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Form 6-K BAYTEX ENERGY CORP. For: Mar 31

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May 3, 2016 12:08 PM EDT



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 Under the
Securities Exchange Act of 1934
For the month of May 2016

Commission File Number: 1-32754

BAYTEX ENERGY CORP.
(Exact name of registrant as specified in its charter)
2800, 520 – 3rd AVENUE S.W.
CALGARY, ALBERTA, CANADA
T2P 0R3
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
      Form 20-F o
   Form 40-F x
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted
by Regulation S-T Rule 101(b)(1): o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted
by Regulation S-T Rule 101(b)(7): o

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
   Yes         o
      No x
If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):
This Report on Form 6-K of Baytex Energy Corp. (the "Company") includes as Exhibit 99.1 the Company's Condensed Interim Unaudited Consolidated Financial Statements for the three months ended March 31, 2016 and 2015 and as Exhibit 99.2 the Company's Management's Discussion and Analysis for the three months ended March 31, 2016 and 2015. Exhibits 99.1 and 99.2 to this Report on Form 6-K shall be deemed to be filed and shall be incorporated by reference into the Company's Registration Statements on Form S-8 (333-171568) and Form F-3 (333-171866).






The following documents attached as exhibits hereto are incorporated by reference herein:
Exhibit No.
Document
99.1
Condensed Interim Unaudited Consolidated Financial Statements for the three months ended March 31, 2016 and 2015
99.2
Management's Discussion and Analysis for the three months ended March 31, 2016 and 2015
99.3
Certification of Interim Filings (Form 52-109F2) – Chief Executive Officer
99.4
Certification of Interim Filings (Form 52-109F2) – Chief Financial Officer
99.5
Press Release dated May 3, 2016 (Baytex reports Q1 2016 results)






SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BAYTEX ENERGY CORP.

_/s/ Rodney D. Gray
Name: Rodney D. Gray
Title:      Chief Financial Officer

Dated: May 3, 2016




Exhibit 99.1
Baytex Energy Corp.
Condensed Consolidated Statements of Financial Position
(thousands of Canadian dollars)(unaudited)
As at
March 31, 2016

December 31, 2015

 
 
 
ASSETS
 
 
Current assets
 
 
Cash
$
452

$
247

Trade and other receivables
77,791

98,093

Financial derivatives
80,434

106,573

 
158,677

204,913

Non-current assets
 
 
Financial derivatives
4,913

4,417

Exploration and evaluation assets (note 4)
549,673

578,969

Oil and gas properties (note 5)
4,459,057

4,674,175

Other plant and equipment
25,593

26,024

 
$
5,197,913

$
5,488,498

 
 
 
LIABILITIES
 
 
Current liabilities
 
 
Trade and other payables
$
228,575

$
267,838

Financial derivatives
1,515

—

 
230,090

267,838

Non-current liabilities
 
 
Bank loan (note 6)
286,373

252,172

Long-term notes (note 7)
1,521,230

1,602,757

Asset retirement obligations (note 8)
313,930

296,002

Deferred income tax liability
582,513

655,255

Financial derivatives
2,965

—

 
2,937,101

3,074,024

 
 
 
SHAREHOLDERS’ EQUITY
 
 
Shareholders' capital (note 9)
4,298,956

4,296,831

Contributed surplus
6,890

4,575

Accumulated other comprehensive income
546,673

705,382

Deficit
(2,591,707
)
(2,592,314
)
 
2,260,812

2,414,474

 
$
5,197,913

$
5,488,498


See accompanying notes to the condensed interim consolidated financial statements.




Page 1


Baytex Energy Corp.
Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)
(thousands of Canadian dollars, except per common share amounts) (unaudited)
 
Three Months Ended March 31
 
2016

2015

 
 
 
Revenue, net of royalties
 
 
Petroleum and natural gas sales
$
153,598

$
283,384

Royalties
(34,582
)
(56,707
)
 
119,016

226,677

 
 
 
Expenses
 
 
Operating
69,680

87,755

Transportation
6,775

15,949

Blending
2,359

9,673

General and administrative
14,169

17,055

Exploration and evaluation (note 4)
1,463

2,351

Depletion and depreciation
141,671

174,127

Share-based compensation (note 10)
4,440

8,004

Financing and interest (note 13)
29,053

29,410

Financial derivatives (gain) (note 15)
(14,503
)
(13,662
)
Foreign exchange (gain) loss (note 14)
(87,343
)
97,055

Loss on disposition of oil and gas properties
22

1,854

Other expense (income)
187

(2,231
)
 
167,973

427,340

Net income (loss) before income taxes
(48,957
)
(200,663
)
Income tax (recovery) expense (note 12)
 
 
Current income tax (recovery) expense
(1,442
)
16,935

Deferred income tax (recovery)
(48,122
)
(41,682
)
 
(49,564
)
(24,747
)
Net income (loss) attributable to shareholders
$
607

$
(175,916
)
Other comprehensive income (loss)
 
 
Foreign currency translation adjustment
(158,709
)
240,918

Comprehensive income (loss)
$
(158,102
)
$
65,002

 
 
 
Net income (loss) per common share (note 11)
 
 
Basic
$
0.00

$
(1.04
)
Diluted
$
0.00

$
(1.04
)
 
 
 
Weighted average common shares (note 11)
 
 
Basic
210,662

168,607

Diluted
211,606

168,607


See accompanying notes to the condensed interim consolidated financial statements.


Page 2


Baytex Energy Corp.
Condensed Consolidated Statements of Changes in Equity
(thousands of Canadian dollars) (unaudited)
 
Shareholders’ capital

Contributed surplus

Accumulated other comprehensive income (loss)

Deficit

Total equity

Balance at December 31, 2014
$
3,580,825

$
31,067

$
199,575

$
(1,304,690
)
$
2,506,777

Dividends to shareholders
—

—

—

(50,649
)
(50,649
)
Vesting of share awards
14,002

(14,002
)
—

—

—

Share-based compensation
—

8,004

—

—

8,004

Issued pursuant to dividend reinvestment plan
10,545

—

—

—

10,545

Comprehensive income (loss) for the period
—

—

240,918

(175,916
)
65,002

Balance at March 31, 2015
$
3,605,372

$
25,069

$
440,493

$
(1,531,255
)
$
2,539,679

Balance at December 31, 2015
4,296,831

4,575

705,382

(2,592,314
)
2,414,474

Vesting of share awards
2,125

(2,125
)
—

—

—

Share-based compensation
—

4,440

—

—

4,440

Comprehensive income (loss) for the period
—

—

(158,709
)
607

(158,102
)
Balance at March 31, 2016
$
4,298,956

$
6,890

$
546,673

$
(2,591,707
)
$
2,260,812


See accompanying notes to the condensed interim consolidated financial statements.

Page 3


Baytex Energy Corp.
Condensed Consolidated Statements of Cash Flows
(thousands of Canadian dollars) (unaudited)
 
Three Months Ended March 31
 
2016

2015

 
 
 
CASH PROVIDED BY (USED IN):
 
 
Operating activities
 
 
Net income (loss) for the period
$
607

$
(175,916
)
Adjustments for:
 
 
Share-based compensation (note 10)
4,440

8,004

Unrealized foreign exchange (gain) loss (note 14)
(86,801
)
101,316

Exploration and evaluation (note 4)
1,463

2,351

Depletion and depreciation
141,671

174,127

Non-cash financing and interest
2,242

1,995

Unrealized financial derivatives loss (note 15)
30,123

88,172

Loss on disposition of oil and gas properties
22

1,854

Deferred income tax (recovery)
(48,122
)
(41,682
)
Change in non-cash working capital
20,409

32,125

Asset retirement obligations settled (note 8)
(1,701
)
(4,446
)
 
64,353

187,900

 
 
 
Financing activities
 
 
Payment of dividends
—

(40,015
)
Increase in bank loan
50,743

99,071

Tenders of long-term notes
—

(10,372
)
 
50,743

48,684

 
 
 
Investing activities
 
 
Additions to exploration and evaluation assets (note 4)
(1,065
)
(2,043
)
Additions to oil and gas properties (note 5)
(80,620
)
(145,386
)
Property acquisitions, net of divestitures
9

(1,550
)
Current income tax expense on dispositions
—

(8,181
)
Additions to other plant and equipment, net of disposals
(322
)
4,370

Change in non-cash working capital
(31,235
)
(80,959
)
 
(113,233
)
(233,749
)
Impact of foreign currency translation on cash balances
(1,658
)
985

Change in cash
205

3,820

Cash, beginning of period
247

1,142

Cash, end of period
$
452

$
4,962

 
 
 
Supplementary information
 
 
Interest paid
$
21,654

$
21,590

Income taxes paid
$
5,138

$
8,181


See accompanying notes to the condensed interim consolidated financial statements.

Page 4


Baytex Energy Corp.
Notes to the Condensed Consolidated Financial Statements
As at March 31, 2016 and December 31, 2015 and for the three months ended March 31, 2016 and 2015
(all tabular amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)
1.
REPORTING ENTITY
Baytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

2.
BASIS OF PRESENTATION
The condensed interim unaudited consolidated financial statements ("consolidated financial statements") have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, as issued by the International Accounting Standards Board. These consolidated financial statements do not include all the necessary annual disclosures as prescribed by International Financial Reporting Standards and should be read in conjunction with the annual audited consolidated financial statements as of December 31, 2015. The Company's accounting policies are unchanged compared to December 31, 2015. The use of estimates and judgments is also consistent with the December 31, 2015 financial statements.

The consolidated financial statements were approved by the Board of Directors of Baytex on May 2, 2016.

The consolidated financial statements have been prepared on the historical cost basis, except for derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is rounded to the nearest thousand, except per share amounts and when otherwise indicated. Prior period financial statement amounts have been reclassified to conform with current period presentation.


Page 5


3.
SEGMENTED FINANCIAL INFORMATION

Baytex's reportable segments are determined based on the Company's geographic locations.

•
Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada.
•
U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the state of Texas, USA.
•
Corporate includes corporate activities and items not allocated between operating segments.
 
