and control of the salt water disposal infrastructure and that Equal has the right to charge JV Participant for all salt water processed from the inception of each facility.  Equal is also required to reimburse JV Participant for certain amounts received as fees for access to the facilities.  On March 18, 2011, Equal and JV Participant agreed to a 30 day stay of proceedings on the bankruptcy court’s conclusion.

As a result of the bankruptcy court ruling, property, plant and equipment was increased by $30.3 million which was offset by the eliminations of the long-term receivable of $12.5 million and joint interest billing receivable from JV Participant of $5.9 million and the recognition of deferred revenues of $1.9 million and a payable of $10.0 million due to JV Participant.

Convertible Debentures

As at December 31, 2010, Equal had $117.0 million of convertible debentures outstanding with a face value of $119.8 million.  During Q3 2010, Equal made the necessary filings, and received the necessary approvals, to make a normal course issuer bid for its 8.25% and 8.00% convertible debentures.  The normal course issuer bid is effective until August 5, 2011.  During 2010, $0.1 million of the 8% convertible debentures were purchased and cancelled pursuant to the normal course issuer bid.  There were no 8.25% convertible debentures cancelled pursuant to the normal course issuer bid in 2010.

The debentures have the following conversion prices:

· ENT.DB – $27.75.  Each $1,000 principal amount of ENT.DB debentures is convertible into approximately 36.04 Equal shares.  Mature on December 31, 2011.

· ENT.DB.A – $20.40.  Each $1,000 principal amount of ENT.DB.A debentures is convertible into approximately 49.02 Equal shares.  Mature on June 30, 2012.

As at December 31, 2010, Equal has issued capital of 27.7 million shares outstanding.  If all the outstanding convertible debentures were converted into shares at their respective conversion prices, a total of 32.5 million shares would be outstanding.

SUBSEQUENT EVENTS

In January 2011, Equal and JV Participant agreed that the farm-out agreement was terminated prior to JV Participant filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  The termination of the farm-out agreement allows Equal to pursue drilling in the Hunton resource play which was previously restricted by a bankruptcy court.  In March 2011, the bankruptcy court concluded that Equal retains ownership and control of the salt water disposal infrastructure and that Equal has the right to charge JV Participant for all salt water processed from the inception of each facility.  Equal is also required to reimburse JV Participant for certain amounts received for access to the facilities.  On March 18, 2011, Equal and JV Participant agreed to a 30 day stay of proceedings on the bankruptcy court’s conclusion.

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 September 30 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.

On March 14, 2011, the outstanding $79.9 million in face value of 8.00% convertible unsecured debentures were redeemed for $83.2 million which included the early redemption premium and unpaid interest.  The redemption was funded by the issuance of the 6.75% convertible unsecured junior subordinated debentures and Equal’s credit facility.

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.

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.

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.

Reserve volumes and values at December 31, 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, 2010 and 2009 and Haas Petroleum Engineering Services, Inc. (“Haas”) evaluated the Oklahoma reserves as at December 31, 2010 and 2009.  The reserve engineers evaluated 100% of the Company’s December 31, 2010 reserves.  The independent engineers used the following future price forecasts in order to evaluate Equal’s reserves as of December 31, 2010.

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)
2011	85.00	84.20	4.25	4.55	0.975
2012	87.70	88.40	4.90	5.30	0.975
2013	90.50	91.80	5.40	5.75	0.975
2014	93.40	94.80	5.90	6.30	0.975
2015	96.30	97.70	6.35	6.80	0.975
2016	99.40	100.90	6.75	7.35	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 and Gas (mboe)

	Proved			Probable			Total
December 31, 2008		19,636			7,264			26,900
Discoveries and extensions		128			31			159
Purchases		860			45			905
Production		(3,605	)		-			(3,605	)
Revision of prior estimates		5,319			1,568			6,887
December 31, 2009		22,338			8,908			31,246
Discoveries and extensions		2,166			1,002			3,168
Purchases		682			243			925
Dispositions		(803	)		(623	)		(1,426	)
Production		(3,328	)		-			(3,328	)
Revision of prior estimates		4,797			(3,467	)		1,330
December 31, 2010		25,852			6,063			31,915

By the end of 2010, total reserves increased by 2% to 31,915 mboe compared to 31,246 mboe from the start of the year.  The increase in the reserves is mainly due to the new wells drilled in the Lochend and Viking resource plays and positive revisions to the reserve estimates in the Hunton resource play.  The main factors contributing to the positive revisions were the increasing NGL yields from the Hunton assets and improved reservoir performance.

