Baytex Announces Second Quarter 2012 Results

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2012) - Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) is pleased to announce its operating and financial results for the three months and six months ended June 30, 2012 (all amounts are in Canadian dollars unless otherwise noted).

Summary

• Produced 53,073 boe/d (86% oil and NGL) in Q2/2012, an increase of 11% over Q2/2011;
  
  
• Generated funds from operations ("FFO") of $124.7 million ($1.04 per basic share) in Q2/2012, a decrease of 10% from Q2/2011;
  
  
• Generated net income of $157.3 million ($1.32 per basic share) in Q2/2012, an increase of 47% over Q2/2011;
  
  
• Completed the sale of non-operated assets in North Dakota for net proceeds of $313.8 million (US$312 million), realizing a pre-tax gain of $175.4 million ($105.2 million net of current and deferred income tax);
  
  
• Maintained a conservative cash payout ratio in Q2/2012 of 42% net of dividend reinvestment plan ("DRIP") participation (63% before DRIP); and
  
  
• Subsequent to the end of the second quarter, issued $300 million of 6.625% Series C senior unsecured debentures due July 19, 2022 at par and called $150 million of 9.15% Series A senior unsecured debentures due 2016 for redemption.
  
  

		Three Months Ended						Six Months Ended
		June 30, 2012		March 31, 2012		June 30, 2011		June 30, 2012		June 30, 2011
FINANCIAL (thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales		284,248		343,355		336,899		627,603		627,214
Funds from operations (1)		124,692		141,736		138,233		266,428		247,703
	Per share - basic	1.04		1.20		1.20		2.24		2.15
	Per share - diluted	1.03		1.18		1.17		2.20		2.10
Cash dividends declared (2)		51,943		55,559		52,763		107,502		104,765
Cash dividends declared per share		0.66		0.66		0.60		1.32		1.20
Net income		157,280		42,958		106,863		200,238		107,813
	Per share - basic	1.32		0.36		0.92		1.68		0.94
	Per share - diluted	1.30		0.36		0.90		1.66		0.91
Exploration and development		102,895		135,918		108,453		238,813		195,467
Property acquisitions		10,173		2,336		(185	)	12,509		37,333
Corporate acquisition		-		-		1,325		-		118,671
Proceeds from divestitures		(313,834	)	(3,568	)	-		(317,402	)	-
Total oil and natural gas capital expenditures		(200,766	)	134,686		109,593		(66,080	)	351,471
Bank loan		396,207		326,889		315,073		396,207		315,073
Long-term debt		302,865		299,865		294,645		302,865		294,645
Working capital (surplus) deficiency		(261,153	)	63,988		72,621		(261,153	)	72,621
Total monetary debt (3)		437,919		690,742		682,339		437,919		682,339

		Three Months Ended			Six Months Ended
		June 30, 2012	March 31, 2012	June 30, 2011	June 30, 2012	June 30, 2011
OPERATING
Daily production
	Light oil and NGL (bbl/d)	7,090	7,565	6,055	7,327	6,329
	Heavy oil (bbl/d)	38,579	38,353	33,839	38,467	32,821
	Total oil and NGL (bbl/d)	45,669	45,918	39,894	45,794	39,150
	Natural gas (mmcf/d)	44.4	45.1	47.8	44.8	49.4
	Oil equivalent (boe/d @ 6:1) (4)	53,073	53,433	47,853	53,254	47,380
Average prices (before hedging)
	WTI oil (US$/bbl)	93.49	102.93	102.56	98.20	98.33
	Edmonton par oil ($/bbl)	84.42	92.81	102.63	88.55	95.57
	BTE light oil and NGL ($/bbl)	71.62	81.99	89.11	76.97	82.14
	BTE heavy oil ($/bbl) (5)	57.42	65.89	71.02	61.65	65.60
	BTE total oil and NGL ($/bbl)	59.63	68.54	73.78	64.10	68.26
	BTE natural gas ($/mcf)	2.00	2.46	4.36	2.23	4.27
	BTE oil equivalent ($/boe)	52.97	60.98	65.84	57.00	60.89
	CAD/USD noon rate at period end	1.0191	0.9991	0.9643	1.0191	0.9643
	CAD/USD average rate for period	1.0102	1.0003	0.9676	1.0052	0.9767
COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
	High	$ 53.61	$ 59.40	$ 58.76	59.40	$ 58.76
	Low	$ 38.54	$ 50.52	$ 47.59	38.54	$ 46.00
	Close	$ 42.89	$ 51.79	$ 52.72	42.89	$ 52.72
Volume traded (thousands)		34,162	23,378	22,857	57,540	57,055
NYSE
Share price (US$)
	High	$ 54.44	$ 59.50	$ 61.95	$ 59.50	$ 61.95
	Low	$ 37.40	$ 50.49	$ 48.63	$ 37.40	$ 46.25
	Close	$ 42.11	$ 51.86	$ 54.44	$ 42.11	$ 54.44
Volume traded (thousands)		8,257	4,488	9,851	12,745	18,035
Common shares outstanding (thousands)		119,914	118,905	116,004	119,914	116,004