Canada
U.S.
Corporate
Consolidated
Three Months Ended March 31
2016

2015

2016

2015

2016

2015

2016

2015

 
 
 
 
 
 
 
 
 
Revenue, net of royalties
 
 
 
 
 
 
 
 
Petroleum and natural gas sales
$
45,148

$
132,413

$
108,450

$
150,971

$
—

$
—

$
153,598

$
283,384

Royalties
(3,835
)
(13,419
)
(30,747
)
(43,288
)
—

—

(34,582
)
(56,707
)
 
41,313

118,994

77,703

107,683

—

—

119,016

226,677

 
 
 
 
 
 
 
 
 
Expenses
 
 
 
 
 
 
 
 
Operating
34,645

60,574

35,035

27,181

—

—

69,680

87,755

Transportation
6,775

15,949

—

—

—

—

6,775

15,949

Blending
2,359

9,673

—

—

—

—

2,359

9,673

General and administrative
—

—

—

—

14,169

17,055

14,169

17,055

Exploration and evaluation
1,463

2,351

—

—

—

—

1,463

2,351

Depletion and depreciation
54,785

75,117

86,139

98,384

747

626

141,671

174,127

Share-based compensation
—

—

—

—

4,440

8,004

4,440

8,004

Financing and interest
—

—

—

—

29,053

29,410

29,053

29,410

Financial derivatives gain
—

—

—

—

(14,503
)
(13,662
)
(14,503
)
(13,662
)
Foreign exchange (gain) loss
—

—

—

—

(87,343
)
97,055

(87,343
)
97,055

Loss (gain) on disposition of oil and gas properties
22

2,074

—

(220
)
—

—

22

1,854

Other expense (income)
—

—

—

—

187

(2,231
)
187

(2,231
)
 
100,049

165,738

121,174

125,345

(53,250
)
136,257

167,973

427,340

Net income (loss) before income taxes
(58,736
)
(46,744
)
(43,471
)
(17,662
)
53,250

(136,257
)
(48,957
)
(200,663
)
Income tax (recovery) expense
 
 
 
 
 
 
 
 
Current income tax (recovery) expense
(1,442
)
16,935

—

—

—

—

(1,442
)
16,935

Deferred income tax (recovery) expense
(14,734
)
(15,054
)
(28,400
)
(18,261
)
(4,988
)
(8,367
)
(48,122
)
(41,682
)
 
(16,176
)
1,881

(28,400
)
(18,261
)
(4,988
)
(8,367
)
(49,564
)
(24,747
)
Net income (loss)
$
(42,560
)
$
(48,625
)
$
(15,071
)
$
599

$
58,238

$
(127,890
)
$
607

$
(175,916
)
 
 
 
 
 
 
 
 
 
Total oil and natural gas capital expenditures (1)
$
4,846

$
22,683

$
76,830

$
126,296

$
—

$
—

$
81,676

$
148,979

(1) Includes acquisitions and divestitures.
As at
March 31, 2016

December 31, 2015

Canadian assets
$
2,015,547

$
2,059,903

U.S. assets
3,084,283

3,304,647

Corporate assets
98,083

123,948

Total consolidated assets
$
5,197,913

$
5,488,498




Page 6


4.
EXPLORATION AND EVALUATION ASSETS

March 31, 2016

December 31, 2015

Balance, beginning of period
$
578,969

$
542,040

Capital expenditures
1,065

5,642

Property acquisitions, net of divestitures
(25
)
1,813

Exploration and evaluation expense
(1,463
)
(8,775
)
Transfer to oil and gas properties
(26
)
(38,062
)
Divestitures
—

(1,588
)
Foreign currency translation
(28,847
)
77,899

Balance, end of period
$
549,673

$
578,969



5.
OIL AND GAS PROPERTIES

Cost

Accumulated depletion

Net book value

Balance, December 31, 2014
$
6,431,760

$
(1,447,844
)
$
4,983,916

Capital expenditures
515,397

—

515,397

Property acquisitions
551

—

551

Transferred from exploration and evaluation assets
38,062

—

38,062

Change in asset retirement obligations
10,722

—

10,722

Divestitures
(20,096
)
19,449

(647
)
Impairment
(755,613
)
—

(755,613
)
Foreign currency translation
607,885

(68,509
)
539,376

Depletion
—

(657,589
)
(657,589
)
Balance, December 31, 2015
$
6,828,668

$
(2,154,493
)
$
4,674,175

Capital expenditures
80,620

—

80,620

Property acquisitions, net of divestitures
(6
)
—

(6
)
Transferred from exploration and evaluation assets
26

—

26

Change in asset retirement obligations
20,409

—

20,409

Foreign currency translation
(220,076
)
44,833

(175,243
)
Depletion
—

(140,924
)
(140,924
)
Balance, March 31, 2016
$
6,709,641

$
(2,250,584
)
$
4,459,057


6.
BANK LOAN
 
March 31, 2016

December 31, 2015

Bank loan - principal
$
290,465

$
256,749

Unamortized debt issuance costs
(4,092
)
(4,577
)
Bank loan
$
286,373

$
252,172


On March 31, 2016, Baytex amended the credit facilities with its banking syndicate to grant the banking syndicate first priority security over its assets. The amended revolving extendible secured credit facilities are comprised of a US$25 million operating loan, a US$350 million syndicated loan for Baytex and a US$200 million syndicated loan for its wholly-owned subsidiary, Baytex Energy USA, Inc., (collectively, the "Revolving Facilities").


Page 7


The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants and do not require any mandatory principal payments prior to maturity on June 4, 2019. Baytex may request an extension under the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year period at any time). Advances (including letters of credit) under the Revolving Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex exceeds any of the covenants under the Revolving Facilities, its ability to borrow funds, increase the facilities or pay dividends to its shareholders may be restricted.

The weighted average interest rate on the credit facilities for the three months ended March 31, 2016 was 3.5% (2.8% for the three months ended March 31, 2015). Baytex is in compliance with all covenants at March 31, 2016.


7.
LONG-TERM NOTES
 
March 31, 2016

December 31, 2015

7.5% notes (US$6,400 – principal) due April 1, 2020
$
8,301

$
8,858

6.75% notes (US$150,000 – principal) due February 17, 2021
194,565

207,600

5.125% notes (US$400,000 – principal) due June 1, 2021
518,840

553,600

6.625% notes (Cdn$300,000 – principal) due July 19, 2022
300,000

300,000

5.625% notes (US$400,000 – principal) due June 1, 2024
518,840

553,600

Total long-term notes - principal
1,540,546

1,623,658

Unamortized debt issuance costs
(19,316
)
(20,901
)
Total long-term notes - net of unamortized debt issuance costs
$
1,521,230

$
1,602,757



8.
ASSET RETIREMENT OBLIGATIONS
 
March 31, 2016

December 31, 2015

Balance, beginning of period
$
296,002

$
286,032

Liabilities incurred
1,680

4,964

Liabilities settled
(1,701
)
(10,888
)
Liabilities acquired
—

593

Liabilities divested
(270
)
(10,578
)
Accretion
1,662

6,262

Change in estimate(1)
600

33,266

Changes in discount rates and inflation rates
18,399

(17,523
)
Foreign currency translation
(2,442
)
3,874

Balance, end of period
$
313,930

$
296,002

(1)
Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in estimate.


Page 8


9.
SHAREHOLDERS' CAPITAL
The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10,000,000 preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at March 31, 2016, no preferred shares have been issued by the Company and all common shares issued were fully paid.
 
Number of Common Shares
(000s)

Amount

Balance, December 31, 2014
168,107

$
3,580,825

Transfer from contributed surplus on vesting and conversion of share awards
1,092

41,836

Issued for cash
36,455

632,494

Issuance costs, net of tax
—

(19,301
)
Issued pursuant to dividend reinvestment plan
4,929

60,977

Balance, December 31, 2015
210,583

$
4,296,831

Transfer from contributed surplus on vesting and conversion of share awards
106

2,125

Balance, March 31, 2016
210,689

$
4,298,956



10.
SHARE AWARD INCENTIVE PLAN
The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not at any time exceed 3.3% of the then-issued and outstanding common shares.

Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Both awards are expensed over the vesting period.

The Company recorded compensation expense related to the share awards of $4.4 million for the three months ended March 31, 2016 (three months ended March 31, 2015 - $8.0 million).

The weighted average fair value of share awards granted during the three months ended March 31, 2016 was $2.75 per restricted and performance award (the three months ended March 31, 2015 - $17.11 per restricted and performance award).

The number of share awards outstanding is detailed below:
(000s)
Number of restricted awards

Number of performance awards(1)

Total number of share awards

Balance, December 31, 2014
747

615

1,362

Granted
615

503

1,118

Vested and converted to common shares
(432
)
(382
)
(814
)
Forfeited
(201
)
(123
)
(324
)
Balance, December 31, 2015
729

613

1,342

Granted
1,259

1,371

2,630

Vested and converted to common shares
(58
)
(16
)
(74
)
Forfeited
(4
)
(13
)
(17
)
Balance, March 31, 2016
1,926

1,955

3,881

(1) Based on underlying awards before applying performance multiplier.


Page 9


11.
NET INCOME (LOSS) PER SHARE
 
Three Months Ended March 31
 
2016
2015
 
Net income

Common shares (000s)

Net income per share

Net loss

Common shares (000s)

Net loss per share

Net income (loss) - basic
$
607

210,662

$
0.00

$
(175,916
)
168,607

$
(1.04
)
Dilutive effect of share awards
—

944

0.00

—

—

—

Net income (loss) - diluted
$
607

211,606

$
0.00

$
(175,916
)
168,607

$
(1.04
)

For the three months ended March 31, 2016, 1.1 million share awards were anti-dilutive (March 31, 2015 - 2.1 million share awards).


12.
INCOME TAXES
The provision for income taxes has been computed as follows:
 
Three Months Ended March 31
 
2016

2015

Net income (loss) before income taxes
$
(48,957
)
$
(200,663
)
Expected income taxes at the statutory rate of 27.00% (2015 - 25.47%)(1)
(13,218
)
(51,109
)
Increase (decrease) in income tax recovery resulting from:
 
 
Share-based compensation
1,199

2,039

Non-taxable portion of foreign exchange (gain) loss
(11,143
)
13,093

Effect of change in income tax rates(1)
226

—

Effect of rate adjustments for foreign jurisdictions
(15,879
)
(12,378
)
Effect of change in deferred tax benefit not recognized(2)
(11,143
)
23,882

Other
394

(274
)
Income tax (recovery)
$
(49,564
)
$
(24,747
)
(1)
Expected income tax rate increased due to an increase in the corporate income tax rate in Alberta (from 10% to 12%), offset by a decrease in the Texas franchise tax rate (from 1.00% to 0.75%).
(2)
A deferred income tax asset has not been recognized for allowable capital losses of $107 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ($149 million as at December 31, 2015).

In 2014, the Canada Revenue Agency (the "CRA”) advised Baytex that it was proposing to reassess certain subsidiaries of Baytex to deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2013. Baytex has filed its 2014 and 2015 income tax returns on the same basis as the 2011 through 2013 tax returns, cumulatively claiming $591 million of non-capital losses. The Company believes that it is entitled to deduct the non-capital losses, that its tax filings to-date are correct and formally responded with a letter to the CRA indicating the same. At this time, the CRA has not issued a formal reply to Baytex’s letter. The Company expects to continue to defend the position as filed.