By the end of 2010, proved reserves increased by 16% to 25,852 mboe compared to 22,338 mboe from the start of the year which was mainly the result of Equal’s increased drilling in the Lochend and Viking resource plays and positive revisions from the increasing NGL yields from the Hunton assets and improved reservoir performance.

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 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

	Years Ended December 31								3-Year
(in $/boe, except for capital expenditures, FDC and reserves which are in thousands)	2010			2009		2008			Average
Capital expenditures (1)		54,522			16,445		37,054			36,687
Future Development Costs Proved		63,094			64,811		36,108			54,671
Proved Plus Probable		87,762			100,678		50,025			79,488
Reserves (2)
Proved reserves added in the year (mboe)		6,963			5,447		4,412			5,607
Probable reserves added in the year (mboe)		(2,465	)		1,599		(428	)		(431	)
Proved plus probable reserves added in the year  (mboe)		4,498			7,046		3,984			5,176
F&D costs (excluding FDC)
Proved reserves ($/boe)		7.83			3.02		8.40			6.54
Proved plus probable reserves ($/boe)		12.12			2.33		9.30			7.09
F&D costs (including FDC)
Proved reserves ($/boe)		8.03			9.17		6.61			8.04
Proved plus probable reserves ($/boe)		10.19			10.21		6.44			9.20
Recycle ratios
Operating netbacks ($/boe) (3)		22.90			20.02		36.87			26.83
Operating recycle ratio (based on proved plus probable reserves including FDC)		2.2			2.0		5.7			3.0
Corporate netbacks ($/boe) (4)		14.01			12.94		28.52			18.75
Corporate recycle ratio (based on proved plus probable finding costs including FDC)		1.4			1.3		4.4			2.1

(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.

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

Equal’s 2010 proved plus probable F&D including the change in FDC was flat at $10.19 per boe from $10.21 per boe in 2009.

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

December 31, 2010 (NPV in millions)

	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		2,375		451		102		9,072		4,440		121,639		101,841		88,843
Proved Non-Producing		50		-		6		324		110		(3,279	)	(3,001	)	(2,694	)
Proved Undeveloped		795		120		43		3,285		1,506		45,579		28,236		18,342
Total Proved		3,220		571		151		12,681		6,056		163,939		127,076		104,491
Total Probable		1,451		323		108		12,516		3,968		114,722		68,194		45,805
Total Proved & Probable		4,671		894		259		25,197		10,024		278,661		195,270		150,296
United States Assets
Proved Producing		645		-		5,586		38,474		12,643		372,726		269,772		208,631
Proved Non-Producing		-		-		100		575		196		5,249		3,723		2,767
Proved Undeveloped		-		-		2,950		24,045		6,957		179,687		115,517		76,239
Total Proved		645		-		8,636		63,094		19,796		557,662		389,012		287,637
Total Probable		3		-		983		6,651		2,095		62,916		42,943		31,080
Total Proved & Probable		648		-		9,619		69,745		21,891		620,578		431,955		318,717
Consolidated Assets
Proved Producing		3,020		451		5,688		47,546		17,083		494,365		371,613		297,474
Proved Non-Producing		50		-		106		899		306		1,970		722		73
Proved Undeveloped		795		120		2,993		27,330		8,463		225,266		143,753		94,581
Total Proved		3,865		571		8,787		75,775		25,852		721,601		516,088		392,128
Total Probable		1,454		323		1,091		19,167		6,063		177,638		111,137		76,885
Total Proved & Probable		5,319		894		9,878		94,942		31,915		899,239		627,225		469,013

(1)   The U.S. reserve report was converted to Canadian dollars using the Bank of Canada noon rate on December 31, 2010 of CAD$0.9946/US$1.00.

