FOR IMMEDIATE RELEASE - CALGARY, ALBERTA - MAY 14, 2003

Baytex Energy Ltd. (TSX-BTE) of Calgary, Alberta is pleased to announce its operating and financial results for the three months ended March 31, 2003. Highlights of the first quarter in 2003 include:

• 343% increase in net income per share to $0.62 compared to $0.14 in Q1/02;

• 34% increase in cash flow per share to $1.03 compared to $0.77 in Q1/02;

• realized $133 million from the sale of assets with 3,400 boe/d of production;

• reduced debt by $173.4 million compared to one year ago; and

• 93% success in the winter drilling program which is expected to replace gas production sold in Q1/03.

A summary of the financial and operating results for the period ended March 31, 2003 is presented as follows:

	*Three Months Ended March 31*
FINANCIAL	2003		2002		% Change
($thousands, except per share amounts)	(Unaudited)
Petroleum and natural gas sales	107,047		79,130		35
Cash flow from operations	54,707		40,125		36
Per share - basic	1.03		0.77		34
- diluted	1.01		0.76		33
Net income	32,943		7,304		351
Per share - basic	0.62		0.14		343
- diluted	0.61		0.14		336

Exploration and development	61,594		39,526		56
Dispositions – net	(134,950	)	(46,363	)	n/a
Total capital expenditures	(73,356	)	(6,837	)	n/a

Long-term notes	304,145		330,249		(8	)
Bank loans and other debt	—		22,179		(100	)
Other working capital (surplus) deficiency	(93,860	)	31,255		n/a
Total net debt	210,285		383,683		(45	)

OPERATING
Daily production
Light oil (bbls/d)	2,969		3,818		(22	)
Heavy oil (bbls/d)	23,278		22,838		2
Total oil (bbls/d)	26,247		26,656		(2	)
Natural gas (mmcf/d)	74.0		73.7		—
Oil equivalent (boe/d @ 6:1)	38,580		38,948		(1	)
Average prices (before hedging)
WTI oil (US$/bbl)	33.86		21.64		56
Edmonton par oil ($/bbl)	50.91		33.51		52
BTE light oil ($/bbl)	45.41		27.58		65
BTE heavy oil ($/bbl)	31.48		21.58		46
BTE total oil ($/bbl)	33.15		22.44		48
BTE natural gas ($/mcf)	7.02		3.19		120
BTE oil equivalent ($/boe)	36.14		21.39		69

Baytex Energy Ltd.

Press Release

May 14, 2003

	Three Months Ended March 31
	2003	2002	% Change
Weighted average shares (thousands)
Basic	53,313	52,027	2
Diluted	54,434	52,596	3

Heavy Oil Pricing

Baytex commenced the delivery of oil in January 2003 under its five-year crude oil supply agreement with Frontier Oil and Refining Company. The agreement calls for Baytex to deliver Lloyd Blend (“LLB”) quality crude at Hardisty, Alberta, through the Express Pipeline to Guernsey, Wyoming. Baytex receives 71% (or 29% differential) of monthly average WTI price for the LLB crude. Quantities delivered were 9,000 bbl/d for January, 11,000 bbl/d for February and March, and will be increased to 13,000 bbl/d for April, 15,000 bbl/d from May to September and 20,000 bbl/d from October this year to the end of 2007. Each barrel of LLB crude is comprised of approximately 80% heavy oil produced by Baytex and 20% diluent.

LLB differentials averaged 25% of WTI during the first quarter of 2003, compared to the long-term first quarter average of 30%. Differentials for April 2003 averaged 30%, but current bids indicate that differentials should narrow to the mid-20% range for the summer months due to higher seasonal demand. Baytex’s cash flow is now much less affected by the volatility of differentials as approximately two-thirds of the Company’s heavy oil production will be priced according to the Frontier agreement by October.

