BTE Baytex Energy Corp

Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three months ended March 31, 2017 (all amounts are in Canadian dollars unless otherwise noted).

“We are off to a great start in 2017 with production trending toward the high end of our guidance range. We now expect to deliver organic production growth of 5-6% this year, as compared to 3-4% previously. In the Eagle Ford, our development is shifting to the northern oil window with larger fracture stimulations and at Peace River and Lloydminster, our drilling program is generating impressive results. We are successfully integrating our Peace River acquisition, with production on these assets increasing and operating cost improvements already underway. These first quarter results demonstrate our ability to generate strong funds from operations and grow production in today’s crude oil pricing environment,” commented Ed LaFehr, President and Chief Executive Officer.

Highlights

• Generated production of 69,298 boe/d (79% oil and NGL) during Q1/2017, an increase of 6% from Q4/2016;
• Delivered funds from operations ("FFO") of $81.4 million ($0.35 per basic share) in Q1/2017;
• Produced 36,081 boe/d in the Eagle Ford, an increase of 8% from Q4/2016, and 33,217 boe/d in Canada, an increase of 5% from Q4/2016;
• Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q1/2017 of     $19.42/boe ($19.46/boe including financial derivatives gain);
• Increased pace of development in the Eagle Ford to five drilling rigs and two completion crews with record low well costs of approximately US$4.5 million despite increasing frac stages and proppant usage during Q1/2017; 
• Executed our Q1/2017 drilling program in Canada drilling 17 net heavy oil wells with strong initial results at Peace River and Lloydminster; and
• Integrated the Peace River acquisition which closed on January 20, 2017. From the time of closing, production on these assets has increased by approximately 13% as we initiated phase one of our plan to bring shut-in production back on-line.

		Three Months Ended
		March 31, 2017				December 31, 2016				March 31, 2016
FINANCIAL(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales		$	260,549			$	233,116			$	153,598
Funds from operations (1)		81,369				77,239				45,645
Per share - basic		0.35				0.36				0.22
Per share - diluted		0.34				0.36				0.22
Net income (loss)		11,096				(359,424		)		607
Per share - basic		0.05				(1.66		)		0.00
Per share - diluted		0.05				(1.66		)		0.00
Exploration and development		96,559				68,029				81,685
Acquisitions, net of divestitures		66,004				(322		)		(9		)
Total oil and natural gas capital expenditures		$	162,563			$	55,556			$	81,676
Bank loan (2)		$	259,966			$	191,286			$	290,465
Long-term notes (2)		1,574,116				1,584,158				1,540,546
Long-term debt		1,834,082				1,775,444				1,831,011
Working capital deficiency (surplus)		16,827				(1,903		)		150,332
Net debt (3)		$	1,850,909			$	1,773,541			$	1,981,343

		Three Months Ended
		March 31, 2017				December 31, 2016				March 31, 2016
OPERATING
Daily production
Heavy oil (bbl/d)		24,625				22,982				24,807
Light oil and condensate (bbl/d)		21,617				20,163				24,489
NGL (bbl/d)		8,306				8,319				10,109
Total oil and NGL (bbl/d)		54,548				51,464				59,405
Natural gas (mcf/d)		88,502				82,032				98,220
Oil equivalent (boe/d @ 6:1) (4)		69,298				65,136				75,776
Benchmark prices
WTI oil (US$/bbl)		51.91				49.29				33.45
WCS heavy oil (US$/bbl)		37.34				34.97				19.22
Edmonton par oil ($/bbl)		63.98				61.58				40.80
LLS oil (US$/bbl)		52.50				49.95				33.24
Baytex average prices (before hedging)
Heavy oil ($/bbl) (5)		35.96				34.33				12.54
Light oil and condensate ($/bbl)		63.26				60.12				37.97
NGL ($/bbl)		26.35				22.64				18.38
Total oil and NGL ($/bbl)		45.31				42.55				24.02
Natural gas ($/mcf)		3.52				3.61				2.40
Oil equivalent ($/boe)		40.16				38.16				21.93
CAD/USD noon rate at period end		1.3322				1.3427				1.2971
CAD/USD average rate for period		1.3229				1.3339				1.3748
COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
High		6.97				7.35				5.39
Low		4.02				4.85				1.57
Close		4.54				6.56				5.13
Volume traded (thousands)		255,645				351,040				483,311
NYSE
Share price (US$)
High		5.19				5.61				4.15
Low		3.01				3.60				1.08
Close		3.65				4.48				3.97
Volume traded (thousands)		136,666				186,423				154,052
Common shares outstanding (thousands)		234,203				233,449				210,689

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 changes in non-cash operating working capital and other operating items. Baytex's determination of 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 potential 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 months ended March 31, 2017.(2) Principal amount of instruments.(3) Net debt is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. We define net debt to be the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes and the bank loan.(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 exclude condensate blending.