SHARE 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 Share Data as at	March 22, 2011		December 31, 2010		December 31, 2009(1)
Shares		27,730,184		27,709,859		21,700,896
Share options		959,924		1,058,152		235,331
Restricted shares		464,578		507,759		534,730
6.75% Convertible debentures ($1,000 per debenture)		45,000		-		-
8.0% Convertible debentures ($1,000 per debenture)		-		80,127		80,210
8.25% Convertible debentures ($1,000 per debenture)		39,580		39,648		39,648

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

OUTLOOK

Equal intends to focus its 2011 capital expenditures on the Alberta-based Cardium and Viking high return light oil resource plays in order to increase its cash flow netback on a per boe basis.  Drilling will also resume in the Hunton resource play in Oklahoma since the farmout agreement with a joint venture participant in Oklahoma was acknowledged in Q1 2011 to have been terminated in 2010.  Since Equal is the operator of all of its potential drilling targets, it can adjust to commodity prices and dictate the pace of its drilling programs to match cash flows.  Equal intends to maintain its operational and financial discipline and has planned a capital spending program of approximately $60 million to match estimated funds from operations in order to retain financial flexibility.

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, 2010, 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.  Management concluded that Equal’s internal control over financial reporting was effective as of December 31, 2010.  The effectiveness of Equal’s internal control over financial reporting as of December 31, 2010 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, 2010, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

CHANGES IN ACCOUNTING POLICIES

The following new Canadian standards are effective January 1, 2011.

CICA 1582 “Business Combinations”, which replaces the previous business combinations standard.  The standard requires assets and liabilities acquired in a business combination, consideration paid, contingent consideration and certain acquired contingencies to be measured at fair value on the date of acquisition.  In addition, acquisition related and restructuring costs are recognized separately from the business combination and are included in the statement of income.  The adoption of this standard impacts the accounting treatment of business combinations entered on or after January 1, 2011.

CICA 1601 "Consolidated Financial Statements" establishes the requirements for the preparation of consolidated financial statements.  The adoption of this standard had no material impact on Equal’s financial statements.

International Financial Reporting Standards

As a publicly accountable entity, Equal is required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011.  The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.  Equal’s transition to IFRS continues to progress according to plan for the 2011 financial reporting requirements.

On adoption of IFRS certain financial statement adjustments are required to be made retroactively against opening retained earnings (accumulated deficit) as at January 1, 2010.  However, IFRS 1 – ‘‘First time adoption of international financial reporting standards’’ provides entities adopting IFRS certain optional exemptions to the general requirement for full retroactive application of IFRS.  Equal expects to apply the following exemptions:

·   Property, Plant and Equipment (‘‘PP&E’’) – Equal will apply the exemption that allows entities that follow the Canadian GAAP full cost accounting guideline to allocate their historic net PP&E to Cash Generating Units (‘‘CGU’s’’) on the date of transition.  Equal has allocated the PP&E into five Cash Generating Units (“CGUs”) in Canada and one CGU in the United States, based on proved plus probable reserve volumes as at January 1, 2010.

·   Business Combinations – IFRS 1 provides an optional exemption to the requirement to retroactively restate any past business combinations recorded under Canadian GAAP.  Equal will apply this exemption and therefore will not be retroactively restating past business combinations.

·   Borrowing Costs – Equal will apply the IFRS 1 exemption which allows an entity to be exempt from capitalizing interest on qualifying assets where active development commenced before January 1, 2010.

·   Cumulative Translation Adjustment (‘‘CTA’’) – IFRS 1 provides an optional exemption to the requirement to retroactively restate CTA and allows entities to set CTA to zero at the date of transition.  Equal will apply this exemption and set CTA to zero at January 1, 2010 which will result in an increase to the accumulated deficit of approximately $22.5 million.