13.
FINANCING AND INTEREST
 
Three Months Ended March 31
 
2016

2015

Interest on bank loan
$
3,611

$
5,418

Interest on long-term notes
23,200

21,997

Accretion on long-term notes
580

377

Accretion on asset retirement obligations
1,662

1,618

Financing and interest
$
29,053

$
29,410



Page 10


14.
FOREIGN EXCHANGE
 
Three Months Ended March 31
 
2016

2015

Unrealized foreign exchange (gain) loss
$
(86,801
)
$
101,316

Realized foreign exchange (gain)
(542
)
(4,261
)
Foreign exchange (gain) loss
$
(87,343
)
$
97,055



15. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities at the reporting date are as follows:

Assets
Liabilities

March 31, 2016

December 31, 2015

March 31, 2016

December 31, 2015

U.S. dollar denominated

US$98,833


US$124,218


US$1,244,957


US$1,240,308


Financial Derivative Contracts

Baytex had the following financial derivative contracts:
Oil
Period
Volume
Price/Unit(1)

Index
Fixed - Sell
April 2016
3,000 bbl/d

US$34.80

WTI
Fixed - Sell
April 2016 to June 2016
2,000 bbl/d

US$62.50

WTI
Fixed - Sell
April 2016 to December 2016
5,000 bbl/d

US$63.79

WTI
Producer 3-way option(2)
April 2016 to December 2016
9,500 bbl/d
US$60.11/US$50/US$40

WTI
Producer 3-way option(2)
April 2016 to December 2017
2,000 bbl/d
US$60/US$50/US$40

WTI
Producer 3-way option(2)
January 2017 to December 2017
4,500 bbl/d
US$60/US$45/US$35

WTI
Basis swap
April 2016
3,000 bbl/d
WTI less US$12.82

WCS
Basis swap
April 2016 to June 2016
500 bbl/d
WTI less US$12.45

WCS
Basis swap
April 2016 to December 2016
4,500 bbl/d
WTI less US$13.27

WCS
Basis swap
July 2016 to September 2016
500 bbl/d
WTI less US$12.30

WCS
Basis swap
October 2016 to December 2016
500 bbl/d
WTI less US$13.45

WCS
Basis swap
January 2017 to December 2017
1,500 bbl/d
WTI less US$13.42

WCS
Sold call option(3)
January 2017 to December 2017
4,500 bbl/d

US$49.11

WTI
Producer 3-way option(2) (4)
July 2016 to December 2016
500 bbl/d
US$55/US$45/US$35

WTI
Producer 3-way option(2) (4)
January 2017 to December 2017
3,500 bbl/d
US$55.79/US$44.71/US$35

WTI
Sold call option(3) (4)
July 2016 to December 2016
500 bbl/d

US$48.00

WTI
Sold call option(3) (4)
January 2017 to December 2017
500 bbl/d

US$50.71

WTI
(1)
Based on the weighted average price/unit for the remainder of the contract.
(2)
Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in the $60/$50/$40 contract, 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.
(3)
Counterparty has the option to enter into a fixed sell for the periods, volumes and prices noted.
(4)
Contracts entered subsequent to March 31, 2016.


Page 11


Natural Gas
Period
Volume
Price/Unit(1)

Index
Fixed - Sell
April 2016 to December 2016
 15,000 mmBtu/d

US$2.98

NYMEX
Fixed - Sell
January 2017 to December 2017
 15,000 mmBtu/d

US$2.79

NYMEX
Fixed - Sell
April 2016 to December 2016
 20,000 GJ/d

$2.85

AECO
Fixed - Sell
January 2017 to December 2017
10,000 GJ/d

$2.65

AECO
Fixed - Sell(2)
January 2018 to December 2018
 5,000 mmBtu/d

US$3.00

NYMEX
Fixed - Sell(2)
May 2016 to December 2016
12,500 GJ/d

$1.65

AECO
(1)
Based on the weighted average price/unit for the remainder of the contract.
(2)
Contracts entered subsequent to March 31, 2016.

Financial derivatives are marked-to-market at the end of each reporting period, with the following reflected in the consolidated statements of income (loss) and comprehensive income (loss):
 
Three Months Ended March 31
 
2016

2015

Realized financial derivatives (gain)
$
(44,626
)
$
(101,834
)
Unrealized financial derivatives loss - commodity
30,123

90,032

Unrealized financial derivate (gain) - redemption feature on long-term notes
—

(1,860
)
Financial derivatives (gain) loss
$
(14,503
)
$
(13,662
)

Physical Delivery Contracts

As at March 31, 2016, the following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with the Company's expected sale requirements. Physical delivery contracts are not considered financial instruments; therefore, no asset or liability has been recognized in the consolidated financial statements.
Heavy Oil
Period
Volume
Price/Unit(1)
WCS Blend
April 2016 to December 2016
2,000 bbl/d
WTI less US$13.68
(1)
Based on the weighted average price/unit for the remainder of the contract.

As at March 31, 2016, Baytex had committed at fixed price to deliver the volumes of raw bitumen as noted below to market on rail:
 
Period
Term volume
Raw bitumen
April 2016 to June 2016
7,500 bbl/d
Raw bitumen
July 2016 to December 2016
7,400 bbl/d


Page 12
Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 1


Exhibit 99.2
BAYTEX ENERGY CORP. 
Management’s Discussion and Analysis
For the three months ended March 31, 2016 and 2015
Dated May 2, 2016

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2016 ("Q1/2016"). This information is provided as of May 2, 2016. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The Q1/2016 results have been compared with the three months ended March 31, 2015 ("Q1/2015"). This MD&A should be read in conjunction with the Company’s condensed interim unaudited consolidated financial statements (“consolidated financial statements”) for the three months ended March 31, 2016, its audited comparative consolidated financial statements for the years ended December 31, 2015 and 2014, together with the accompanying notes and its Annual Information Form for the year ended December 31, 2015. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

In this MD&A, 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, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

This MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our advisory on forward-looking information and statements.

NON-GAAP FINANCIAL MEASURES    

In this MD&A, we refer to certain financial measures (such as funds from operations, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). While funds from operations, net debt and operating netback are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures by other issuers.

Funds from Operations

The Company considers funds from operations ("FFO") a key measure that provides a more complete understanding of our results of operations and financial performance, including our ability to generate funds for capital investments, debt repayment and potential dividends. However, funds from operations should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income (loss).

The following table reconciles cash flow from operating activities (a GAAP measure) to funds from operations (a non-GAAP measure).

 
Three Months Ended March 31
($ thousands)
2016

2015

Cash flow from operating activities
$
64,353

$
187,900

Change in non-cash working capital
(20,409
)
(32,125
)
Asset retirement expenditures
1,701

4,446

Funds from operations
$
45,645

$
160,221




Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 2


Net Debt

We believe that net debt assists in providing a more complete understanding of our financial position.

The following table summarizes our net debt at March 31, 2016 and December 31, 2015.
($ thousands)
March 31, 2016

December 31, 2015

Bank loan(1)
$
290,465

$
256,749

Long-term notes(1)
1,540,546

1,623,658

Working capital deficiency(2)(3)
150,332

169,498

Net debt
$
1,981,343

$
2,049,905

(1)
Principal amount of instruments.
(2)
Working capital is current assets less current liabilities (excluding current financial derivatives).
(3)
In the oil and gas industry, it is not unusual to have a working capital deficiency as accounts receivable arising from sales of production are usually settled within one or two months but accounts payable related to capital and operating expenditures are usually settled over a longer time span (often two to four months) due to vendor billing cycles and internal approval processes.

Operating Netback

We define operating netback as oil and natural gas revenue, less royalties, operating expenses and transportation expenses. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of production basis.

Bank EBITDA

Bank EBITDA is used to assess compliance with certain financial covenants.

The following table reconciles net income (loss) to Bank EBITDA.
 
Three Months Ended March 31
($ thousands)
2016

2015

Net income (loss)
$
607

$
(175,916
)
Plus:
 
 
Financing and interest
29,053

29,410

Unrealized foreign exchange (gain) loss
(86,801
)
101,316

Unrealized financial derivatives loss
30,123

88,172

Current income tax (recovery) expense
(1,442
)
16,935

Deferred income tax (recovery)
(48,122
)
(41,682
)
Depletion and depreciation
141,671

174,127

Non-cash items(1)
5,925

12,209

Bank EBITDA
$
71,014

$
204,571

(1) Non-cash items include share-based compensation, exploration and evaluation expense and gain (loss) on divestiture of oil and gas properties.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 3


FIRST QUARTER HIGHLIGHTS

The price of West Texas Intermediate light oil ("WTI") reached its lowest point in 13 years in February of 2016 as commodity prices continued to slide during the first half of Q1/2016. Continued oversupply combined with elevated crude oil storage levels weighed on the market with WTI averaging US$33.45/bbl in Q1/2016 compared to US$42.18/bbl in Q4/2015 and US$48.64/bbl in Q1/2015. With the further decrease in commodity prices and the belief that prices will stay "lower for longer", we took several steps to protect our liquidity. We reduced our 2016 exploration and development capital budget by 33% to a range of $225 to $265 million, shut-in approximately 7,500 bbl/d of low or negative margin production throughout the quarter and renegotiated our credit facilities with our banking syndicate.

Production averaged 75,776 boe/d during Q1/2016, representing a 16% reduction from Q1/2015 mainly due to the low or negative margin production being shut-in combined with declining production in Canada resulting from minimal capital investment over the past 15 months. U.S. production averaged 41,067 boe/d for Q1/2016, largely unchanged from 41,076 boe/d in Q1/2015. Canadian production averaged 34,709 boe/d for Q1/2016, a decrease of 30% from Q1/2015.

Funds from operations for Q1/2016 was $45.6 million ($0.22 per basic and diluted share) compared to $160.2 million ($0.95 per basic and diluted share) in Q1/2015. The decrease in FFO was directly attributable to lower commodity prices and lower production volumes in Canada as well as lower realized financial derivatives gain.

Capital expenditures, in response to lower commodity prices, were $81.7 million during Q1/2016, representing a decrease of $65.7 million from the $147.4 million spent in Q1/2015. Capital spending focused on our Eagle Ford assets with 94% of total capital being deployed in the U.S. Spending in the U.S. totaled $76.8 million in Q1/2016 where we drilled 12.5 net wells, completed 9.4 net wells and brought 10.2 net wells on-stream. Activity in Canada was significantly reduced in Q1/2016 as we drilled 1.0 net well and spent $4.9 million compared to 9.1 net wells and $21.3 million in Q1/2015.

At the end of Q1/2016, we amended our credit facilities to provide increased financial flexibility. The amendments include reducing our credit facilities to US$575 million, granting our bank lending syndicate first priority security with respect to our assets and restructuring our financial covenants. At March 31, 2016, we were in compliance with all of our financial covenants and $290.5 million was drawn on the facilities leaving approximately $455.0 million in undrawn credit capacity.

RESULTS OF OPERATIONS

The Canadian division includes the heavy oil assets in Peace River and Lloydminster and the conventional oil and natural gas assets in Western Canada. The U.S. division includes the Eagle Ford assets in Texas.

Production
 
Three Months Ended March 31
 
2016
2015
Daily Production
Canada

U.S.

Total

Canada

U.S.