The Frontier agreement stipulates that Baytex retains ownership of the oil in transit in the Express Pipeline. It takes approximately 15 days for the barrels to be moved from the Hardisty terminal to the Guernsey delivery point, where ownership of the oil is officially transferred from Baytex to Frontier. At the end of March 2003, there were approximately 134,000 barrels of oil in transit. These barrels have been included in the reported first quarter average production of 23,278 barrels per day. However, the revenue and expenses associated with these barrels will be reported as April sales when the title transfer occurred. This timing difference in revenue recognition has the effect of deferring $1.7 million ($0.03 per share) of cash flow from heavy oil produced in March to the following month.

Baytex has consistently followed its risk management policy in managing its exposure to fluctuations in commodity prices. The war in Iraq had kept oil prices at unusually high levels in the first quarter with WTI averaging US$33.86 during this period. Consequently, Baytex reported a loss from derivative contracts of $13.6 million or $0.26 per share for the quarter compared to a gain of $4.1 million or $0.08 per share for the same period last year. Excluding the impact of derivative contracts, cash flow per share for the first quarter of 2003 would have been 86% higher than that of the first quarter one year ago.

Property Sale and Debt Reduction

On March 31, 2003, Baytex completed the sale of its producing assets at Ferrier, O’Chiese, Willesden Green and Brazeau River in Alberta for cash consideration of $133.3 million. These assets produced an aggregate 15.1 mmcf/d of natural gas and 900 bbl/d of associated liquids in the first quarter of 2003, which were included in Baytex’s total production reported for this period. Utilizing part of the proceeds from this property sale, on May 5, 2003, Baytex prepaid all of its outstanding US$57 million senior secured notes. Total costs of the prepayment amounted to $90 million, leaving the Company with approximately $40 million of cash on deposit. The rising Canadian dollar since the beginning of the year has benefited Baytex in the prepayment of these notes. The US$/CDN$ exchange rate has gone from 0.6331 at December 31, 2002 to 0.6806 at March 31, 2003 to the current 0.72 range. As the Company’s only remaining debt is the US$150 million senior subordinated notes, Baytex’s debt position will benefit should the strength of the Canadian currency continue.

Winter Drilling Results

Baytex conducted a very active exploration and development program of $62 million in the first quarter of 2003, compared to $40 million spent a year ago. During the first quarter, the Company participated in the drilling of 104 (92.1 net) wells, resulting in 63 (56.0 net) oil wells, 31 (26.8 net) gas wells, three (2.3 net) service wells and seven (7.0 net) dry holes. Overall success rate was 93.3% (92.4% net).

This winter’s natural gas drilling program was highlighted by a successful follow-up well at Chinchaga, where a Slave Point discovery well was drilled a year ago. Baytex is currently constructing an 8.0 mmcf/d gas plant and expects to tie in these two wells by August this year. The Company plans to drill one or two development wells in this area next winter.

Other natural gas drilling conducted by the Company’s Northern District included six development wells in the Goodfish/Nina area and one well at Edson. This District was also successful in drilling four development wells at Red Earth for light oil, as well as an exploratory oil well at each of Red Fish, Alberta and Laprise, British Columbia. The Plains District drilled a total of 13 gas wells in the Company’s central Alberta areas of Bon Accord, Leahurst and Garden Plains. This District was also responsible for the drilling of five successful wells in the Ferrier/O’Chiese area in the first quarter, which wells were included in the asset disposition program. The overall success of the winter drilling program is expected to result in the replacement of the gas production recently sold when all new wells are tied in by August this summer.

The Company drilled a total of 56 heavy oil wells during the first quarter, with 23 of these wells at Carruthers and 14 at Ardmore. Wells drilled in the first quarter will contribute to production in the second quarter. Baytex plans to drill 50 heavy oil wells during the second quarter. However, the wet spring conditions may delay this drilling plan in addition to curtailing production in the affected areas.

Corporate Governance

The Board of Directors of Baytex is committed to ensuring proper corporate governance practices for the Company and continues to search for ways to enhance the Board’s ability to guide the Company in today’s dynamic corporate environment. In this regard, Baytex is pleased to announce that Mr. Edward Chwyl and Mr. Gary J. Drummond, Q.C., have been nominated for election to Baytex’s Board of Directors at the upcoming annual general meeting on May 27, 2003. Mr. Chwyl is a petroleum engineer and brings with him over 30 years of senior management and board experience in the oil and gas industry, including serving as President and CEO of Tarragon Oil and Gas Limited from 1989 to 1998. Mr. Drummond has a distinguished career in the energy business, including serving as President and CEO of Direct Energy Marketing Limited, a subsidiary of Centrica plc., until the end of 2002. These gentlemen will add invaluable industry and business experience to the Company’s Board.