CEO Appointment

As previously announced in December 2016, Ed LaFehr has been appointed Chief Executive Officer, succeeding James Bowzer. Mr. Bowzer, who has been in the role since September 2012, has worked with Mr. LaFehr to ensure a seamless leadership transition and will remain on the Board of Directors. Mr. LaFehr has been nominated for election as a Director at our Annual Meeting of Shareholders to be held on May 4, 2017.

Mr. LaFehr joined Baytex in July 2016 as President and has been an integral member of the executive leadership team, holding responsibility for the Canadian and U.S. business operations and corporate development. Mr. LaFehr has a long track record of success in the oil and gas industry leading organizations, growing assets and joint ventures, and driving capital and cost efficiencies.  

Operating Results

Our operating results for the first quarter reflect an increased pace of drilling activity in the Eagle Ford that began late in Q4/2016, the resumption of drilling activity in Canada and an initial contribution from our Peace River acquisition.

Production increased 6% to average 69,298 boe/d (79% oil and NGL) in Q1/2017, as compared to 65,136 boe/d (79% oil and NGL) in Q4/2016. Capital expenditures for exploration and development activities totaled $96.6 million in Q1/2017 and included the drilling of 67 (35.5 net) wells with a 100% success rate.

Reflective of our strong first quarter operating results and planned activity level for the balance of the year, we are tightening our 2017 production guidance range to 68,000 to 70,000 boe/d (previously 66,000 to 70,000 boe/d). At the mid-point of our guidance range, this reflects an increase of 1.5%. Our expected exit production rate for 2017 now reflects an organic growth rate of approximately 5-6% over our 2016 exit production rate, as compared to our prior expectation of 3-4%. We are now forecasting full-year 2017 exploration and development capital expenditures of $325 to $350 million (previously $300 to $350 million).

Eagle Ford

Our Eagle Ford assets in South Texas provide us with exposure to one of the premier oil resource plays in North America. The assets generate the highest cash netbacks in our portfolio with an inventory of development prospects in excess of 10 years at our current pace of development. In Q1/2017, we directed 60% of our exploration and development expenditures toward these assets.

Production increased 8% during the first quarter to average 36,081 boe/d (76% liquids), as compared to 33,432 boe/d in Q4/2016. During the first quarter, we averaged 5 drilling rigs and 2 completion crews on our lands.

In Q1/2017, we participated in the drilling of 36 (8.4 net) wells and commenced production from 33 (9.4 net) wells. The wells that commenced production during the quarter have established 30-day initial production rates of approximately 1,250 boe/d. A recently completed pad within the oil window of our Longhorn acreage established 30-day initial production rates of approximately 1,450 boe/d. At quarter end, we had 44 (10.7 net) wells waiting on completion.

We continued to see record low well costs during the first quarter with wells being drilled, completed and equipped for approximately US$4.5 million, down 20% from approximately US$5.6 million in Q1/2016. These record low well costs were achieved despite increasing the number of frac stages and proppant usage. In Q1/2017, we increased the effective number of frac stages per well to 28 (from 22 in Q1/2016) and the amount of proppant per completed foot to 1,800 pounds (from 1,000 pounds in Q1/2016).

Our pace of development in the Eagle Ford is expected to remain stable throughout 2017 with 4-5 drilling rigs and 2 completion crews working on our lands. At this pace, we expect to bring approximately 34 net wells on production in 2017.

Peace River

Our Peace River region, located in northwest Alberta, has been a core asset for us since we commenced operations in the area in 2004. Through our innovative multi-lateral horizontal drilling and production techniques, the area is recognized as having some of the strongest capital efficiencies in the oil and gas industry and, over the years, has contributed significantly to our growth. Production during the first quarter averaged approximately 17,000 boe/d (93% heavy oil).  

In November, we announced the strategic acquisition of additional heavy oil assets in Peace River. The assets are located immediately adjacent to our existing Peace River lands and more than doubled our land base in the area. The acquisition will drive efficiencies and synergies in our operations and significantly enhances our inventory of drilling locations for future growth. In total, we now have 350 potential drilling locations on our lands representing a drilling inventory of approximately 14 years. We closed the acquisition on January 20, 2017 for total consideration of $66 million. At the time of closing, the assets were producing approximately 3,000 boe/d.  

Since closing the acquisition, production has increased by approximately 13% as we initiated phase one of our plan to bring approximately 3,000 boe/d of shut-in production back on-line. During the first quarter, we restarted 29 wells at a total cost of approximately $0.5 million, which resulted in an incremental 400 boe/d of production and capital efficiencies of approximately $1,250 per boe/d. Phase two will include additional gas conservation and vapour recovery systems that are expected to be implemented over the next 6-18 months. We are also undertaking an extensive review of the operations to ensure regulatory compliance and identify opportunities to reduce operating costs. We expect to achieve a 15-20% reduction in operating costs on the acquired assets in 2017 with further improvements anticipated in 2018 and beyond.