Notes:
(1)	Funds from operations is a non-GAAP measure that represents cash generated from operating activities adjusted for finance costs, changes in non-cash operating working capital and other operating items. Baytex's funds from operations may not be comparable to other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends and capital investments. For a reconciliation of funds from operations to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three months and six months ended June 30, 2012.
(2)	Cash dividends declared are net of DRIP participation.
(3)	Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred income tax assets or liabilities and unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loans.
(4)	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. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(5)	Heavy oil prices are net of blending costs.

Executive Management Appointment

As previously announced, the Board of Directors has approved the appointment of Mr. James L. Bowzer as President, Chief Executive Officer and a Director of Baytex effective September 4, 2012.

Mr. Bowzer most recently served as Vice President, North America Production Operations, for Marathon Oil Corporation ("Marathon") in Houston, Texas. He has over 30 years of global experience leading large organizations, directing new projects and developing successful leaders. Since 2008, he has been responsible for Marathon's expansive domestic portfolio which includes unconventional plays in the Bakken, Niobrara and Anadarko Woodford in the United States and heavy oil in Canada, and conventional plays located in Alaska, Colorado, Louisiana, Oklahoma, Texas and Wyoming. From 2006 to 2008, Mr. Bowzer was Marathon's Regional Vice President, International Production, covering a diverse mix of significant businesses, including operations in Norway, the United Kingdom, Ireland and Africa. Prior thereto, he reported directly to the CEO of Marathon as General Manager, Strategic Planning, responsible for strategy, financial and economic valuation and business development activities. Mr. Bowzer has held a number of leadership and technical positions at Marathon in its various domestic and international operations.

Mr. Bowzer has a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming and completed the Advanced Management Program at the Graduate School of Business at Indiana University. He has served on the board of directors of many industry and professional associations.

Operations Review

Production continued to perform in accordance with our operating budget, averaging 53,073 boe/d (86% oil and NGL) during Q2/2012. This production rate represents an increase of 11% over Q2/2011, which growth is essentially attributable to our exploration and development program. The current quarter production also compares favourably to the 53,433 boe/d average in Q1/2012, after accounting for the approximately 440 boe/d impact on the quarter average from the North Dakota disposition, and the usual production curtailment associated with spring break-up field conditions. Our 2012 annual production guidance remains at 53,500 to 54,500 boe/d and our 2012 exploration and development capital budget remains at $400 million. Our production mix for 2012 is forecast to be 73% heavy oil, 14% light oil and NGL and 13% natural gas.

Capital expenditures for exploration and development activities totaled $102.9 million for Q2/2012. During the quarter, Baytex participated in the drilling of 38 (22.9 net) wells with a 100% success rate.

Wells Drilled in Q2/2012
		Crude Oil				Natural Gas		Stratigraphic and Service		Dry and Abandoned		Total
		Primary		Thermal
		Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Heavy oil
	Lloydminster area	10	6.1	-	-	-	-	-	-	-	-	10	6.1
	Peace River area	11	11.0	-	-	-	-	-	-	-	-	11	11.0
		21	17.1	-	-	-	-	-	-	-	-	21	17.1
Light oil, NGL and natural gas
	Western Canada	3	2.1	-	-	-	-	-	-	-	-	3	2.1
	North Dakota	14	3.7	-	-	-	-	-	-	-	-	14	3.7
		17	5.8	-	-	-	-	-	-	-	-	17	5.8
Total		38	22.9	-	-	-	-	-	-	-	-	38	22.9

Heavy Oil

In Q2/2012, heavy oil production averaged 38,579 bbl/d, an increase of 14% over Q2/2011 and 1% over Q1/2012. During the current quarter, we drilled 21 (17.1 net) oil wells on our heavy oil properties with a success rate of 100%.

