Baytex Reports Q3 2015 Results

CALGARY, ALBERTA--(Marketwired - Nov. 6, 2015) - Baytex Energy Corp. ("Baytex") (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three and nine months ended September 30, 2015 (all amounts are in Canadian dollars unless otherwise noted).

"During the third quarter, we continued to position our company to withstand the current low commodity price environment. Consistent with our revised plans for 2015, we moved forward with a slower pace of development in the Eagle Ford and suspended heavy oil drilling in Canada. We remained focused on cost reduction initiatives across all of our operations and maintaining strong levels of financial liquidity. We have built an exceptional asset base focused on crude oil and liquids with a significant inventory of development prospects. We are well positioned for success as oil prices improve," commented James Bowzer, President and Chief Executive Officer.

Highlights

• Generated production of 82,170 boe/d (81% oil and NGL) in Q3/2015;
• Delivered funds from operations ("FFO") of $105.1 million ($0.51 per share) in Q3/2015;
• Realized an operating netback (sales price less royalties, production and operating expenses, and transportation expenses) in Q3/2015 of $15.57/boe ($18.90/boe including financial derivative gains);
• Produced approximately 39,000 boe/d in the Eagle Ford with 14 wells brought onstream during the quarter generating average 30-day initial production rates of approximately 1,350 boe/d;
• Realized drilling cost savings in the Eagle Ford of greater than 10% for the second consecutive quarter (an overall reduction of 27% compared to 2014); and
• Maintained strong levels of financial liquidity with the suspension of our dividend and approximately $1.05 billion in undrawn capacity on our credit facilities.

			Three Months Ended									Nine Months Ended
			September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
FINANCIAL (thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales		$	268,625		$	345,432		$	634,415		$	899,672		$	1,496,627
Funds from operations (1)			105,052			158,049			297,964			423,322			634,277
	Per share - basic		0.51			0.77			1.79			2.18			4.44
	Per share - diluted		0.51			0.77			1.78			2.18			4.40
Cash dividends declared (2)			17,248			37,908			89,771			96,624			228,610
Dividends declared per share			0.20			0.30			0.72			0.80			2.06
Net income (loss)			(517,856	)		(26,955	)		144,369			(720,727	)		229,009
	Per share - basic		(2.49	)		(0.13	)		0.87			(3.71	)		1.60
	Per share - diluted		(2.49	)		(0.13	)		0.86			(3.71	)		1.59
Exploration and development			126,804			106,010			230,032			380,243			551,373
Acquisitions, net of divestitures			(498	)		1,170			(341,908	)		2,222			2,580,819
Total oil and natural gas capital expenditures		$	126,306		$	107,180		$	(111,876	)	$	382,465		$	3,132,192
Bank loan(3)		$	208,195		$	192,255		$	624,067		$	208,195		$	624,067
Long-term debt(3)			1,581,002			1,493,013			1,380,811			1,581,002			1,380,811
Working capital deficiency			160,539			137,243			250,939			160,539			250,939
Total monetary debt (4)		$	1,949,736		$	1,822,511		$	2,255,817		$	1,949,736		$	2,255,817

		Three Months Ended			Nine Months Ended
		September 30, 2015	June 30, 2015	September 30, 2014	September 30, 2015	September 30, 2014
OPERATING
Daily production
	Heavy oil (bbl/d)	33,639	35,397	45,500	36,067	45,641
	Light oil and condensate (bbl/d)	24,712	25,899	28,124	26,210	14,569
	NGL (bbl/d)	8,507	8,232	6,629	8,322	3,714
	Total oil and NGL (bbl/d)	66,858	69,528	80,253	70,599	63,924
	Natural gas (mcf/d)	91,869	91,456	83,300	91,448	58,766
	Oil equivalent (boe/d @ 6:1) (5)	82,170	84,770	94,137	85,840	73,718
Benchmark prices
	WTI oil (US$/bbl)	46.43	57.94	97.17	51.00	99.61
	WCS heavy oil (US$/bbl)	33.13	46.35	76.99	37.80	78.50
	Edmonton par oil ($/bbl)	56.22	67.72	98.65	58.63	101.83
	LLS oil (US$/bbl)	49.79	62.38	101.93	54.24	104.55
Baytex average prices (before hedging)
	Heavy oil ($/bbl) (6)	30.90	44.59	73.99	34.54	74.84
	Light oil and condensate ($/bbl)	55.46	65.11	99.65	57.54	100.19
	NGL ($/bbl)	15.35	15.78	36.77	16.79	40.59
	Total oil and NGL ($/bbl)	38.00	48.82	79.91	42.39	78.62
	Natural gas ($/mcf)	3.28	3.06	4.43	3.19	4.73
	Oil equivalent ($/boe)	34.59	43.34	72.04	37.10	71.97
CAD/USD noon rate at period end		1.3394	1.2474	1.1208	1.3394	1.1208
CAD/USD average rate for period		1.3094	1.2294	1.0893	1.2631	1.0940
COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
High		19.50	24.14	49.49	24.87	49.88
Low		3.92	19.24	41.73	3.92	38.90
Close		4.27	19.43	42.35	4.27	42.35
Volume traded (thousands)		165,674	80,572	40,645	368,426	140,378
NYSE
Share price (US$)
High		15.51	20.10	46.46	20.10	46.46
Low		2.92	15.42	37.54	2.92	35.34
Close		3.20	15.58	37.86	3.20	37.86
Volume traded (thousands)		109,902	44,497	5,212	178,612	12,915
Common shares outstanding (thousands)		210,225	206,193	166,709	210,225	166,709