During the first quarter, we drilled 4 (4.0 net) multi-lateral horizontal wells (average of 12 laterals per well), two of which have been producing for more than 30 days and have established 30-day initial production rates of 614 bbl/d and 489 bbl/d. The cost to drill, complete and equip a multi-lateral well at Peace River is approximately $2.5 million, representing an 11% improvement from the wells we drilled in Q3/2015.

We plan to drill a total of 11 net multi-lateral horizontal wells at Peace River in 2017.

Lloydminster

Our Lloydminster region, which straddles the Alberta and Saskatchewan border, produced approximately 9,100 boe/d (98% heavy oil) during the first quarter, unchanged from Q4/2016. This area is characterized by multiple stacked pay formations at relatively shallow depths, which we have successfully developed through vertical and horizontal drilling, waterflood and SAGD operations.

During the first quarter, we drilled 17 (13.1 net) wells, including 12 (12.0 net) operated wells. We are now applying our multi-lateral drilling and production techniques from our Peace River region to Lloydminster, which we expect will lead to a 25% improvement in individual well capital efficiencies compared to single-lateral horizontal wells.

At Soda Lake, we drilled 8 (8.0 net) multi-lateral horizontal wells in the first quarter of 2017 (16 multi-lateral horizontal wells are planned for the full-year). Depending on the overall length and completion, well costs range from $700,000 to $900,000 with average 30-day initial production rates of 90-150 bbl/d. Through efficient operational execution and lower service costs, the cost to drill, complete and equip our first eight multi-lateral wells have come in approximately 15% below budget with 30-day initial production rates meeting expectations.

We plan to drill a total of 52 net wells at Lloydminster in 2017. At this pace of development, we have a drilling inventory of over 10 years on these lands.   

Financial Review

We generated FFO of $81.4 million ($0.35 per share) in Q1/2017, compared to $77.2 million ($0.36 per share) in Q4/2016. The increase in FFO is largely due to higher production and commodity prices, offset by lower realized hedging gains.  

Financial Liquidity

Our net debt totaled $1.85 billion at March 31, 2017, as compared to $1.78 billion at December 31, 2016. The increase in net debt primarily relates to the Peace River acquisition that closed in January 2017 and was funded with a $115 million equity issue that closed in December 2016. 

We continue to maintain strong financial liquidity with our US$575 million revolving credit facilities one-third drawn and our first meaningful long-term note maturity is not until 2021. With our strategy to spend within funds from operations, we expect this liquidity position to be stable going forward.   

Our revolving credit facilities, which currently mature June 2019, are covenant based and do not require annual or semi-annual reviews. We are well within our financial covenants on these facilities as our Senior Secured Debt to Bank EBITDA ratio as at March 31, 2017 was 0.7:1.00, compared to a maximum permitted ratio of 5.00:1.00, and our interest coverage ratio was 4.0:1.00, compared to a minimum required ratio of 1.25:1.00.

Operating Netback

During the first quarter, our operating netback improved as compared to Q4/2016. In Q1/2017, the price for West Texas Intermediate light oil (“WTI”) averaged US$51.91/bbl, as compared to US$49.29/bbl in Q4/2016. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, increased slightly during Q1/2017, averaging US$14.58/bbl, as compared to US$14.32/bbl in Q4/2016.

We generated an operating netback in Q1/2017 of $19.42/boe ($19.46/boe including financial derivatives gain), as compared to $17.62/boe ($19.24/boe including financial derivatives gain) in Q4/2016 and $5.82/boe ($12.29/boe including financial derivatives gain) in Q1/2016. The Eagle Ford generated an operating netback of $26.83/boe during Q1/2017 while our Canadian operations generated an operating netback of $11.37/boe.

The following table summarizes our operating netbacks for the periods noted.

		Three Months Ended March 31
		2017													2016
($ per boe except for sales volume)		Canada				U.S.				Total					Canada					U.S.				Total
Sales volume (boe/d)		33,217				36,081				69,298					34,709					41,067				75,776
Realized sales price		$	32.81			$	46.93			$	40.16				$	13.55				$	29.02			$	21.93
Less:
Royalty		4.23				13.72				9.17					1.21					8.23				5.02
Operating expense		14.52				6.38				10.28					10.97					9.38				10.11
Transportation expense		2.69				—				1.29					2.14					—				0.98
Operating netback		$	11.37			$	26.83			$	19.42				$	(0.77	)			$	11.41			$	5.82
Realized financial derivatives gain			—				—				0.04					—					—				6.47
Operating netback after financial derivatives gain		$	11.37			$	26.83			$	19.46				$	(0.77	)			$	11.41			$	12.29

Risk Management

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our FFO. We realized a financial derivatives gain of $0.3 million in Q1/2017.