The following is a listing of key areas where accounting policies differ and where accounting policy decisions are necessary that will impact our reported financial position and results of operations:

·   Exploration and Evaluation (“E&E”) expenditures – Upon transition to IFRS, Equal will reclassify all E&E expenditures that are currently recognized as PP&E to E&E assets.  This consists of the carrying value of certain undeveloped land that relates to exploration properties.  E&E assets will not be amortized and must be assessed for impairment when indicators suggest the possibility of impairment as well as upon transition to PP&E.  Equal has identified approximately $4.8 million of its property, plant and equipment that meets the criteria to be classified as E&E in the opening balance sheet prepared under IFRS as at January 1, 2010.

·   Impairment of PP&E assets – Canadian GAAP generally uses a two-step approach to impairment testing; first comparing asset carrying values with undiscounted future cash flows to determine whether an impairment exists, and then measuring impairment by comparing asset carrying values to their fair value (which is calculated using discounted cash flows).  Under Canadian GAAP, Equal includes all assets in one of two full cost pools, being Canada and the United States.

IFRS uses a one-step approach for testing and measuring impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use.  Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP resulting in impairment testing being done at the CGU level.

These differences may potentially result in impairment charges where the carrying value of assets were previously supported under Canadian GAAP by consolidated undiscounted cash flows, but could not be supported by cash flows determined on a more granular discounted basis.

At January 1, 2010 preliminary impairment tests were performed in accordance with IFRS which indicated impairments of approximately $41.4 million in PP&E in the Canadian CGUs with the offset recorded to opening retained earnings (accumulated deficit).  The impairment test has not been audited and is subject to change.

·   Calculation of depletion expense for PP&E assets – Upon transition to IFRS, Equal has the option to calculate depletion using a reserve base of proved reserves or proved plus probable reserves, as compared to the Canadian GAAP method of calculating depletion using proved reserves only.  Equal plans to determine its depletion expense using proved plus probable reserves as its depletion base.

·   Equal’s former trust indenture – Under IFRS, prior to Equal converting to a corporate structure from a trust structure, Equal’s former trust indenture required that its unitholders’ capital be classified as long-term debt on the balance sheet.  Under Canadian GAAP, the unitholders’ capital was classified as equity.  At January 1, 2010, unitholders’ capital of $674.1 million is classified as long-term debt.

·   Unit issue costs – Under IFRS, since Equal’s former trust units were classified as long-term debt, the unit issue costs are amortized over the period of the debt.  At January 1, 2010, unitholders’ capital was increased by $8.8 million to reflect the amortization of the unit issue costs with the offset recorded to opening retained earnings (accumulated deficit).

·   Equity-based compensation – Under IFRS, as a result of the trust structure, the Company is required to record its equity-based compensation plans as if they were liability-settled.  As such, under IFRS, the liability is re-valued at each balance sheet date.  Under Canadian GAAP, the equity-based compensation was recorded using the equity-settled method.  At January 1, 2010, the equity-based compensation liability was $1.9 million to reflect the value of Equal’s long-term incentive plans and the $11.1 million contributed surplus balance was eliminated with the offsets recorded in opening retained earnings (accumulated deficit).

·   Convertible debentures – Under IFRS, since Equal’s former trust indenture requires it to record its unitholders’ capital as a long-term liability, it is required to revalue the convertible debentures at each balance sheet date to their fair value.  Under Canadian GAAP, the convertible debentures were bifurcated between their liability and equity components with the liability components subsequently accreted to their face value at maturity.  At January 1, 2010, Equal’s convertible debentures will decrease $0.1 million to $114.8 million as the liabilities are revalued to reflect their fair values and the $4.0 million equity component of the convertible debentures is eliminated with the offsets recorded to opening retained earnings (accumulated deficit).

·   Asset retirement obligation – Under IFRS, Equal is required to revalue its entire liability for asset retirement costs at each balance sheet date using a current liability-specific discount rate, which can generally be interpreted to mean the current risk-free rate of interest.  Under Canadian GAAP, obligations are discounted using a credit-adjusted risk-free rate and, once recorded, the asset retirement obligation is not adjusted for future changes in discount rates.  At January 1, 2010, Equal’s total of its asset retirement obligations will increase $3.9 million to $25.0 million as the liability is revalued to reflect the estimated risk free rate of interest at that time of 4.08% with the offset recorded to opening retained earnings (accumulated deficit).