Total

Liquids (bbl/d)











Heavy oil
24,807

—

24,807

39,226

—

39,226

Light oil and condensate
1,566

22,923

24,489

2,091

25,965

28,056

NGL
1,335

8,774

10,109

1,239

6,985

8,224

Total liquids (bbl/d)
27,708

31,697

59,405

42,556

32,950

75,506

Natural gas (mcf/d)
42,003

56,217

98,220

42,255

48,755

91,010

Total production (boe/d)
34,709

41,067

75,776

49,599

41,076

90,675

 






Production Mix






Heavy oil
71
%
—
%
33
%
79
%
—
%
43
%
Light oil and condensate
5
%
56
%
32
%
4
%
63
%
31
%
NGL
4
%
21
%
13
%
3
%
17
%
9
%
Natural gas
20
%
23
%
22
%
14
%
20
%
17
%

Production for Q1/2016 averaged 75,776 boe/d, a 16% decrease from Q1/2015. Canadian production of 34,709 boe/d decreased 30%, or 14,890 boe/d, from Q1/2015 as we shut-in 7,500 boe/d of low or negative margin production throughout the quarter. The shut in volumes reduced average production in the quarter by approximately 5,000 boe/d, with the remainder due to natural declines from reduced capital spending. U.S. production averaged 41,067 boe/d in Q1/2016 and was relatively unchanged from Q1/2015 with continued capital investment in the Eagle Ford offsetting the production declines.


Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 4


Commodity Prices
 
The prices received for our crude oil and natural gas production directly impact our earnings, funds from operations and our financial position.
Crude Oil
For Q1/2016, the WTI oil prompt averaged US$33.45/bbl, a 31% decrease from the average WTI price of US$48.64/bbl in Q1/2015. The low prices experienced during Q1/2016, as compared to Q1/2015, were due to continued oversupply of crude oil and on-going concerns due to the high levels of storage and potential capacity concerns.

The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged US$14.23/bbl for Q1/2016 as compared to US$14.73/bbl in Q1/2015. The improvement in the nominal differential was due to increased pipeline capacity from Canada to the U.S. Gulf Coast, which allows WCS pricing to achieve pipeline equivalency with the large waterborne Gulf Coast refinery market.

Natural Gas
For Q1/2016, the AECO natural gas prices averaged $2.11/mcf, a 28% decrease compared to $2.95/mcf in Q1/2015. For Q1/2016, the NYMEX natural gas price averaged US$2.09/mmbtu, a 30% decrease compared to US$2.98/mmbtu in Q1/2015. The decrease in natural gas prices on both indices between periods was driven by historically high production levels and extremely weak weather related demand.

The following table compares selected benchmark prices and our average realized selling prices for Q1/2016 and Q1/2015.
 
Three Months Ended March 31
 
2016

2015

Change

Benchmark Averages
 
 
 
WTI oil (US$/bbl)(1)
33.45

48.64

(31
)%
WCS heavy oil (US$/bbl)(2)
19.22

33.91

(43
)%
LLS oil (US$/bbl)(3)
33.24

50.55

(34
)%
CAD/USD average exchange rate
1.3748

1.2308

12
 %
Edmonton par oil ($/bbl)
40.80

51.94

(21
)%
AECO natural gas price ($/mcf)(4)
2.11

2.95

(28
)%
NYMEX natural gas price (US$/mmbtu)(5)
2.09

2.98

(30
)%
(1)
WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2)
WCS refers to the average posting price for the benchmark WCS heavy oil.
(3)
LLS refers to the Argus trade month average for Louisiana Light Sweet oil.
(4)
AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(5)
NYMEX refers to the NYMEX last day average index price as published by the CGPR.

 
Three Months Ended March 31
 
2016
2015
 
Canada

U.S.

Total

Canada

 U.S.

Total

Average Sales Prices(1)
 
 
 
 
 
 
Canadian heavy oil ($/bbl)(2)
$
12.54

$
—

$
12.54

$
28.57

$
—

$
28.57

Light oil and condensate ($/bbl)
35.89

38.11

37.97

47.84

52.70

52.34

NGL ($/bbl)
16.91

18.60

18.38

24.18

18.49

19.35

Natural gas ($/mcf)
1.91

2.76

2.40

2.68

3.69

3.22

Weighted average ($/boe)(2)
$
13.55

$
29.02

$
21.93

$
27.50

$
40.84

$
33.54

(1)
Baytex's risk management strategy employs both oil and natural gas financial and physical forward contracts (fixed price forward sales and collars) and heavy oil differential physical delivery contracts (fixed price and percentage of WTI). The pricing information in the table excludes the impact of financial derivatives.
(2)
Realized heavy oil prices are calculated based on sales volumes, net of blending costs.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 5


Average Realized Sales Prices

U.S. light oil and condensate pricing for Q1/2016 was $38.11/bbl, down 28% from $52.70/bbl in Q1/2015, which is consistent with a 27% decrease in the LLS benchmark (expressed in Canadian dollars). During Q1/2016, our Canadian average sales price for light oil and condensate was $35.89/bbl, down 25% from $47.84/bbl in Q1/2015 compared to a 21% decrease in the benchmark Edmonton par price. Our Canadian realized price decreased more than the benchmark as a higher percentage of our Canadian light oil was a lower grade crude than in Q1/2015 which has increased the discount from the benchmark.

Our realized heavy oil priced for Q1/2016 was $12.54/bbl compared to $28.57/bbl received in Q1/2015. The 56% decrease in realized price was more than the 43% decrease in WCS price as the Company's heavy oil is generally sold at a fixed dollar differential to the WCS benchmark price.

Our realized natural gas price for Q1/2016 was $2.40/mcf, down 25% from $3.22/mcf in Q1/2015. This 25% decrease is in line with the decreases in the AECO and NYMEX benchmarks during these periods.

Our realized NGL price was $18.38/bbl or 40% of WTI (expressed in Canadian dollars) in Q1/2016 compared to $19.35/bbl or 32% of WTI (expressed in Canadian dollars) in Q1/2015. Our realized NGL price has increased in the U.S. in 2016 as the terms of certain post-production NGL processing arrangements in the Eagle Ford were changed, which increased both revenues and operating expenses.

Gross Revenues
 
Three Months Ended March 31
 
2016
2015
($ thousands)
Canada

U.S.

Total

Canada

U.S.

Total

Oil revenue












Heavy oil
$
28,308

$
—

$
28,308

$
100,856

$
—

$
100,856

Light oil and condensate
5,114

79,505

84,619

9,001

123,156

132,157

NGL
2,055

14,849

16,904

2,697

11,625

14,322

Total liquids revenue
35,477

94,354

129,831

112,554

134,781

247,335

Natural gas revenue
7,312

14,096

21,408

10,186

16,190

26,376

Total oil and natural gas revenue
42,789

108,450

151,239

122,740

150,971

273,711

Heavy oil blending revenue
2,359

—

2,359

9,673

—

9,673

Total petroleum and natural gas revenues
$
45,148

$
108,450

$
153,598

$
132,413

$
150,971

$
283,384


Total petroleum and natural gas revenues for Q1/2016 of $153.6 million decreased $129.8 million from Q1/2015 with lower commodity prices contributing $80.4 million of the decrease and the remaining $49.4 million from lower production volumes. In Canada, petroleum and natural gas revenues for Q1/2016 totaled $45.1 million, representing a decrease of $87.3 million compared to Q1/2015 with the decrease resulting from lower realized prices and lower production volumes. Petroleum and natural gas revenues of $108.5 million in the U.S. decreased $42.5 million from the prior period due to a decrease in realized prices on all products.

Heavy oil blending revenue of $2.4 million for Q1/2016 decreased $7.3 million compared to Q1/2015. Heavy oil blending revenue decreased as the Company sold less diluent with the decrease in heavy oil production within Canada. Heavy oil transported through pipelines requires blending to reduce its viscosity in order to meet pipeline specifications. The cost of blending diluent is recovered in the sale price of the blended product. Our heavy oil transported by rail does not require blending diluent. The purchases and sales of blending diluent are recorded as heavy oil blending expense and revenue, respectively.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 6


Royalties

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues, or on operating netbacks less capital investment for specific heavy oil projects, and are generally expressed as a percentage of gross revenue. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for Q1/2016 and Q1/2015.
 
Three Months Ended March 31
 
2016
2015
($ thousands except for % and per boe)
Canada

U.S.

Total

Canada

U.S.

Total

Royalties
$
3,835

$
30,747

$
34,582

$
13,419

$
43,288

$
56,707

Average royalty rate(1)
9.0
%
28.4
%
22.9
%
10.9
%
28.7
%
20.7
%
Royalty rate per boe
$
1.21

$
8.23

$
5.02

$
3.01

$
11.71

$
6.95

(1)
Average royalty rate excludes sales of heavy oil blending diluents and the effects of financial derivatives.

Total royalties for Q1/2016 of $34.6 million decreased 39%, or $22.1 million from Q1/2015, due to the decline in gross revenues. The overall royalty rate in Q1/2016 was 22.9% compared to 20.7% in Q1/2015. The royalty rate has increased as proportionately more of the Company's revenue and royalties are from the U.S. which has a higher royalty rate. Canadian royalties decreased to 9.0% of revenue for Q1/2016, compared to 10.9% of revenue in Q1/2015. Canadian crown royalty rates are partially based on price and with the lower commodity prices during Q1/2016 the Company experienced lower crown royalty rates compared to Q1/2015. The Q1/2016 U.S. royalty rate of 28.4% has remained consistent with the Q1/2015 rate of 28.7% and overall royalties have decreased with the decrease in gross revenues.

Operating Expenses
 
Three Months Ended March 31
 
2016
2015
($ thousands except for per boe)
Canada

U.S.(1)

Total

Canada

U.S.(1)

Total

Operating expenses
$
34,645

$
35,035

$
69,680

$
60,574

$
27,181

$
87,755

Operating expenses per boe
$
10.97

$
9.38

$
10.11

$
13.57

$
7.35

$
10.75

(1)
Operating expenses related to the Eagle Ford assets include transportation expenses.

Operating expenses for Q1/2016 of $69.7 million decreased $18.1 million compared to Q1/2015. On a per boe basis, operating expenses for Q1/2016 decreased $0.64/boe to $10.11/boe, compared to $10.75/boe in Q1/2015. Operating expenses per boe have decreased with lower cost Eagle Ford assets comprising a larger percentage of our total production in Q1/2016 as compared to Q1/2015.

Canadian operating expenses of $34.6 million for Q1/2016 decreased $25.9 million compared to Q1/2015. The decrease is a result of lower production volumes and realized cost savings across all of our operations. On a per boe basis, Canadian operating expenses were $10.97/boe in Q1/2016 compared to $13.57/boe in Q1/2015 reflecting the cost savings initiatives during 2016 and the impact of shut-in volumes. As commodity prices improve and the higher cost shut-in volumes are restored, we expect Canadian operating expenses, on a per boe basis, to increase.