Outlook

Baytex is planning for an exploration and development capital budget of $160 million for 2003. A cold winter and an extended spring-breakup period have combined to affect the timing of drilling and tying in wells, which will likely curtail production targets for the year. The Company is now projecting for production to average between 37,000 boe/d and 39,000 boe/d in 2003. The financial position of Baytex has never been stronger. Without any significant acquisitions, cash flow in the second half of 2003 is anticipated to exceed capital spending and Baytex will have a substantial amount of cash on deposit. The Company’s credit facilities, recently approved at $147 million, are expected to remain totally undrawn during 2003. The Company will prudently execute its investment plans and will continue to evaluate all available alternatives to ensure that shareholder returns are maximized.

Management’s Discussion and Analysis

Management’s discussion and analysis (“MD&A”) should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended March 31, 2003 and 2002 and the audited consolidated financial statements and MD&A for the year ended December 31, 2002. Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Baytex evaluates performance based on net income and cash flow from operations. Cash flow from operations represents cash generated from operating activities before changes in non-cash working capital, deferred charges and other assets and deferred credits. The Company considers it a key measure as it demonstrates the ability of the business to generate the cash flow necessary to fund future growth through capital investment and to repay debt.

Sales Volumes For the first three months of 2003, light oil sales volumes decreased by 22% to 2,969 bbl/d from 3,818 bbl/d for the same period a year ago due to property sales during 2002. Heavy oil sales volumes during the first quarter of 2003 decreased 5% to 21,788 bbl/d from 22,838 bbl/d for the same period last year. This decrease is due to the 134,100 barrels of heavy oil production in transit at the end of the quarter. Natural gas sales volumes were consistent at 74.0 mmcf/d for the first quarter of 2003 compared to 73.7 mmcf/d for the same period last year.

Revenue

	Three Months ended March 31
	2003				2002
	$000s		$/Unit		$000s	$/Unit
Oil Revenue (barrels)
Light oil	12,132		45.41		9,476	27.58
Heavy oil	61,720		31.48		44,359	21.58
Derivative contracts gain (loss)	(13,581	)	(6.10	)	2,444	1.02
Total oil revenue	60,271		27.05		56,279	23.46

Natural gas revenue (mcf)	46,776		7.02		21,159	3.19
Derivative contracts gain	—		—		1,692	0.25
Total natural gas revenue	46,776		7.02		22,851	3.44

Total Revenue (boe @ 6:1)	107,047		32.07		79,130	22.57

Revenue from light oil for the first quarter of 2003 increased 28% from the corresponding period a year ago due to a 65% increase in wellhead prices offset by a 22% decrease in sales volumes. Revenue from heavy oil increased 39% due to a 46% increase in wellhead prices offset by a 5% decline in sales volumes. Natural gas revenue increased 121% as wellhead prices increased by 120%.

Royalties Total royalties increased 89% to $22.2 million for the three months ended March 31, 2003 from $11.8 million for the same period last year. Total royalties for the first quarter of 2003 increased to 18.4% of sales compared to 15.7% of sales for the same period in 2002 due to higher product prices and accompanying higher royalty rates. Royalties as a percentage of sales by product were 18.7% for light oil, 14.7% for heavy oil and 23.3% for natural gas in the first quarter of 2003 compared to 17.0%, 12.7% and 21.6%, respectively, for the corresponding quarter last year.

Operating Expenses Operating expenses for the first quarter of 2003 increased 8% to $19.7 million from $18.3 million for the first quarter of 2002. Operating expenses were $5.91 per boe for the first three months of 2003 compared to $5.21 a year ago. The increase is attributable to higher natural gas and propane fuel costs and generally higher field costs due to harsh operating conditions during a cold winter. For the first quarter of 2003, operating expenses were $4.40 per barrel of light oil, $7.21 per barrel of heavy oil and $0.66 per mcf of natural gas. Operating expenses by product for the same period last year were $6.55, $5.91 and $0.60, respectively.