·   Deferred taxes – Under IFRS, entities that are subject to different tax rates on distributed and undistributed income must calculate deferred taxes using the undistributed profits rate.  As a result of using the undistributed profits rate and other IFRS adjustments, Equal will record a reduction in its deferred tax liability of $14.6 million upon transition to IFRS with the offset recorded to opening retained earnings (accumulated deficit).

A Canadian GAAP and IFRS reconciliation of Equal’s January 1, 2010 Balance Sheet and Equity is presented below.  The adjustments and resulting IFRS amounts are unaudited and subject to change.

($ millions)	Canadian GAAP		IFRS Adjustments			IFRS
Current assets		57.5		-			57.5
Long-term assets		404.8		(41.4	)		363.4
Total assets		462.3		(41.4	)		420.9
Current liabilities		28.8		(0.1	)		28.7
Long-term liabilities		214.5		675.2			889.7
Equity		219.0		(716.5	)		(497.5	)
Total liabilities and equity		462.3		(41.4	)		420.9

In addition to accounting policy differences, Equal’s transition to IFRS is expected to impact its internal controls over financial reporting, disclosure controls and procedures, certain of Equal’s business activities and IT systems as follows:

·   Internal controls over financial reporting (“ICFR”) – Equal is currently in the process of reviewing its ICFR documentation and is identifying instances where controls must be amended or added in order to address the accounting policy changes required under IFRS.  No material changes in control procedures are expected as a result of transition to IFRS.

·   Disclosure controls and procedures – Equal has assessed the impact of transition to IFRS on its disclosure controls and procedures and has not identified any material changes required in its control environment.  It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP.  Equal is currently drafting its IFRS note disclosure in accordance with current IFRS standards and continues to monitor requirements put forth by the IASB in discussion papers and exposure drafts for future disclosure requirements.  Throughout the transition process, Equal has carefully considered its stakeholders’ information requirements and will continue to ensure that adequate and timely information is provided to meet these needs.

·   Business activities – Equal has been cognizant of the upcoming transition to IFRS and based on the changes to Equal’s accounting policies, no issues are expected to arise with the existing debt covenants and related agreements.

·   IT systems – Equal has completed the accounting system updates required in order to prepare for IFRS reporting.  The modifications were not significant, however, deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&E and E&E expenditures at a more granular level of detail for IFRS reporting.

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 revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

·   estimated capital expenditures on projects that are in progress;

·   estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that Equal expects to recover in the future;

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

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

·   outcome of the settlement with the Joint Venture Participant; and

·   estimated future recoverable value of property, plant and equipment.

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.

2010 FINANCIAL REPORT 

EQUAL ENERGY LTD.

MESSAGE TO SHAREHOLDERS

GLOSSARY

AECO	a storage and pricing hub for Canadian natural gas market	mcf per day	thousands of cubic feet of natural gas per day
bbl or bbls	barrels of oil	mmbtu	millions of British Thermal Shares
bbls per day	barrels of oil per day	mmbtu per day	millions of British Thermal Shares per day
boe	barrels of oil equivalent (6 mcf equivalent to 1 bbl)	mmcf	millions of cubic feet of natural gas
boe per day	barrels of oil equivalent per day	Mwh	megawatt-hour
Cdn$	Canadian dollars	NGL	natural gas liquids (ethane, propane, butane and condensate)
FD&A	Finding Development & Acquisition Costs	NI 51-101	National Instrument 51-101
FDC	Future Development Costs	NYMEX	New York Mercantile Exchange
GAAP	Canadian Generally Accepted Accounting Principles	Q1	first quarter of the year - January 1 to March 31
GJ	Gigajoule	Q2	second quarter of the year - April 1 to June 30
GORR	Gross overriding royalty	Q3	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)
mcf	thousand cubic feet of natural gas

2010 FINANCIAL REPORT