U.S. operating expenses were $35.0 million for Q1/2016, a $7.9 million increase compared to Q1/2015. In Q1/2016, the operator of the Eagle Ford property changed certain post-production processing arrangements which increased operating expenses and revenues in the U.S. by approximately $1.00/boe. Operating expenses in the U.S. also increased as the Canadian dollar was weaker against the U.S. dollar in Q1/2016 compared to Q1/2015.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 7


Transportation Expenses

Transportation expenses include the costs to move production from the field to the sales point. The largest component of transportation expenses relates to the trucking of heavy oil to pipeline and rail terminals. The following table compares our transportation expenses for Q1/2016 and Q1/2015.
 
Three Months Ended March 31
 
2016
2015
($ thousands except for per boe)
Canada

U.S.(1)

Total

Canada

U.S.(1)

Total

Transportation expenses
$
6,775

$
—

$
6,775

$
15,949

$
—

$
15,949

Transportation expense per boe
$
2.14

$
—

$
0.98

$
3.57

$
—

$
1.95

(1) Transportation expenses related to the Eagle Ford assets have been included in operating expenses.

Transportation expenses for Q1/2016 totaled $6.8 million ($0.98/boe), a decrease of 58%, or $9.2 million, compared to Q1/2015. The decrease is due to lower heavy oil volumes being transported to the sales point, decreased fuel costs and the increased use of lower cost internal trucking. On a per unit basis, costs have decreased as the volumes shut-in were subject to high transportation charges.

Blending Expenses

Blending expenses for Q1/2016 of $2.4 million have decreased $7.3 million or 76%, compared to Q1/2015. Consistent with the decrease in heavy oil blending revenue, blending expenses decreased due to a decrease in both the volume of blending diluent required and the price of blending diluent.

Financial Derivatives

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 funds from operations. Financial derivatives are managed at the corporate level and are not allocated between divisions. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price. Changes in the fair value of contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for Q1/2016 and Q1/2015.
 
Three Months Ended March 31
($ thousands)
2016

2015

Change

Realized financial derivatives gain (loss)
 
 
 
Crude oil
$
41,492

$
108,027

$
(66,535
)
Natural gas
3,134

5,728

(2,594
)
Foreign currency
—

(11,921
)
11,921

Total
$
44,626

$
101,834

$
(57,208
)
Unrealized financial derivatives gain (loss)
 
 
 
Crude oil
$
(34,987
)
$
(69,579
)
$
34,592

Natural gas
4,864

(4,998
)
9,862

Foreign currency
—

(15,456
)
15,456

Interest and financing(1)
—

1,861

(1,861
)
Total
$
(30,123
)
$
(88,172
)
$
58,049

Total financial derivatives gain (loss)
 
 
 
Crude oil
$
6,505

$
38,448

$
(31,943
)
Natural gas
7,998

730

7,268

Foreign currency
—

(27,377
)
27,377

Interest and financing
—

1,861

(1,861
)
Total
$
14,503

$
13,662

$
841

(1)
Unrealized interest and financing derivatives gain (loss) includes the change in fair value of the call options embedded in our long-term notes.

The realized financial derivatives gain of $44.6 million for Q1/2016, relate mainly to crude oil prices being at levels significantly below those set in our fixed price contracts.

The unrealized loss of $30.1 million for Q1/2016 is mainly due to the realization, or reversal, of previous unrealized gains recorded at December 31, 2015.


Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 8



A summary of the financial derivative contracts in place as at March 31, 2016 and the accounting treatment thereof are disclosed in note 15 to the consolidated financial statements.

Operating Netback

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the periods indicated:
 
Three Months Ended March 31
 
2016
2015
($ per boe except for volume)
Canada

U.S.

Total

Canada

 U.S.

Total

Sales volume (boe/d)
34,709

41,067

75,776

49,599

41,076

90,675

Operating netback:












Oil and natural gas revenues
$
13.55

$
29.02

$
21.93

$
27.50

$
40.84

$
33.54

Less:












Royalties
1.21

8.23

5.02

3.01

11.71

6.95

Operating expenses
10.97

9.38

10.11

13.57

7.35

10.75

Transportation expenses
2.14

—

0.98

3.57

—

1.95

Operating netback
$
(0.77
)
$
11.41

$
5.82

$
7.35

$
21.78

$
13.89

Realized financial derivatives gain
—

—

6.47

—

—

12.48

Operating netback after financial derivatives
$
(0.77
)
$
11.41

$
12.29

$
7.35

$
21.78

$
26.37


Exploration and Evaluation Expense

Exploration and evaluation expense includes the derecognition of exploration and evaluation assets and will vary period to period depending on the expiry of leases and assessment of our exploration programs and assets.

Exploration and evaluation expense decreased to $1.5 million for Q1/2016 from $2.4 million in Q1/2015. The decrease for Q1/2016 is due to lower expiries of undeveloped land.

Depletion and Depreciation
 
Three Months Ended March 31
 
2016
2015
($ thousands except for per boe)
Canada

U.S.

Total

Canada

U.S.

Total

Depletion and depreciation(1)
$
54,785

$
86,139

$
141,671

$
75,117

$
98,384

$
174,127

Depletion and depreciation per boe
$
17.35

$
23.05

$
20.55

$
16.83

$
26.61

$
21.34

(1)
Total includes corporate depreciation.

Depletion and depreciation expense decreased by $32.5 million to $141.7 million for Q1/2016 from $174.1 million in Q1/2015. The depletion rate of $20.55/boe for Q1/2016 decreased from $21.34/boe in Q1/2015 as the Company recognized $755.6 million of impairments on oil and gas properties in 2015 which reduced the depletable base and the depletion rate for 2016.

General and Administrative Expenses
 
Three Months Ended March 31
($ thousands except for % and per boe)
2016

2015

Change

General and administrative expenses
$
14,169

$
17,055

(17
)%
General and administrative expenses per boe
$
2.05

$
2.09

(2
)%

General and administrative expenses for Q1/2016 decreased 17% to $14.2 million from $17.1 million in Q1/2015. The decrease is attributable to reductions in staffing levels to coincide with lower activity levels combined with a reduction in discretionary spending.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 9


Share-Based Compensation Expense

Compensation expense associated with the Share Award Incentive Plan is recognized in income (loss) over the vesting period of the share awards with a corresponding increase in contributed surplus. The issuance of common shares upon the conversion of share awards is recorded as an increase in shareholders’ capital with a corresponding reduction in contributed surplus.

Compensation expense related to the Share Award Incentive Plan decreased to $4.4 million for Q1/2016 from $8.0 million in Q1/2015. The decrease in share-based compensation expense during Q1/2016 is a result of the lower fair value of share awards granted.

Financing and Interest

Financing and interest include interest on bank loan and long-term notes and accretion on long-term notes and asset retirement obligations.
 
Three Months Ended March 31
($ thousands except for %)
2016

2015

Change

Interest on bank loan
$
3,611

$
5,418

(33
)%
Interest on long-term notes
23,200

21,997

5
 %
Accretion on long-term notes
580

377

54
 %
Accretion on asset retirement obligations
1,662

1,618

3
 %
Financing and interest
$
29,053

$
29,410

(1
)%

Financing and interest decreased slightly to $29.1 million for Q1/2016, compared to $29.4 million in Q1/2015. Interest on bank loan of $3.6 million in Q1/2016 decreased from $5.4 million in Q1/2015 due to lower bank borrowings partially offset by a higher effective interest rate. Interest on long-term notes increased slightly to $23.2 million during Q1/2016 compared to $22.0 million in Q1/2015 as the Canadian dollar weakened during the period and approximately 81% of the long-term notes are denominated in U.S. dollars.

Foreign Exchange

Unrealized foreign exchange gains and losses are recognized with the change in the value of the long-term notes denominated in U.S. dollars. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in the Canadian operations.
 
Three Months Ended March 31
($ thousands except for % and exchange rates)
2016

2015

Change

Unrealized foreign exchange (gain) loss
$
(86,801
)
$
101,316

(186
)%
Realized foreign exchange (gain)
(542
)
(4,261
)
(87
)%
Foreign exchange (gain) loss
$
(87,343
)
$
97,055

(190
)%
CAD/USD exchange rates:
 
 
 
At beginning of period
1.3840

1.1601

 
At end of period
1.2971

1.2683

 

The Company recorded unrealized foreign exchange gain of $86.8 million for Q1/2016. This gain related to our U.S. dollar denominated long-term notes that decreased $81.5 million during the quarter as a result of the Canadian dollar strengthening against the U.S. dollar at March 31, 2016 as compared to December 31, 2015. The realized foreign exchange gain for Q1/2016 was due to day-to-day U.S. dollar denominated transactions.

Income Taxes
 
Three Months Ended March 31
($ thousands)
2016

2015

Change

Current income tax (recovery) expense
$
(1,442
)
$
16,935

$
(18,377
)
Deferred income tax (recovery)
(48,122
)
(41,682
)
(6,440
)
Total income tax (recovery)
$
(49,564
)
$
(24,747
)
$
(24,817
)

For Q1/2016, current income tax recovery of $1.4 million increased $18.4 million from an expense of $16.9 million for Q1/2015. The change primarily relates to a decrease in taxable income.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 10


The deferred income tax recovery of $48.1 million for Q1/2016 increased $6.4 million from $41.7 million for Q1/2015. The increase is primarily the result of a decrease in the amount of tax pool claims required to shelter the decreased taxable income.

In 2014, the Canada Revenue Agency (the "CRA”) advised Baytex that it was proposing to reassess certain subsidiaries of Baytex to deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2013. Baytex has filed its 2014 and 2015 income tax returns on the same basis as the 2011 through 2013 tax returns, cumulatively claiming $591 million of non-capital losses. The Company believes that it is entitled to deduct the non-capital losses, that its tax filings to-date are correct, and has formally responded with a letter to the CRA indicating the same. At this time, the CRA has not issued a formal response to Baytex’s letter. The Company expects to continue to defend the position as filed.

Net Income (Loss) and Funds From Operations

Net income for Q1/2016 totaled $0.6 million ($0.00 per basic and diluted share) compared to net loss of $175.9 million ($1.04 per basic and diluted share) in Q1/2015. Funds from operations for Q1/2016 totaled $45.6 million ($0.22 per basic and diluted share) as compared to $160.2 million ($0.95 per basic and diluted share) in Q1/2015. The components of the change in net income (loss) and funds from operations from Q1/2015 to Q1/2016 are detailed in the following table:
($ thousands)
Net income (loss)

Funds from operations

Three Months Ended March 31, 2015
$
(175,916
)
$
160,221

Decrease in
 
 
Operating netback
(73,098
)
(73,098
)
Realized financial derivatives gain
(57,208
)
(57,208
)
Unrealized financial derivatives loss
58,049

—

Depletion and depreciation
32,456

—

Current income tax expense
18,377

18,377

Other expenses(1)(2)
3,390

(2,647
)
Increase in
 
 
Unrealized foreign exchange gain
188,117

—

Deferred income tax (recovery)
6,440

—

Three months ended March 31, 2016
$
607

$
45,645

(1) For funds from operations, other expenses include general and administrative expenses, interest on bank loan and long-term notes, realized foreign exchange loss and other expenses.
(2) For net income (loss), other expenses include exploration and evaluation expenses, general and administrative expenses, other expenses, share-based compensation, financing and interest costs, realized foreign exchange loss and gain on disposition.