General and Administrative Expenses General and administrative expenses for the first three months of 2003 were consistent with the prior year at $1.6 million. On a per unit basis, these expenses increased from $0.45 per boe in 2002 to $0.48 per boe in 2003. In accordance with the full cost accounting policy, $1.6 million of expenses relating to exploration and development activities were capitalized in the first quarters of 2003 and 2002.

Interest Expense Interest expense increased to $6.5 million for the first quarter of 2003 from $5.6 million a year ago. The increase is due to the termination of interest rate swap arrangements in August 2002.

Depletion and Depreciation The provision for depletion and depreciation decreased to $25.2 million for the first three months of 2003 compared to $26.0 million for the same quarter last year. On a per unit basis, the current period provision was $7.55 per boe compared to $7.42 per boe in the same period last year.

Site Restoration Costs Site restoration costs for the first quarter of 2003 decreased to $0.6 million from $0.8 million for the same quarter last year. On a per unit basis, the provision for the first quarter of 2003 was $0.17 per boe compared to $0.23 per boe for the corresponding quarter a year ago.

Foreign Exchange The foreign exchange gain in the first quarter of 2003 was $22.8 million compared to a $0.2 million loss in the prior year. The 2003 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.6806 at March 31, 2003 compared to 0.6331 at December 31, 2002. The 2002 loss is based on the translation of the U.S. dollar denominated long-term debt at 0.6275 at March 31, 2002 compared to 0.6279 at December 31, 2001.

Income Taxes Current tax expenses were $2.6 million for the first quarter of 2003 compared to $2.0 million for the same quarter of 2002. The current tax expenses are comprised of $2.2 million of Saskatchewan Capital Tax and $0.4 million of Large Corporation Tax compared to $1.6 million and $0.4 million, respectively, for the same period in 2002.

Liquidity and Capital Resources At March 31, 2003, total net debt (including working capital) was $210.3 million compared to $383.7 million at the end of the first quarter of 2002 and $362.8 million at December 31, 2002. The decrease in the net debt from December 31, 2002 is due to the sale of properties and the changes in working capital at March 31, 2003.

On May 5, 2003, the Company redeemed the US$57 million Senior Secured Term Notes at principal plus US$4.4 million of yield maintenance payment. The Company’s bank facilities are at $147 million subsequent to the asset sale and the note redemption and are totally undrawn.

Capital Expenditures. Total exploration and development expenditures increased to $61.6 million for the first quarter of 2003 compared to $39.5 million for the same period a year ago. The Company’s total capital expenditures for these periods are summarized as follows:

	Three Months ended March 31
($thousands)	2003		2002
Land	4,895		2,233
Seismic	2,829		2,030
Drilling and completions	43,162		25,709
Equipment	8,803		7,605
Other	1,905		1,949
Total exploration and development	61,594		39,526
Property acquisitions	54		690
Property dispositions	(135,004	)	(47,053	)
Net capital expenditures	(73,356	)	(6,837	)

Conference Call

A conference call has been scheduled for Wednesday, May 14, 2003 at 2:00 p.m. Calgary time (4:00 p.m. eastern time) to discuss Baytex’s 2003 first quarter operating and financial results. Participants from the Company will include Dale Shwed, President and CEO and Ray Chan, Senior Vice-President and CFO. A question and answer period will follow the management presentation. To participate in the conference call, please contact the Conference Operator at 1-800-440-1782 ten minutes prior to the call.

The replay will be available one hour after the conclusion of the conference call and will be accessible until Wednesday, May 28, 2003. Callers may dial 1-800-558-5253 and enter Access Code #21143029. The conference call will be archived on Baytex’s website at www.baytex.ab.ca.

Annual Meeting

Baytex Energy’s Annual Meeting of Shareholders will be held on Tuesday, May 27, 2003 at 3:00 p.m. (Mountain Daylight Time) in the Alberta Room of the Fairmont Palliser Hotel, 133 – 9^th Ave. S.W., Calgary, Alberta.