Production from our Peace River area properties averaged approximately 19,300 bbl/d in Q2/2012, an increase of 4% over Q1/2012 and 34% over Q2/2011. In this quarter, we drilled 11 (11.0 net) cold horizontal producers in the Seal area (encompassing a total of 139 laterals). During the quarter, 10 Seal wells established average 30-day peak production rates of approximately 575 bbl/d and one Reno well established a 30-day peak production rate of 300 bbl/d. We plan to drill approximately 22 cold horizontal wells in the Peace River area in the remainder of the year.

In the Cliffdale area of Seal, successful operations continued at our 10-well commercial cyclic steam stimulation ("CSS") module, with production during the second quarter averaging 440 bbl/d, consistent with project design parameters. During Q2/2012, two wells received steam and four wells commenced post-steam flowback operations. First-cycle peak rates of 230 bbl/d and second-cycle peak rates of 325 bbl/d were observed. Thermal flowback operations on the original pilot well generated a fourth-cycle peak rate of 390 bbl/d with a significant increase in sustained average daily production rates. The final five CSS wells that were completed during the first quarter of 2012 continued their initial cold-production phase, a process designed to generate reservoir voidage prior to first steam. First-cycle steaming for these remaining five wells will commence in the second half of 2012. To date, the Cliffdale project has demonstrated a cumulative steam-oil-ratio of less than 1.9 barrels of steam per barrel of oil. Subject to receipt of regulatory approvals, we plan to initiate development of a new 15-well commercial CSS module during Q4/2012.

Second quarter drilling included five (5.0 net) horizontal wells and five (1.1 net) vertical wells in our Lloydminster heavy oil area. This area is characterized by stacked pay which has lead to successful exploitation of multiple horizons. Our Lloydminster heavy oil projects generate consistent, repeatable results with horizontal wells typically producing 30-day peak rates of approximately 70-80 bbl/d and vertical wells typically producing 30-day peak rates of approximately 30-40 bbl/d. We expect to drill approximately 11 horizontal wells and 18 vertical wells in this area in the second half of 2012.

Light Oil & Natural Gas

During Q2/2012, light oil, NGL and natural gas production averaged 14,494 boe/d, which was comprised of 7,090 bbl/d of light oil and NGL and 44.4 mmcf/d of natural gas. Compared to Q2/2011, light oil and NGL production increased 17% and natural gas production decreased 7%. Compared to the Q1/2012, light oil and NGL production decreased 6%, reflecting the sale of the non-operated North Dakota assets, and natural gas production decreased 2%.

On May 22, 2012, Baytex completed the sale of its non-operated interests in North Dakota for cash proceeds of US$312 million, after closing adjustments. The assets included approximately 950 boe/d of Bakken light oil production (based on Q1/2012 production) and 149,700 (50,400 net) acres of land, of which approximately 24% was developed. This sale represented 45% of our North Dakota net acreage and approximately 40% of our U.S. production. These assets were not a primary focus of our U.S. Business Unit as they were non-operated and generally had a lower average working interest than our remaining lands.

In our Bakken/Three Forks play in North Dakota, we participated in the drilling of 14 (3.7 net) horizontal oil wells during Q2/2012, six of which were Baytex-operated, and the fracture-stimulation of 14 (2.7 net) wells. During the quarter, 18 Baytex-interest 1,280-acre spacing wells established average 30-day peak rates of approximately 310 bbl/d. We plan to drill approximately 12 (4.0 net) wells in North Dakota during the remainder of 2012.

During Q2/2012, Baytex entered into an agreement to acquire approximately 72,300 (50,600 net) acres (70% working interest) in Weston and Niobrara Counties, Wyoming for US$176 per net acre (total initial consideration of US$8.9 million). Baytex is in the process of permitting two horizontal wells to test the Turner formation, which produces from existing vertical wells in the area and is being developed with horizontal techniques elsewhere in the basin. Baytex will complete its obligations under this agreement by carrying the seller for a 30% working interest in these two wells, estimated to cost approximately US$4 million per well on a 100% basis.