Notes:

1. 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. We define funds from operations as cash flow 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 capital investments and future dividends. 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 and nine months ended September 30, 2015.
2. Cash dividends declared are net of participation in our dividend reinvestment plan.
3. Principal amount of instruments.
4. 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 current financial derivatives)) and the principal amount of both the long-term debt and the bank loan.
5. 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.
6. Heavy oil prices exclude condensate blending.

Operations Review

During the third quarter, we continued to position our company to withstand the current low commodity price environment. Drilling activity was reduced in the Eagle Ford and heavy oil drilling in Canada was suspended. We remained focused during the quarter on cost reduction initiatives across all of our operations, including drilling and completions, production and operating expenses and general and administrative expenses. Drilling costs have been reduced by approximately 27% in the Eagle Ford as compared to 2014, and both operating costs and general and administrative expenses have been reduced by approximately 15% versus budget.

Production averaged 82,170 boe/d (81% oil and NGL) in Q3/2015 as compared to 84,770 boe/d in Q2/2015. The reduction in volumes is largely attributable to reduced activity levels in Canada. Capital expenditures for exploration and development activities totaled $126.8 million in Q3/2015 with $93.3 million spent in the U.S. and $33.5 million spent in Canada. During Q3/2015, we participated in the drilling of 57 (29.5 net) wells with a 100% success rate.

With the previously announced reduction in exploration and development activities in Canada, we anticipate our full year capital expenditures will be toward the lower end of our guidance of $500 to $575 million. Similarly, we anticipate our full year 2015 production will be toward the lower end of our guidance of 84,000 to 86,000 boe/d. We are in the process of setting our 2016 capital budget, the details of which are expected to be released in December following approval by our Board of Directors.

Wells Drilled - Three Months Ended September 30, 2015

						Stratigraphic		Dry and
		Crude Oil		Natural Gas		and Service		Abandoned		Total
		Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Heavy oil
	Lloydminster	17	12.3	-	-	1	1.0	-	-	18	13.3
	Peace River	5	5.0	-	-	-	-	-	-	5	5.0
		22	17.3	-	-	1	1.0	-	-	23	18.3
Light oil and natural gas
	Eagle Ford	7	2.2	24	6.7	1	0.3	-	-	32	9.2
	Western Canada	-	-	2	2.0	-	-	-	-	2	2.0
		7	2.2	26	8.7	1	0.3	-	-	34	11.2
Total		29	19.5	26	8.7	2	1.3	-	-	57	29.5

Wells Drilled - Nine Months Ended September 30, 2015

						Stratigraphic		Dry and
		Crude Oil		Natural Gas		and Service		Abandoned		Total
		Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Heavy oil
	Lloydminster	26	17.4	-	-	1	1.0	-	-	27	18.4
	Peace River	6	6.0	-	-	5	5.0	-	-	11	11.0
		32	23.4	-	-	6	6.0	-	-	38	29.4
Light oil and natural gas
	Eagle Ford	54	12.9	92	24.6	1	0.3	2	0.6	149	38.4
	Western Canada	-	-	2	2.0	-	-	-	-	2	2.0
		54	12.9	94	26.6	1	0.3	2	0.6	151	40.4
Total		86	36.3	94	26.6	7	6.3	2	0.6	189	69.8