Forward-Looking Statements

Certain statements in this press release are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this press release contains forward-looking statements relating to Management’s approach to operations, expectations relating to the number of wells, amount and timing of capital projects, foreign exchange rates, interest rates, worldwide and industry production, prices of oil and gas, heavy oil differentials, company production, cash flow and debt levels. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the ability to produce and transport crude oil and natural gas to markets; the result of exploration and development drilling and related activities; fluctuation in foreign currency exchange rates; the imprecision of reserve estimates; the ability of suppliers to meet commitments; actions by governmental authorities including increases in taxes; decisions or approvals of administrative tribunals; change in environmental and other regulations; risks associated with oil and gas operations; the weather in the Company’s areas of operations; and other factors, many of which are beyond the control of the Company. There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast.

Baytex is an intermediate oil and gas exploration and production company whose shares are traded on The Toronto Stock Exchange under the trading symbol “BTE”.

Financial statements for the period ended March 31, 2003 are attached.

FOR DETAILED INFORMATION, PLEASE CONTACT:

Dale Shwed, President and C.E.O.

Telephone: (403) 750-1241

Ray Chan, Senior Vice-President and C.F.O.

Telephone: (403) 267-0715

Website: www.baytex.ab.ca

Baytex Energy Ltd.

Consolidated Balance Sheets

(Unaudited - thousands)

	March 31, 2003			December 31, 2002
Assets
Current assets
Cash and short-term investments (note 6)	$	142,447		$	4,098
Accounts receivable	57,698			52,667
Crude oil inventory (note 2)	3,267			—
	203,412			56,765

Deferred charges and other assets	8,367			8,679
Petroleum and natural gas properties	833,167			932,316
	$	1,044,946		$	997,760

Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	109,552		$	92,563

Long-term debt (note 3)	304,145			326,977
Deferred credits	11,056			12,181
Provision for future site restoration costs	22,134			21,950
Future income taxes	202,953			184,402
	649,840			638,073

Shareholders’ Equity
Share capital (note 4)	400,652			398,176
Deficit	(5,546		)	(38,489		)
	395,106			359,687

	$	1,044,946		$	997,760

See accompanying notes to the consolidated financial statements.

Baytex Energy Ltd.

Consolidated Statements of Operations and Deficit

(Unaudited - thousands, except per share data)

	Three Months Ended March 31,
	2003			2002
Revenue
Petroleum and natural gas sales	$	107,047		$	79,130
Royalties	(22,241		)	(11,782		)
	84,806			67,348

Expenses
Operating	19,732			18,271
General and administrative	1,600			1,587
Interest	6,457			5,630
Foreign exchange (gain) loss	(22,832		)	186
Depletion and depreciation	25,219			26,002
Site restoration costs	566			796
	30,742			52,472

Income before income taxes	54,064			14,876

Income taxes
Current	2,570			1,995
Future	18,551			5,577
	21,121			7,572

Net income	32,943			7,304

Deficit, beginning of period	(38,489		)	(75,954		)

Accounting policy change for foreign exchange	—			(7,671		)

Deficit, beginning of period, as restated	(38,489		)	(83,625		)

Deficit, end of period	$	(5,546	)	$	(76,321	)

Net income per share
Basic	$	0.62		$	0.14
Diluted	$	0.61		$	0.14

See accompanying notes to the consolidated financial statements.

Baytex Energy Ltd.

Consolidated Statements of Cash Flows

(Unaudited - thousands)

	Three Months Ended March 31,
	2003			2002
Cash provided by (used in):

Operating activities
Net income	$	32,943		$	7,304
Items not affecting cash:
Site restoration costs	566			796
Amortization of deferred charges	260			260
Foreign exchange (gain) loss	(22,832		)	186
Depletion and depreciation	25,219			26,002
Future income taxes	18,551			5,577
Cash flow from operations	54,707			40,125
Change in non-cash working capital	(22,922		)	(15,318		)
Decrease in deferred charges and other assets	52			—
Decrease in deferred credits	—			(4,609		)
	31,837			20,198