During Q2/2012, we drilled two horizontal wells in our Viking light oil resource play in Central Alberta, with one well drilled in Q1/2012 and one well drilled in Q2/2012 establishing average 30-day peak rates of 80 bbl/d. We have five Viking wells planned for the second half of 2012.

Financial Review

We generated FFO of $125 million ($1.04 per basic share) in Q2/2012, a decrease of 10% compared to Q2/2011, and a decrease of 12% compared to Q1/2012, both due to lower realized prices for oil and natural gas. Revenue, net of royalties, were $238.2 million in Q2/2012, a 17% decrease from Q2/2011 due in part to the increase in sales volumes which were delivered to market on railways. Unlike pipelines, heavy oil transported on railways does not need to be blended with condensate. As a result, we sell an unblended barrel, the price of which does not include the cost of the blending diluent. Correspondingly, our transportation and blending expenses are 29% lower in Q2/2012 than they were in Q2/2011 as we did not have to purchase as much condensate for blending. Our sales price, net of blending cost, is enhanced by transporting heavy oil on railways, but from a reporting perspective, there is a reduction in gross revenue and a reduction in transportation and blending expenses.

The average WTI price for Q2/2012 was US$93.49, a 9% decrease from both Q2/2011 and Q1/2012. We received an average oil and NGL price of $59.63/bbl in Q2/2012 (inclusive of our physical hedging gains), down 19% from $73.78/bbl for Q2/2011 and down 13% from $68.54/bbl for Q1/2012. We received an average natural gas price of $2.00/mcf in Q2/2012, down 54% from $4.36/mcf for Q2/2011 and down 19% from $2.46/mcf for Q1/2012.

The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 24% during Q2/2012, and 22% for the first half of 2012, as compared to 17% and 21%, respectively, for the same periods in 2011. The increase in Canadian heavy crude differentials in Q2/2012, as compared to Q2/2011, was caused by operational issues at export pipelines and U.S. refineries that run Canadian heavy oil. Demand for Canadian heavy oil is expected to remain strong in the future, with additional refinery expansions in late 2012 and in 2013, together with increasing rail exports of Canadian heavy oil and increasing pipeline access to U.S. gulf coast refineries. However, sporadic refinery and export pipeline upsets, together with growing heavy oil production, increase the likelihood of continued volatility in WCS price differentials from month-to-month. Current prompt WCS differential to WTI is approximately 17%, with a forward strip suggesting approximately 24% for the second half of 2012. Over the longer term, we continue to believe that transportation solutions to allow Canadian crudes to access additional markets will proceed, and that the prices for Canadian crudes will more closely match those of worldwide quality peers.

Baytex continues to actively hedge its exposure to commodity prices and foreign exchange rates. We have established forward contracts for the balance of 2012 on approximately 43% of our WTI price exposure, 28% of our heavy oil differential exposure, 38% of our natural gas price exposure, and 32% of our exposure to currency movements between the Canadian and U.S. dollars. We have begun to secure hedging contracts on our WTI exposure for 2013. Details of all hedging contracts are contained in the notes to our interim financial statements. We continue to monitor the markets for opportunities to add to our hedge positions.

Our WCS differential hedges are primarily contracts that provide a fixed dollar differential to WTI. Based on the forward strip for WTI, our WCS contracts for 2012 translate to approximately an 18% differential to WTI. We have additional contracts for smaller volumes in place for 2013 and 2014 at an average differential of 21% to WTI. In addition to our hedging program, we are also mitigating our exposure to WCS differentials by transporting crude oil to higher value markets by railways. We are currently delivering approximately 27% of our heavy oil volumes to market by rail and expect to increase rail deliveries to approximately 35% to 40% of our heavy oil volumes by year-end. Furthermore, as part of our long-term transportation portfolio, we have entered into a transportation services agreement for a pipeline expansion that will enable us to access the U.S. gulf coast markets for approximately 12% of our heavy oil production (based on current production rates) for a 10-year period. This pipeline expansion is expected to commence service in mid-2014.