U.S. Operations

Production in the Eagle Ford averaged 38,941 boe/d (78% oil and NGL) during Q3/2015, as compared to 39,548 boe/d in Q2/2015 and 41,076 boe/d in Q1/2015. Capital expenditures in the Eagle Ford in Q3/2015 totaled $93.3 million, down from $98.3 million in Q2/2015 and $126.2 million in Q1/2015. We continue to work with our partner on cost reductions. To-date, we have achieved an approximate 27% reduction in well costs - with wells now being drilled, completed and equipped for approximately US$6.0 million, as compared to US$8.2 million in 2014.

In response to the low crude oil price environment, we have moderated our pace of development throughout 2015. The number of drilling rigs is consistent with our reduced development plan with approximately six rigs currently drilling on our acreage, as compared to 12 rigs in late 2014. As at September 30, 2015, we had 87 (24.2 net) wells waiting on completion. We currently have three frac crews working on completing wells.

In Q3/2015, we participated in the drilling of 32 (9.2 net) wells and commenced production from 31 (6.5 net) wells. Of the 31 wells that commenced production during Q3/2015, 14 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,350 boe/d.

In addition to targeting the Lower Eagle Ford formation, we continue to delineate the Austin Chalk formation with 45 (12.6 net) wells now on production. The wells that came on production in the Austin Chalk during Q3/2015 have established an average 30-day initial production rate of approximately 1,100 boe/d.

Additional advancements have been made to delineate the multi-zone development potential of our Sugarkane acreage. We have initiated "stack and frac" pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk. Recent production data from one pad (a total of six wells) that targeted four zones achieved 30-day initial production rates per well ranging from 700 to 1,480 boe/d. We now have thirteen multi-zone projects in various stages of execution and production.

Canadian Operations

Production in Canada averaged 43,229 boe/d (84% oil and NGL) during Q3/2015, as compared to 45,222 boe/d in Q2/2015. The reduced volumes in Canada are a result of lower drilling activity and uneconomic production that we have shut-in. At September 30, 2015, we had a total of approximately 2,400 boe/d of uneconomic production shut-in, including the Cliffdale Cyclical Steam Stimulation project, which was suspended late in the third quarter. Capital expenditures for our Canadian assets in Q3/2015 totaled $33.5 million, an increase from $7.7 million in Q2/2015.

In the third quarter, we proceeded with our 2015 budget plan in Peace River and Lloydminster, however, as commodity prices deteriorated we suspended our development activities. At Peace River, we drilled five (5.0 net) wells and at Lloydminster, we drilled 17 (12.3 net) wells. We achieved an approximate 20% reduction in well costs - with wells now being drilled, completed, and equipped for approximately $2.7 million at Peace River ($3.4 million previously) and $750,000 at Lloydminster ($950,000 previously).

Financial Review

We generated FFO of $105.1 million ($0.51 per share) in Q3/2015, compared to $158.0 million ($0.77 per share) in Q2/2015. The $52.9 million decline in FFO is largely due to a decline in commodity prices, lower realized hedging gains and lower production volumes. This was partially offset by lower costs associated with our operations, lower transportation and general and administrative expenses along with lower royalties.

We recorded a net loss in Q3/2015 of $300.7 million ($2.49 per share) compared to a net loss of $27.0 million ($0.13 per share) in Q2/2015. The net loss in the quarter is largely attributable to the non-cash impairment charge of $493.2 million ($419.0 million after-tax) related to our Eagle Ford operations. The impairment charge, which is directly attributable to the decline in commodity prices, included $210.3 million related to oil and gas properties and the remaining goodwill of $282.9 million associated with the acquisition. We have determined that no impairments are required on our Canadian operations at this time.

In Q3/2015, our realized sales price decreased as commodity prices decreased. The average price for West Texas Intermediate light oil ("WTI") decreased to US$46.43/bbl during the quarter, as compared to US$57.94/bbl in Q2/2015. This 20% decline in the benchmark index resulted in our realized price for light oil and condensate decreasing only 15% to $55.46/bbl, as our realized price benefited from the weakening Canadian dollar during the period. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, widened to US$13.30/bbl in Q3/2015, as compared to US$11.59/bbl in Q2/2015. The widening differential and lower WTI price resulted in a 29% decrease in the price of WCS. We had a corresponding 31% decrease in our realized heavy oil price to $30.90/bbl over the same period.