Dividends

In Q1/2015, we declared monthly dividends of $0.10 per share for January to March totaling $0.30 per share. The Company paid $40.0 million in cash dividends in Q1/2015, and $10.5 million of dividends declared were settled by issuing 560,000 shares under the Company's dividend reinvestment plan. In response to the prolonged low price commodity environment and in an effort to preserve liquidity, Baytex suspended the monthly dividend effective September 2015.

Other Comprehensive Income (Loss)

Other comprehensive income (loss) is comprised of the foreign currency translation adjustment on U.S. net assets not recognized in profit or loss. The $158.7 million foreign currency translation loss for Q1/2016 is due to the strengthening of the Canadian dollar against the U.S. dollar at March 31, 2016 as compared to December 31, 2015.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 11


Capital Expenditures

Capital expenditures for Q1/2016 and Q1/2015 are summarized as follows:
 
Three Months Ended March 31
 
2016
2015
($ thousands except for # of wells drilled)
Canada

U.S.

Total

Canada

U.S.

Total

Land
$
862

$
—

$
862

$
3,456

$
153

$
3,609

Seismic
55

—

55

59

—

59

Drilling, completion and equipping
3,432

69,684

73,116

11,226

120,997

132,223

Facilities
506

7,146

7,652

6,531

5,007

11,538

Total exploration and development
$
4,855

$
76,830

$
81,685

$
21,272

$
126,157

$
147,429

Total acquisitions, net of divestitures
(9
)
—

(9
)
1,411

139

1,550

Total oil and natural gas expenditures
$
4,846

$
76,830

$
81,676

$
22,683

$
126,296

$
148,979

Wells drilled (net)
1.0

12.5

13.5

9.1

16.0

25.1


Capital spending was focused on our Eagle Ford assets with 94% of total capital being spent in the U.S. where we invested $76.8 million in Q1/2016, as compared to $126.2 million in Q1/2015. In Q1/2016, we drilled 12.5 net wells, completed 9.4 net wells and brought 10.2 net wells on stream in the Eagle Ford. We also participated in the construction of facilities resulting in $7.1 million of expenditures. Total costs in the Eagle Ford have continued to decrease with wells now being drilled, completed and equipped for approximately US$5.6 million as compared to US$8.2 million in 2014.

Activity in Canada was significantly reduced in Q1/2016 as we drilled 1.0 net well and spent $4.8 million, as compared to 9.1 net wells and $21.3 million in Q1/2015. Despite achieving cost reductions of approximately 20% in Canada during 2015, the prevailing commodity prices during Q1/2016 did not support additional drilling on our heavy oil assets in Peace River or Lloydminster.

LIQUIDITY, CAPITAL RESOURCES AND RISK MANAGEMENT

We regularly review our capital structure and liquidity sources to ensure that our capital resources will be sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds from operations and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures.

We regularly review our exposure to counterparties to ensure they have the financial capacity to honor outstanding obligations to us in the normal course of business. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection.

The current commodity price environment has reduced our internally generated funds from operations. As a result, we have taken several steps to protect our liquidity, which included reducing our 2016 capital program by approximately 33% from our initial plans and working with our lending syndicate to secure our bank credit facilities. We have also shut-in low or negative margin production.

If the current commodity price environment continues, or if prices decline further, we may need to make additional changes to our capital program. A sustained low price environment could lead to a default of certain financial covenants, which could impact our ability to borrow under existing credit facilities or obtain new financing. It could also restrict our ability to pay future dividends or sell assets and may result in our debt becoming immediately due and payable. Should our internally generated funds from operations be insufficient to fund the capital expenditures required to maintain operations, we may draw additional funds from our current credit facilities or we may consider seeking additional capital in the form of debt or equity. There is also no certainty that any of the additional sources of capital would be available when required.

At March 31, 2016, net debt was $1,981.3 million, as compared to $2,049.9 million at December 31, 2015. The decrease at March 31, 2016 is primarily attributable to the decrease in our U.S. dollar denominated bank loan and long-term notes of $99 million due to the strengthening Canadian dollar. This was offset by a $34 million increase in credit facilities as capital expenditures exceeded funds from operations during the quarter.

Bank Loan

On March 31, 2016, we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our banking syndicate first priority security over our assets and restructuring our financial covenants. The amended revolving extendible secured credit facilities are comprised of a US$25 million operating loan, a US$350 million syndicated loan and a US$200 million syndicated loan for our wholly-owned subsidiary, Baytex Energy USA, Inc. (collectively, the "Revolving Facilities").

The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants as detailed below and do not require any mandatory principal payments prior to maturity on June 4, 2019. Baytex may request an extension under the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year term at any time). The agreement relating to the Revolving Facilities is accessible on the SEDAR website at www.sedar.com (filed under the category "Material contracts - Credit agreements" on April 13, 2016).

The weighted average interest rate on the credit facilities for Q1/2016 was 3.5% as compared to 2.8% in Q1/2015.

Covenants

On March 31, 2016, we reached an agreement with the lending syndicate to restructure the financial covenants applicable to the Revolving Facilities. The following table summarizes the financial covenants contained in the amended credit agreement and our compliance therewith as at March 31, 2016.
 
 
Ratio for the Quarter(s) ending:
Covenant Description
Position as at March 31, 2016
March 31, 2016 to March 31, 2018
June 30, 2018 to September 30, 2018
December 31, 2018
Thereafter
Senior Secured Debt (1) to Bank EBITDA (2)
(Maximum Ratio)
0.61:1.00
5.00:1.00
4.50:1.00
4.00:1.00
3.50:1.00
Interest Coverage (3) 
(Minimum Ratio)
4.82:1.00
1.25:1.00
1.50:1.00
1.75:1.00
2.00:1.00
(1)
"Senior secured debt" is defined as the principal amount of our bank loan and other secured obligations identified in the credit agreement. As at March 31, 2016, our Senior Secured Debt totaled $303 million.
(2)
Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income (loss) for financing and interest costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange and stock based compensation) and is calculated based on a trailing twelve month basis. Bank EBITDA is calculated based on a trailing twelve month basis and was $495 million for the twelve months ended March 31, 2016.
(3)
Interest coverage is computed as the ratio of Bank EBITDA to financing and interest excluding accretion on long-term notes and asset retirement obligations to trailing twelve month adjusted income. Financing and interest for the trailing twelve months ended March 31, 2016 was $103 million.

If we exceed or breach any of the covenants under the Revolving Facilities or our long-term notes, we may be required to repay, refinance or renegotiate the loan terms and may be restricted from paying dividends to our shareholders or taking on further debt.

Long-Term Notes

Baytex has five series of senior unsecured notes outstanding that total $1.54 billion as at March 31, 2016. The senior unsecured notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts our ability to raise additional debt beyond our existing credit facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of EBITDA to financing and interest costs) of 2.5:1.

On February 17, 2011, we issued US$150 million principal amount of senior unsecured notes bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. These notes are redeemable at our option, in whole or in part, commencing on February 17, 2016 at specified redemption prices.

On July 19, 2012, we issued $300 million principal amount of senior unsecured notes bearing interest at 6.625% payable semi-annually with principal repayable on July 19, 2022. These notes are redeemable at our option, in whole or in part, commencing on July 19, 2017 at specified redemption prices.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "2021 Notes") and US$400 million of 5.625% notes due June 1, 2024 (the "2024 Notes"). The 2021 Notes and the 2024 Notes pay interest semi-annually and are redeemable at the Company's option, in whole or in part, commencing on June 1, 2017 (in the case of the 2021 Notes) and June 1, 2019 (in the case of the 2024 Notes) at specified redemption prices.

Pursuant to the acquisition of Aurora Oil & Gas Limited ("Aurora") on June 11, 2014, we assumed all of Aurora's existing senior unsecured notes and then purchased and cancelled approximately 98% of the outstanding notes. On February 27, 2015, we redeemed one tranche of the remaining Aurora notes at a price of US$8.3 million plus accrued interest. The remaining Aurora notes (US$6.4 million principal amount) are redeemable at our option, in whole or in part, commencing on April 1, 2016 at specified redemption prices.

Financial Instruments

As part of our normal operations, we are exposed to a number of financial risks, including liquidity risk, credit risk and market risk. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. We manage liquidity risk through cash and debt management. Credit risk is the risk that a counterparty to a financial asset will default, resulting in the Company incurring a loss. Credit risk is managed by entering into sales contracts with creditworthy entities and reviewing our exposure to individual entities on a regular basis. Market risk is the risk that the fair value of future cash flows will fluctuate due to movements in market prices, and is comprised of foreign currency risk, interest rate risk and commodity price risk. Market risk is partially mitigated through a series of derivative contracts intended to reduce some of the volatility of our funds from operations.

A summary of the risk management contracts in place as at March 31, 2016 and the accounting treatment thereof is disclosed in note 15 to the consolidated financial statements.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. The rights and terms of preferred shares are determined upon issuance. As at April 30, 2016, we had 210,714,772 common shares and no preferred shares issued and outstanding. During Q1/2016, we issued 106,000 shares pursuant to our share-based compensation program.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s funds from operations in an ongoing manner. A significant portion of these obligations will be funded by funds from operations. These obligations as of March 31, 2016 and the expected timing for funding these obligations are noted in the table below.
($ thousands)
Total

Less than 1 year

1-3 years

3-5 years

Beyond 5 years

Trade and other payables
$
228,575

$
228,575

$
—

$
—

$
—

Bank loan(1) (2)
290,465

—

—

290,465

—

Long-term notes(2)
1,540,546

—

—

202,866

1,337,680

Interest on long-term notes
502,936

76,273

152,546

151,304

122,813

Operating leases
47,949

7,987

16,394

15,208

8,360

Processing agreements
50,004

9,010

9,521

9,043

22,430

Transportation agreements
68,211

13,193

23,107

21,903

10,008

Total
$
2,728,686

$
335,038

$
201,568

$
690,789

$
1,501,291

(1)
The bank loan is covenant-based with a revolving period that is extendible annually for up to a four-year term. Unless extended, the revolving period will end on June 4, 2019, with all amounts to be repaid on such date.
(2)
Principal amount of instruments.

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

OFF BALANCE SHEET TRANSACTIONS

Baytex does not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2016, nor are any such arrangements outstanding as of the date of this MD&A.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Baytex is required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". The certificate requires Baytex to disclose in the interim MD&A any weaknesses in or changes to Baytex's internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, Baytex's internal controls over financial reporting. We confirm that no such weaknesses were identified in or changes were made to internal controls over financial reporting during the three months ended March 31, 2016.



Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 12


QUARTERLY FINANCIAL INFORMATION

 
2016
2015
2014
($ thousands, except per common share amounts)
Q1

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Gross revenues
153,598

229,361

265,898

342,792

283,384

465,917

634,400

475,973

Net income (loss)
607

(412,924
)
(517,856
)
(26,955
)
(175,916
)
(361,816
)
144,369

36,799

Per common share - basic
0.00

(1.96
)
(2.49
)
(0.13
)
(1.04
)
(2.16
)
0.87

0.27

Per common share - diluted
0.00

(1.96
)
(2.49
)
(0.13
)
(1.04
)
(2.16
)
0.86

0.27


FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document 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 document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; our exploration and development capital budget for 2016; our belief that the amended credit facilities provide increased financial flexibility; crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our expectation for Canadian operating expenses for the remainder of 2016; our ability to reduce the volatility in our funds from operations by utilizing financial derivative contracts; the proposed reassessment of our tax filings by the Canada Revenue Agency; the potential taxes owing and reduction of non-capital losses if the reassessment by the Canada Revenue Agency is successful; our intention to defend the proposed reassessments if issued by the Canada Revenue Agency; our view of our tax filing position; the cost to drill, complete and equip a well in the Eagle Ford; the sufficiency of our capital resources to meet our on-going short, medium and long-term commitments; the financial capacity of counterparties to honor outstanding obligations to us in the normal course of business; and the existence, operation and strategy of our risk management program. 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.

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 natural gas prices; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; 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; risks related to the accessibility, availability, proximity and capacity 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; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; 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

Baytex Energy Corp.                                            
Q1 2016 MD&A    Page 13


and Analysis for the year ended December 31, 2015, 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.





Exhibit 99.3

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE

 I, James L. Bowzer, President and Chief Executive Officer of Baytex Energy Corp., certify the following:
1.
Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Baytex Energy Corp. (the "issuer") for the interim period ended March 31, 2016.
2.
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
(a)
designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)
material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)
information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)
designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1
Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is COSO, the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.
5.2
ICFR - material weakness relating to design: N/A
5.3
Limitation on scope of design: N/A
5.4
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2016 and ended on March 31, 2016 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.





Date: May 3, 2016

/s/ James L. Bowzer            
James L. Bowzer
President and Chief Executive Officer
Baytex Energy Corp.





Exhibit 99.4

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE

 I, Rodney D. Gray, Chief Financial Officer of Baytex Energy Corp., certify the following:
1.
Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Baytex Energy Corp. (the "issuer") for the interim period ended March 31, 2016.
2.
No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.
Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.
Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.
Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
(a)
designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)
material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)
information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)
designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1
Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is COSO, the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.
5.2
ICFR - material weakness relating to design: N/A
5.3
Limitation on scope of design: N/A
5.4
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2016 and ended on March 31, 2016 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.





Date: May 3, 2016


/s/ Rodney D. Gray        
Rodney D. Gray
Chief Financial Officer
Baytex Energy Corp.





Exhibit 99.5

BAYTEX REPORTS Q1 2016 RESULTS

CALGARY, ALBERTA (May 3, 2016) - Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its operating and financial results for the three months ended March 31, 2016 (all amounts are in Canadian dollars unless otherwise noted).

“We continue to meet the challenges brought on by this low oil price environment head on. During the first quarter, we announced amendments to our bank credit facilities that provide us with increased financial flexibility and we shut-in low or negative margin heavy oil production. To generate the highest netback and rate of return, we focused our capital expenditures on the Eagle Ford. Our operating results in the Eagle Ford were strong during the quarter with production up 2% over Q4/2015 and well costs continuing to decline. We remain well positioned to benefit from an oil price recovery as our three core plays provide some of the strongest capital efficiencies in North America,” commented James Bowzer, President and Chief Executive Officer.

Highlights
•
Generated production of 75,776 boe/d (78% oil and NGL) in Q1/2016;
•
Delivered funds from operations ("FFO") of $45.6 million ($0.22 per share) in Q1/2016;
•
Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q1/2016 of $5.82/boe ($12.29/boe including financial derivatives gain);
•
Produced 41,067 boe/d in the Eagle Ford, an increase of 2% from Q4/2015 and 5% from Q3/2015;
•
Advanced the multi-zone potential of our Sugarkane acreage with 19 wells establishing an average 30-day initial production rate of approximately 1,300 boe/d;
•
Amended our bank credit facilities and financial covenants to provide increased financial flexibility; and
•
Maintained strong levels of financial liquidity with a Senior Secured Debt to Bank EBITDA ratio of 0.61:1.00.

 
Three Months Ended
 
March 31, 2016

December 31, 2015

March 31, 2015

FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
 
 
 
Petroleum and natural gas sales
$
153,598

$
229,361

$
283,384

Funds from operations (1)
45,645

93,095

160,221

Per share - basic
0.22

0.44

0.95

Per share - diluted
0.22

0.44

0.95

Net income (loss)
607

(412,924
)
(175,916
)
Per share - basic
0.00

(1.96
)
(1.04
)
Per share - diluted
0.00

(1.96
)
(1.04
)
Exploration and development
81,685

140,796

147,429

Acquisitions, net of divestitures
(9
)
(574
)
1,550

Total oil and natural gas capital expenditures
$
81,676

$
140,222

$
148,979

 






Bank loan (2)
$
290,465

$
256,749

$
780,447

Long-term notes (2)
1,540,546

1,623,658

1,513,002

Working capital deficiency
150,332

169,498

162,546

Net debt (3)
$
1,981,343

$
2,049,905

$
2,455,995



Baytex Energy Corp.
Press Release - May 3, 2016
Page 2

 
Three Months Ended
 
March 31, 2016

December 31, 2015

March 31, 2015

OPERATING
 
 
 
Daily production
 
 
 
Heavy oil (bbl/d)
24,807

31,733

39,226

Light oil and condensate (bbl/d)
24,489

24,930

28,056

NGL (bbl/d)
10,109

8,996

8,224

Total oil and NGL (bbl/d)
59,405

65,659

75,506

Natural gas (mcf/d)
98,220

92,708

91,010

Oil equivalent (boe/d @ 6:1) (5)
75,776

81,110

90,675

 
 
 
 
Benchmark prices
 
 
 
WTI oil (US$/bbl)
33.45

42.18

48.64

WCS heavy oil (US$/bbl)
19.22

27.69

33.91

Edmonton par oil ($/bbl)
40.80

52.94

51.94

LLS oil (US$/bbl)
33.24

43.33

50.55

 
 
 
 
Baytex average prices (before hedging)
 
 
 
Heavy oil ($/bbl) (6)
12.54

24.41

28.57

Light oil and condensate ($/bbl)
37.97

50.17

52.34

NGL ($/bbl)
18.38

17.23

19.35

Total oil and NGL ($/bbl)
24.02

33.21

36.40

Natural gas ($/mcf)
2.40

2.76

3.22

Oil equivalent ($/boe)
21.93

30.03

33.54

 
 
 
 
CAD/USD noon rate at period end
1.2971

1.3840

1.2683

CAD/USD average rate for period
1.3748

1.3353

1.2308

COMMON SHARE INFORMATION
 
 
 
TSX
 
 
 
Share price (Cdn$)
 
 
 
High
5.39

6.88

24.87

Low
1.57

3.50

16.03

Close
5.13

4.48

20.03

Volume traded (thousands)
483,311

283,619

122,179

 
 
 
 
NYSE
 
 
 
Share price (US$)
 
 
 
High
4.15

5.27

19.99

Low
1.08

2.50

13.14

Close
3.97

3.24

15.80

Volume traded (thousands)
154,052

153,763

24,213

Common shares outstanding (thousands)
210,689

210,583

169,001

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 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, 2016.
(2)
Principal amount of instruments.
(3)
Total net 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 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.


Baytex Energy Corp.
Press Release - May 3, 2016
Page 3

Operations Review

Our operating results for the first quarter were consistent with our expectations and reflect a reduced pace of drilling activity in response to the low crude oil price environment. Production of 75,776 boe/d (78% oil and NGL) in Q1/2016 exceeded our first quarter guidance range of 73,000 to 75,000 boe/d, due largely to continued strong operating results in the Eagle Ford. Capital expenditures for exploration and development activities totaled $81.7 million in Q1/2016 and included the drilling of 45 (13.5 net) wells with a 100% success rate.

During the first quarter, we pro-actively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production in order to optimize the value of our resource base and maximize our funds from operations. Should netbacks improve, we have the ability to restart these wells within one month.

Our 2016 production guidance remains at 68,000 to 72,000 boe/d with budgeted exploration and development expenditures of $225 to $265 million. In 2016, we are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings. Our 2016 program will remain flexible and allows for adjustments to spending based on changes in the commodity price environment. In addition, we may contemplate minor non-core asset sales.

Wells Drilled - Three Months Ended March 31, 2016
 
 
 
Stratigraphic
Dry and
 
 
Crude Oil
Natural Gas
and Service
Abandoned
Total
 
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
 
 
 
 
 
 
 
 
 
 
 
Heavy oil
 
 
 
 
 
 
 
 
 
 
Lloydminster
—

—

—

—

—

—

—

—

—

—

Peace River
—

—

—

—

—

—

—

—

—

—

 
—

—

—

—

—

—

—

—

—

—

Light oil and natural gas
 
 
 
 
 
 
 
 
 
 
Eagle Ford
6

1.9

38

10.6

—

—

—

—

44

12.5

Western Canada
—

—

1

1.0

—

—

—

—

1

1.0

 
6

1.9

39

11.6

—

—

—

—

45

13.5

Total
6

1.9

39

11.6

—

—

—

—

45

13.5


Our performance in the Eagle Ford was strong during the first quarter with production averaging 41,067 boe/d (77% liquids), an increase of 2% from Q4/2015 and 5% from Q3/2015. Capital expenditures totaled $76.8 million in the Eagle Ford, representing 96% of our exploration and development spending during the quarter. Our pace of development in the Eagle Ford was largely unchanged during the first quarter with approximately six drilling rigs and one frac crew working on our lands. At March 31, 2016, we had 36 (10.7 net) wells waiting on completion.

Significant advancements have been made in the past twelve months to delineate the multi-zone potential of our Sugarkane acreage and we continue to monitor “stack and frac” pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation. A recent five-well pad that targeted the Austin Chalk and Upper Eagle Ford formations delivered an average 30-day initial production rate per well of approximately 1,350 boe/d. We currently have 13 multi-zone projects in various stages of execution and production.

In the Eagle Ford in Q1/2016, we participated in the drilling of 44 (12.5 net) wells and commenced production from 34 (10.2 net) wells. Of the 34 wells that commenced production during the first quarter, 19 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,300 boe/d. To-date, we have achieved an approximate 32% reduction in well costs in the Eagle Ford - with wells now being drilled, completed and equipped for approximately US$5.6 million, as compared to US$8.2 million in 2014.