Financing activities
Decrease in bank loan	—			(51,679		)
Decrease in deferred credits	(1,125		)	—
Issue of shares (net of issue expenses)	2,668			105
	1,543			(51,574		)

Investing activities
Petroleum and natural gas property expenditures	(61,648		)	(40,216		)
Disposal of petroleum and natural gas properties	135,004			47,053
Properties held for sale	—			(46,895		)
Change in non-cash working capital	31,613			71,434
	104,969			31,376

Change in cash and short-term investments	138,349			—

Cash and short-term investments, beginning of period	4,098			—

Cash and short-term investments, end of period	$	142,447		$	—

See accompanying notes to the consolidated financial statements.

Notes to the Consolidated Financial Statements

Three Months Ended March 31, 2003 and 2002

(Unaudited)

1. Accounting Policies

The interim consolidated financial statements of Baytex Energy Ltd. (the “Company”) are presented in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements of the Company as at December 31, 2002. The interim consolidated financial statements contain disclosures, which are supplemental to the Company’s annual consolidated financial statements. Certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements, have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements and notes thereto for the year ended December 31, 2002.

2. Crude Oil Inventory

Inventories of crude oil, consisting of production in transit in pipelines at the balance sheet date pursuant to a long-term crude oil supply agreement, are valued at the lower of cost or net realizable value.

3. Long-term Debt

(thousands)	March 31, 2003		December 31, 2002

Senior secured term notes (US$57,000,000)	$	83,750	$	90,037
Senior subordinated term notes (US$150,000,000)	220,395		236,940
	$	304,145	$	326,977

Interest Expense

The Company has incurred interest expense on its outstanding debt as follows:

	Three Months Ended March 31
	2003		2002
Bank loan	$	31	$	162
Amortization of deferred charge	260		260
Long-term debt	6,166		5,208
Total interest	$	6,457	$	5,630

4. Share Capital

The Company has an unlimited number of common shares in its authorized share capital.

Issued and Outstanding:

Common shares – (thousands)

	# of shares	Amount
Balance – January 1, 2003	52,819	$	398,176
Flow-though shares issued	103	810
Future tax related to flow-through shares	—	(192		)
Exercise of stock options	481	1,858
Balance – March 31, 2003	53,403	$	400,652

In January 2003, the Company issued 103,050 flow-through common shares at a price of $7.86 per share.

Stock options – (thousands)	# of options		Weighted average exercise price
Balance – January 1, 2003	5,126		$	6.98
Granted	79		$	8.63
Exercised	(481	)	$	3.86
Cancelled	(66	)	$	5.41
Balance – March 31, 2003	4,658		$	7.35
Exercisable – March 31, 2003	1,517		$	8.35

The Company accounts for its stock options using intrinsic values. On this basis, compensation costs are not required to be recognized in the financial statements for stock options granted at market value. Had compensation costs for the Company’s stock option plan been determined based on the fair-value method at the dates of grants under the plan after January 1, 2002, the Company’s pro-forma net income for the three months ended March 31, 2003 would have been reduced by $0.5 million (2002 - $4,300) and basic net income per share would be $0.61 (2002 - $0.14) and diluted net income per share would be $0.60 (2002 - $0.14). The weighted average fair market value of options granted during the three months ended March 31, 2003 was $3.99 per option (2002 – $2.73 per option). The fair value of the stock options granted during the three months ended March 31, 2003 is estimated on the grant date using the Black-Scholes option-pricing model using the following assumptions: risk free interest rate of 4.5%; expected life of 4 years; and expected volatility of 54%.

5. Supplemental Cash Flow Information

	Three Months Ended March 31
(thousands)	2003		2002
Interest paid	$	13,939	$	12,338
Income taxes paid	$	6,686	$	334

6. Subsequent Event

Utilizing the cash proceeds from the sale of properties, on May 5, 2003, the Company redeemed the US$57 million senior secured term notes at principal plus US$4.4 million of yield maintenance payment. The Company’s bank facilities are at $147 million subsequent to the note redemption.

7. Comparative Figures

Certain comparative figures have been reclassified to conform to the current period’s presentation.