We generated an operating netback in Q3/2015 of $15.57/boe ($18.90/boe including financial derivatives gains). Our Canadian operations generated an operating netback of $10.68/boe while the Eagle Ford generated an operating netback of $21.01/boe. Our Eagle Ford assets are located in south Texas and are proximal to Gulf Coast crude oil markets with established transportation systems, resulting in stronger realized prices. Our light oil and condensate production in the Eagle Ford is priced primarily off a Louisiana Light Sweet crude oil benchmark which typically trades at a premium to WTI. This strong pricing, combined with low cash costs, contributed positively to our operating netback in Q3/2015.

During the quarter, we continued to focus on cost reduction initiatives across all of our operations. Production and operating expenses decreased 10% on a per boe basis as compared to Q3/2014, despite the impact of fixed costs on lower production in Canada. We are also benefiting from the Eagle Ford assets which have lower costs and comprise a larger percentage of our production. Transportation expenses in Canada have been reduced by 27% on a per boe basis as compared to Q3/2014, due to overall cost reduction initiatives, which includes the use of internal trucking and decreased fuel charges.

The table below provides a summary of our operating netbacks for the periods noted.

		Three Months Ended Sept. 30, 2015						Three Months Ended Sept. 30, 2014
($ per boe)		Canada		Eagle Ford		Total				Change
Sales Price	$	29.06	$	40.72		$34.59	$	72.04		(52	)%
Other income		0.69		-		0.36		-		100	%
Less:
Royalties		3.88		11.74		7.61		17.43		(56	)%
Production and operating expenses		12.31		7.97(1	)	10.25		11.39		(10	)%
Transportation expenses		2.88		-		1.52		2.36		(36	)%
Operating netback	$	10.68	$	21.01		$15.57	$	40.86		(61)	%
Financial derivatives gain (loss)		-		-		3.33		(0.47	)	-	%
Operating netback after financial derivatives	$	10.68	$	21.01		$ 18.90	$	40.39		(52	)%
(1) In the Eagle Ford, transportation expenses are included in production and operating expenses.

General and administrative expenses were $14.0 million in Q3/2015 as compared to $16.8 million in Q3/2014. The decrease is primarily a result of reductions to staffing levels to coincide with lower activity levels combined with a reduction in discretionary spending.

As previously announced on August 20, 2015, we suspended our monthly cash dividend following the September 15, 2015 payment. We believe this was a prudent step to minimize additional bank borrowings during this period of extremely low commodity prices. We continue to believe in returning a portion of our funds from operations to shareholders under normal operating conditions. However, based on the current forward strip, we would not generate sufficient free cash flow to pay a dividend.

Risk Management

We employ a comprehensive risk management program which is intended to reduce some of the volatility in our FFO. In Q3/2015, we realized financial derivatives gains of $25.2 million, primarily due to crude oil prices being at levels significantly below those set in our fixed price contracts, which were partially offset by the settlement of our out-of-money foreign exchange contracts.

As part of our hedging program, we also focus on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to markets by rail when economics warrant. We have no fixed investment or take or pay obligations to transport crude oil by rail and infrastructure around our core heavy oil producing regions allows for optimization between rail and pipe. In Q3/2015, approximately 16,000 bbl/d of our heavy oil volumes were delivered to market by rail, down 20% from the previous quarter as we optimize our heavy oil netbacks. For Q4/2015, we expect to deliver approximately 15,000 bbl/d of our heavy oil volumes to market by rail.

For Q4/2015, we have entered into hedges on approximately 22% of our net WTI exposure with 20% fixed at US$76.37/bbl and 2% hedged utilizing a 3-way collar structure (as described in the table below). For 2016, Baytex has entered into hedges on approximately 38% of its net WTI exposure with 15% fixed at US$63.64/bbl and 23% hedged utilizing a 3-way collar structure.

The unrealized financial derivatives gain with respect to our WTI hedges as at September 30, 2015 was $81.9 million. The following table summarizes our WTI hedges in place as at November 5, 2015.