Production in Canada averaged 34,709 boe/d (80% oil and NGL) during Q1/2016 as compared to 40,826 boe/d in Q4/2015. The reduced volumes in Canada reflect the impact of production that was shut-in during the first quarter and the fact there has been no heavy oil drilling since Q3/2015. Capital expenditures for our Canadian assets in Q1/2016 totaled $4.8 million, a decrease from $8.8 million in Q4/2015, and included the drilling of one (1.0 net) liquids-rich natural gas well in the Pembina/O’Chiese region of west-central Alberta.

Financial Review

The first quarter of 2016 was challenging as the global oversupply of crude oil continued to weigh on the market, with crude oil prices hitting a low of US$26/bbl in February. The sharp reduction in crude oil prices had a significant impact on our FFO, which totaled $45.6 million ($0.22 per share) in Q1/2016, as compared to $93.1 million ($0.44 per share) in Q4/2015.

In Q1/2016, the average price for West Texas Intermediate light oil (“WTI”) averaged US$33.45/bbl, as compared to US$42.18/bbl in Q4/2015. This 21% decline in the benchmark index resulted in our realized price for light oil and condensate decreasing 24% to $37.97/bbl. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$14.23/bbl in Q1/2016, as compared to US$14.49/bbl in Q4/2015. The lower WTI price in Q1/2016 resulted in a 31% decrease in the price of WCS and a 49% decrease in our realized heavy oil price to $12.54/bbl, as compared to Q4/2015.

We generated an operating netback in Q1/2016 of $5.82/boe ($12.29/boe including financial derivatives gain). The Eagle Ford generated an operating netback of $11.41/boe while our Canadian operations generated an operating loss of $0.77/boe. In Canada, 71% of our production during the quarter was weighted to heavy oil, where price realizations were particularly weak. As a result, we proactively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production during the first quarter. With WTI currently trading above US$40/bbl, our operating netback in Canada has improved from that reported in the first quarter.

In the Eagle Ford, our assets are located in south Texas, proximal to Gulf Coast markets, with light oil and condensate production priced off a Louisiana Light Sweet crude oil benchmark which typically trades at a premium to WTI. Declining production in the region has increased competition for field supplies resulting in lower transportation and gathering costs and improved price realizations. This relative pricing, combined with low cash costs, contributed positively to our operating netback. During the quarter, the terms of certain post-production NGL processing arrangements in the Eagle Ford were changed, which increased both revenues and operating expenses by approximately $1.00/boe.

During the quarter, we continued to focus on cost reduction initiatives across all of our operations. Operating expenses in Canada decreased 19% on a per boe basis as compared to Q1/2015, despite the impact of fixed costs on lower production volumes. Transportation expenses in Canada have been reduced by 40% on a per boe basis as compared to Q1/2015, due to ongoing optimization within our trucking division and decreased fuel costs.

The following table provides a summary of our operating netbacks for the periods noted.
 
Three Months Ended March 31
 
2016
2015
($ per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Sales Price
$
13.55

$
29.02

$
21.93

$
27.5

$
40.84

$
33.54

Less:
 
 
 
 
 
 
Royalties
1.21

8.23

5.02

3.01

11.71

6.95

Production and operating expenses
10.97

9.38

10.11

13.57

7.35

10.75

Transportation expenses
2.14

—

0.98

3.57

—

1.95

Operating netback
$
(0.77
)
$
11.41

$
5.82

$
7.35

$
21.78

$
13.89

Financial derivatives gain
—

—

6.47

—

—

12.48

Operating netback after financial derivatives
$
(0.77
)
$
11.41

$
12.29

$
7.35

$
21.78

$
26.37



General and administrative expenses were $14.2 million in Q1/2016, as compared to $17.1 million in Q1/2015. 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 a continued cost control measure, all full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective March 1, 2016.

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 $44.6 million in Q1/2016, primarily due to crude oil prices being at levels significantly below those set in our financial derivative contracts.

For the balance of 2016, we have entered into hedges on approximately 44% of our net WTI exposure with 17% fixed at US$62.03/bbl and 27% hedged utilizing a 3-way option structure (as described in note 2 to the table below). We have also entered into hedges on approximately 38% of our net WCS differential exposure and 58% of our net natural gas exposure.

For 2017, we have entered into hedges on approximately 28% of our net WTI exposure hedged utilizing a 3-way option structure (as described in note 2 to the table below). We have also entered into hedges on approximately 8% of our net WCS differential exposure and 32% of our net natural gas exposure.

The unrealized financial derivatives gain with respect to our hedges as at April 26, 2016 was approximately $54 million. The following table summarizes our hedges in place as at May 3, 2016.


 
Q2/2016
Q3/2016
Q4/2016
Balance of 2016
Full-Year 2017
CRUDE OIL
 
 
 
 
 
WTI Fixed Hedges
 
 
 
 
 
Volumes (bbl/d)
8,000

5,000

5,000

6,000

—

Price (US$/bbl)
$59.84
$63.79
$63.79
$62.03
—

 
 
 
 
 
 
WTI 3-Way Option
 
 
 
 
 
Volumes (bbl/d)
9,500

10,000

10,000

9,833

10,000

Average Ceiling/Floor/Sold Floor (US$/bbl) (2)
$60/$50/$40

$60/$50/$40

$60/$50/$40

$60/$50/$40

$59/$46/$36

 
 
 
 
 
 
Total WTI Hedge Volumes (bbl/d)
17,500

15,000

15,000

15,833

10,000

Hedge (%) (1)
49
%
42
%
42
%
44
%
28
%
 
 
 
 
 
 
WCS Differential Hedges
 
 
 
 
 
Volumes (bbl/d)
8,000

7,000

7,000

7,333

1,500

WCS Price Relative to WTI (US$/bbl)
($13.26)

($13.32)

($13.40)

($13.32)

($13.42)

Hedge (%) (1)
42
%
37
%
37
%
38
%
8
%
 
 
 
 
 
 
NATURAL GAS
 
 
 
 
 
AECO Fixed Hedges
 
 
 
 
 
Volumes (GJ/d)
28,333

32,500

32,500

31,111

10,000

Price ($/GJ)
$2.01
$2.01
$1.75
$1.92
2.65

 
 
 
 
 
 
NYMEX Fixed Hedges
 
 
 
 
 
Volumes (mmbtu/d)
15,000

15,000

15,000

15,000

15,000

Price (US$/mmbtu)
$2.98
$2.98
$2.98
$2.98
2.79

 
 
 
 
 
 
Total Hedge Volume (mmbtu/d)
41,855

45,804

45,804

44,488

24,478

Hedge (%) (1)
55
%
60
%
60
%
58
%
32
%
 
 
 
 
 
 
Notes:
 
 
 
 
 
(1)  Percentage of hedged volumes is based on the mid-point of our 2016 production guidance (excluding NGL), net of royalties.
(2)  WTI 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

Total long-term debt at March 31, 2016 was $1.83 billion, comprised of a bank loan of $290 million and senior unsecured notes of $1.54 billion. The decrease in total long-term debt at March 31, 2016, as compared to December 31, 2015, was due to an increase in the Canada-U.S. dollar exchange rate which resulted in the principal amount of our U.S. dollar denominated debt decreasing when converted to Canadian dollars. Our U.S. dollar long-term notes total US$956 million with no material maturities until 2021 and our Canadian dollar long-term notes total C$300 million and mature in 2022. These long-term notes contain no material financial maintenance covenants.

On March 31, 2016, we announced amendments to our bank credit facilities that provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our bank lending syndicate first priority security with respect to our assets and restructuring our financial covenants. These facilities are not borrowing base facilities and do not require annual or semi-annual reviews. There are no mandatory principal payments prior to maturity in June 2019 and the maturity date can be further extended with the consent of our bank lending syndicate. With this revised agreement, we expect to realize savings of approximately $8 million in 2016 from lower interest expense and standby fees.

The following table summarizes the financial covenants contained in the amended credit agreement and our compliance therewith as at March 31, 2016.
 
 
Ratio for the Quarter(s) ending:
Covenant Description
Position as at March 31, 2016
March 31, 2016 to March 31, 2018
June 30, 2018 to Sept. 30, 2018
Dec. 31, 2018
Thereafter
Senior Secured Debt (1)  to Bank EBITDA (2) (Maximum Ratio)
0.61:1.00
5.00:1.00
4.50:1.00
4.00:1.00
3.50:1.00
Interest Coverage (3) (Minimum Ratio)
4.72:1.00
1.25:1.00
1.50:1.00
1.75:1.00
2.00:1.00
Notes:

(1) 
“Senior Secured Debt” is defined as the principal amount of our bank loan and other secured obligations under the credit facilities. At March 31, 2016, our Senior Secured Debt totaled $303 million.
(2) 
“Bank EBITDA” is calculated based on terms and conditions set out in the credit agreement which adjusts net income for interest expense, income taxes, certain non-cash items and acquisition and disposition activity. Bank EBITDA is calculated based on a trailing twelve month basis and was $495 million for the twelve months ended March 31, 2016.
(3) 
“Interest Coverage” is computed as the ratio of Bank EBITDA to interest expense on our Senior Secured Debt and long-term notes. Interest expense for the trailing twelve months ended March 31, 2016 was $105 million.

With these amendments to our bank credit facilities, we expect to have adequate liquidity and financial flexibility to execute our business plan. In addition, we are well positioned to benefit from an oil price recovery as our three core plays provide some of the strongest capital efficiencies in North America.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016 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. MDT (11:00 a.m. EDT)
Baytex will host a conference call today, May 3, 2016, starting at 9:00am MDT (11:00am EDT). 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/7374 in your web browser.

An archived recording of the conference call will be available until May 10, 2016 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 6106828. 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; with respect to the shut-in of certain heavy oil production, our expectation that it will preserve the value of our resource base and maximize our funds from operations and the time required to re-start such production; our expectations for annual average production rate and exploration and development capital expenditures for 2016; our target for 2016 capital expenditures to approximate funds from operations in order to minimize additional bank borrowings; the possibility of non-core asset sales; our Eagle Ford shale play, including our assessment of the performance of wells drilled in Q1/2016, 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, and the cost to drill, complete and equip a well; 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 partially reduce the volatility in our funds from operations by utilizing financial derivative contracts; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in reducing the volatility in our funds from operations; our liquidity and financial capacity; our belief that the revised credit agreement provides us with increased financial flexibility; the amount that we will save in 2016 on interest expense and standby fees as a result of the amendments to our credit agreement; and our belief that we have adequate liquidity and financial flexibility to execute our business plan, that we are well positioned to benefit from an oil price recovery and that our three core plays provide some of the strongest capital efficiencies in North America. 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.

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 natural gas prices; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; 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; risks related to the accessibility, availability, proximity and capacity 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; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; 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, 2015, 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 as 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 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 our credit agreements governing our revolving credit facilities. This measure 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.

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 78% 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




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