During Q2/2012, Baytex completed the previously disclosed sale of non-operated interests in North Dakota for net proceeds of $313.8 million (US$312 million), realizing a pre-tax gain of $175.4 million. Cash tax expense of $17 million has been accrued in the second quarter related to this disposition. Under U.S. income tax laws, if the proceeds of a disposition are reinvested into qualifying properties within a prescribed time frame, the tax on the gain may be deferred. In order to qualify for this potential deferral, we were required to place the sales proceeds into escrow pending the acquisition of replacement properties. Subsequent to the end of the second quarter, US$112.5 million of the sales proceeds were returned from escrow and used to reduce borrowings on our credit facilities. The balance of US$199.5 million will either be invested in replacement properties in the U.S. or remain in escrow until Q4/2012, at which time it will be released and used to reduce borrowings on our credit facilities. At this time it is not likely we will conclude a transaction to acquire qualifying replacement properties within the prescribed time frame and, therefore, the tax accrued will become payable as installments in the third and fourth quarters of 2012.

We ended the quarter with total monetary debt of $438 million representing a debt-to-FFO ratio of 0.8 times, based on FFO over the trailing twelve-month period. In July 2012, we issued $300 million of 6.625% Series C senior unsecured debentures due July 19, 2022 at par. A portion of the net proceeds of this issue will be used to redeem $150 million of 9.15% Series A senior unsecured debentures, which have been called for redemption on August 26, 2012 at 104.575% of principal amount, with the remaining proceeds used to reduce borrowings on our credit facilities. Pro forma the debenture issue in July and the debenture redemption in August, and assuming the repatriation of all of the North Dakota sales proceeds (net of tax), the only outstanding borrowings Baytex would have are the US$150 million Series B debentures due 2021 and the $300 million Series C debentures due 2022. Our entire $700 million credit facilities would be undrawn. This significant level of available liquidity, combined with the long term maturities of our outstanding debt, will ensure that we have the financial capacity to continue to execute our growth and income business model during this volatile commodity price environment.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three months and six months ended June 30, 2012 and 2011 and related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytex.ab.ca and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to: our average production rate for 2012; our exploration and development capital expenditures for 2012; our production mix for 2012, development plans for our properties, including the number of wells to be drilled in the remainder of 2012; initial production rates from wells drilled; our Cliffdale cyclic steam stimulation project at Seal, including our assessment of the steam and flowback operations, the cumulative steam-oil ratio for the project and our plan for a second commercial module of CSS; our Lloydminster heavy oil area, including the development potential of these properties, our ability to exploit multiple horizons and estimated 30-day peak productions rates from new horizontal and vertical wells; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy oil and West Texas Intermediate; the alleviation of pipeline constraints through the addition of incremental transportation capacity; the completion of refinery turnarounds; the demand for Canadian heavy oil by U.S. refiners; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; our ability to mitigate our exposure to heavy oil price differentials by transporting our crude oil to market by railways; the volume of heavy oil to be transported to market on railways in 2012; the expected in-service date for a pipeline expansion that will enable us to access the U.S. Gulf Coast markets; the application of the proceeds from the sale of our non-operated interests in North Dakota; the amount of our undrawn credit facilities at June 30, 2012; our debt-to-FFO ratio; our pro forma financial position following the issuance of the Series C senior unsecured debentures, the redemption of the Series A senior unsecured debentures and the repatriation of the proceeds from the sale of our non-operated interests in North Dakota; our liquidity and financial capacity; and our ability to continue to execute our growth and income business model in a volatile commodity price environment. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of FFO and capital expenditures and our prevailing financial circumstances at the time.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the receipt, in a timely manner, of regulatory and other required approvals; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned that such assumptions, 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: fluctuations in market prices for petroleum and natural gas; fluctuations in foreign exchange or interest rates; general economic, market and business conditions; stock market volatility and market valuations; changes in income tax laws; industry capacity; geological, technical, drilling and processing problems and other difficulties in producing petroleum and natural gas reserves; uncertainties associated with estimating petroleum and natural gas reserves; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; risks associated with oil and gas operations; changes in royalty rates and incentive programs relating to the oil and gas industry; changes in environmental and other regulations; incorrect assessments of the value of acquisitions; failure to obtain the necessary regulatory and other approvals on the planned timelines; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in Baytex's Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2011, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

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 and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

Non-GAAP Financial Measures

Funds from operations is not a measurement based on Generally Accepted Accounting Principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Baytex's determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.

Total monetary debt is not a measurement based on GAAP in Canada. Baytex defines total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred income tax assets or liabilities and unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loans. Baytex believes that this measure assists in providing a more complete understanding of its cash liabilities.