	Q4/2015		Full-Year 2016		Full-Year 2017
Fixed Hedges
Volumes (bbl/d)		9,667		6,250	-
Hedge (%) (1)		20%		15%	-
Price (US$/bbl)	$	76.37	$	63.64	-
3-Way Option
Volumes (bbl/d)		1,000		9,500	2,000
Hedge (%) (1)		2%		23%	5%
Average Ceiling/Floor/Sold Floor (US$/bbl) (2)		$62.50/$50/$40		$60/$50/$40	$60/$50/$40
Total Hedge Volume
Volumes (bbl/d)		10,667		15,750	2,000
Hedge (%) (1)		22%		38%	5%
(1) Percentage of hedged volumes is based on the mid-point of our 2015 production guidance (excluding NGL), net of royalties.
(2) Producer 3-way option consists of a sold call, a bought put and a sold put. In a $60/$50/$40 example, Baytex receives WTI + US$10/bbl when WTI is at or below US$40/bbl; Baytex receives US$50/bbl when WTI is between US$40/bbl and US$50/bbl; Baytex receives WTI when WTI is between US$50/bbl and US$60/bbl; and Baytex receives US$60/bbl when WTI is above US$60/bbl.

Financial Liquidity

We have taken several steps to maintain strong levels of financial liquidity this year, including evaluating our level and timing of capital spending, negotiating cost savings with service providers, reducing staffing levels, completing an equity financing and suspending the monthly dividend.

Total monetary debt at September 30, 2015 was $1.95 billion, comprised of a bank loan of $208 million, long-term debt of $1.58 billion and a working capital deficiency of $161 million. The increase in total monetary debt at September 30, 2015, as compared to June 30, 2015, was primarily due to the Canadian dollar increase of our U.S. dollar denominated debt as well as capital expenditures and cash dividends exceeding FFO for the quarter.

We have unsecured revolving credit facilities consisting of a $1.0 billion Canadian facility and a US$200 million U.S. facility. As at September 30, 2015, we had approximately $1.05 billion in undrawn capacity on these facilities, which do not mature until June 2019.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Today 9:00 a.m. MST (11:00 a.m. EST)

Baytex will host a conference call today, November 6, 2015, starting at 9:00am MST (11:00am EST). To participate, please dial 416-340-2219 or toll free in North America 1-866-225-2055 and toll free international 1-800-6578-9868. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/6965 in your web browser. An archived recording of the conference call will be available until December 6, 2015 by dialing toll free 1-800-408-3053 within North America (Toronto local dial 905-694-9451, International toll free 1-800-3366-3052) and entering reservation code 3580921. The conference call will also be archived on the Baytex website at http://www.baytexenergy.com/.

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 business strategies, plans and objectives; our belief that we are well positioned for success as oil prices improve; our annual average production rate for 2015; our capital expenditures for 2015; the timing of announcing our 2016 capital and operating budget; our Eagle Ford shale play, including initial production rates from new wells, our plans to use "stack and frac" pilots to target three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation, our assessment of the results of our "stack and frac" pilots and the number of frac crews completing wells; our expectation that we will return a portion of funds from operations to shareholders under normal operating conditions; 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 the volatility in heavy oil price differentials by transporting our crude oil to market on railways; the volume of heavy oil to be transported to market on railways in the fourth quarter of 2015; and our liquidity and financial capacity. 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 funds from operations 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: our ability to execute and realize on the anticipated benefits of the acquisition of the Eagle Ford assets; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserves 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 for our operating activities; 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; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). 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 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: the volatility of oil and natural gas prices; substantial or extended declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; uncertainties in the capital markets that may restrict the availability of or increase the cost of capital or of borrowing; refinancing risk for existing debt and the risk of failing to comply with covenants in existing debt agreements; risks associated with properties operated by third parties, specifically with respect to a substantially majority of our Eagle Ford assets; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all hazards associated with acquiring, developing and exploring for oil and natural gas; business risks; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; the implementation of strategies for reducing greenhouse gases; depletion of our reserves; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2014, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

The above summary of assumptions and risks related to forward-looking statements in this press release has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations and such information may not be appropriate for other purposes. 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.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

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. We define total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives)) and the principal amount of both the long-term debt and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to product revenue less royalties, production and operating expenses and transportation expenses dividend by barrels of oil equivalent sales volume for the applicable period. Baytex's determination of operating netback may not be comparable with the calculation of similar measures for other entities. Baytex believes that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent 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.

References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

Baytex Energy Corp.

Baytex Energy Corp. is an oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Approximately 81% of Baytex's production is weighted toward crude oil and natural gas liquids. Baytex's common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit our website at www.baytexenergy.com.