For the remainder of 2017, we have entered into hedges on approximately 48% of our net WTI exposure with 9% fixed at US$54.46/bbl and 39% hedged utilizing a 3-way option structure that provides us with downside price protection at approximately US$47/bbl and upside participation to approximately US$59/bbl. We have also entered into hedges on approximately 38% of our net WCS differential exposure and 60% of our net natural gas exposure.

A complete listing of our financial derivative contracts can be found in Note 17 to our Q1/2017 financial statements.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 2017 and the 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 Tomorrow – May 5, 20179:00 a.m. MDT (11:00 a.m. EDT)

Baytex will host a conference call tomorrow, May 5, 2017, starting at 9:00am MDT (11:00am EDT). To participate, please dial toll free in North America 1-866-226-4099 or international 1-647-427-2258. Alternatively, to listen to the conference call online, please enter http://edge.media-server.com/m/p/9suibzi6 in your web browser.   An archived recording of the conference call will be available approximately two hours after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at 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 but not limited to: our business strategies, plans and objectives; our 2017 production and capital expenditure guidance; our Eagle Ford assets, including our assessment that it is a premier oil resource play, that development is shifting to the northern oil window, our 2016-2017 exit production organic growth rate; our inventory of development prospects (in years based on 2017 activity levels), the cost to drill, complete and equip a well, initial production rates from new wells drilled in Q1/2017, the number of drilling rigs and frac crews working on our lands during 2017 and the number of wells we plan to bring on production in 2017; our Peace River assets, including that the area has some of the strongest capital efficiencies in the oil and gas industry, that our recently completed acquisition will drive efficiencies and synergies in our operations and significantly enhances our drilling inventory, our total inventory of potential drilling locations (both in number and years (based on 2017 activity levels)), our plan for bringing shut-in production volumes back on-line, our expectation that we will achieve meaningful operating cost improvements in 2017, 2018 and beyond, the cost to drill, complete and equip a well, initial production rates from wells drilled in Q1/2017, and the number of multi-lateral wells to be drilled in 2017; our Lloydminster assets, including our expectation that multi-lateral drilling will improve individual well capital efficiencies, the cost to drill, complete and equip a multi-lateral horizontal well, initial production rates from multi-lateral horizontal wells; the number and type of wells to be drilled in 2017, and our inventory of drilling prospects (in years based on 2017 activity levels); our belief that we have strong financial liquidity and that our liquidity position will remain stable going forward; our target for capital expenditures to approximate funds from operations; our ability to partially reduce the volatility in our funds from operations by utilizing financial derivative contracts for commodity prices, heavy oil differentials and interest and foreign exchange rates; and the percentage of our anticipated 2017 oil and natural gas production that is hedged.  In addition, information and statements relating to reserves and contingent resources are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves and contingent resources described exist in quantities predicted or estimated, and that they can be profitably produced in the future.

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; our ability to borrow under our credit agreements; 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; 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). Readers are 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; a decline or an extended period of the currently low oil and natural gas prices; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; availability and cost of gathering, processing and pipeline systems; depletion of our reserves; 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 risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; we may lose access to our information technology systems; risks associated with the ownership of our securities, including 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, 2016, 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 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 will be the same in whole or in part as those referenced in the forward-looking statements 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 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 capital investments and potential future dividends to shareholders.  The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.

Net debt is not a measurement based on GAAP in Canada.  We define net debt to be the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Bank EBITDA is not a measurement based on GAAP in Canada.  We define Bank EBITDA as our consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items as set out in the credit agreement governing our revolving credit facilities. Bank EBITDA is used to measure compliance with certain financial covenants.

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 divided by barrels of oil equivalent sales volume for the applicable period.  Our determination of operating netback may not be comparable with the calculation of similar measures for other entities.  We believe 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.

This press release discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total proved, probable and unbooked locations.  Proved locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves.  Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review.  Unbooked locations do not have attributed reserves.  Unbooked locations are farther away from existing wells and, therefore, there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty whether such wells will result in additional oil and gas reserves, resources or production.  At the Eagle Ford, our net drilling locations include 201 proved, 81 probable and 283 unbooked locations.  At Peace River, our net drilling locations include 116 proved, 54 probable and 180 unbooked locations (which include locations attributable to the assets acquired on January 20, 2017, which were based on an internal evaluation prepared by a qualified reserves evaluator and are not included in our 2016 reserves report).  At Lloydminster, our net drilling locations include 279 proved, 103 probable and 252 unbooked locations.

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 79% 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 or contact:

Brian Ector, Senior Vice President, Capital Markets and Public Affairs

Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com