EX-99.1 2 ex991q32018fs.htm EXHIBIT 99.1 Exhibit
Baytex Energy Corp.
Condensed Consolidated Statements of Financial Position
(thousands of Canadian dollars) (unaudited)
As at
September 30, 2018

December 31, 2017

 
 
 
ASSETS
 
 
Current assets
 
 
Cash
$
45,159

$
—

Trade and other receivables
178,167

112,844

Financial derivatives (note 18)
5,725

18,510

 
229,051

131,354

Non-current assets
 
 
Financial derivatives (note 18)
489

—

Exploration and evaluation assets (note 6)
365,235

272,974

Oil and gas properties (note 7)
5,887,126

3,958,309

Other plant and equipment
9,402

9,474

 
$
6,491,303

$
4,372,111

 
 
 
LIABILITIES
 
 
Current liabilities
 
 
Trade and other payables
$
317,118

$
144,542

Financial derivatives (note 18)
98,522

50,095

Onerous contracts
2,135

2,574

 
417,775

197,211

Non-current liabilities
 
 
Bank loan (note 8)
488,804

212,138

Long-term notes (note 9)
1,514,459

1,474,184

Asset retirement obligations (note 10)
553,624

368,995

Deferred income tax liability
351,977

204,698

Financial derivatives (note 18)
9,965

—

 
3,336,604

2,457,226

 
 
 
SHAREHOLDERS’ EQUITY
 
 
Shareholders' capital (note 11)
5,701,527

4,443,576

Contributed surplus
14,837

15,999

Accumulated other comprehensive income
540,200

463,104

Deficit
(3,101,865
)
(3,007,794
)
 
3,154,699

1,914,885

 
$
6,491,303

$
4,372,111


See accompanying notes to the condensed consolidated interim unaudited 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 September 30
Nine Months Ended September 30
 
2018

2017

2018

2017

 
 
 
 
 
Revenue, net of royalties
 
 
 
 
Petroleum and natural gas sales (note 12)
$
436,761

$
258,620

$
1,070,433

$
796,706

Royalties
(91,945
)
(55,176
)
(233,989
)
(172,367
)
 
344,816

203,444

836,444

624,339

 
 
 
 
 
Expenses
 
 
 
 
Operating
77,698

64,391

213,735

199,446

Transportation
9,520

9,312

25,875

26,327

Blending and other
19,548

16,069

55,077

42,554

General and administrative
10,158

11,074

31,729

37,672

Transaction costs (note 4)
13,066

—

13,066

—

Exploration and evaluation (note 6)
510

497

3,887

5,505

Depletion and depreciation
144,501

117,670

364,654

371,156

Share-based compensation (note 13)
7,180

2,469

15,010

12,611

Financing and interest (note 16)
30,029

27,498

86,825

85,296

Financial derivatives loss (gain) (note 18)
30,900

18,350

135,243

(33,417
)
Foreign exchange loss (gain) (note 17)
(20,943
)
(42,475
)
40,023

(86,016
)
(Gain) loss on disposition of oil and gas properties
(34
)
6,068

(1,764
)
6,592

Other (income) expense
(302
)
283

(869
)
1,192

 
321,831

231,206

982,491

668,918

Net income (loss) before income taxes
22,985

(27,762
)
(146,047
)
(44,579
)
Income tax expense (recovery) (note 15)
 
 
 
 
Current income tax expense (recovery)
—

(48
)
(71
)
(1,489
)
Deferred income tax expense (recovery)
(4,427
)
(18,486
)
(51,905
)
(54,226
)
 
(4,427
)
(18,534
)
(51,976
)
(55,715
)
Net income (loss) attributable to shareholders
$
27,412

$
(9,228
)
$
(94,071
)
$
11,136

Other comprehensive income (loss)
 
 
 
 
Foreign currency translation adjustment
(39,360
)
(85,483
)
77,096

(165,809
)
Comprehensive income (loss)
$
(11,948
)
$
(94,711
)
$
(16,975
)
$
(154,673
)
 
 
 
 
 
Net income (loss) per common share (note 14)
 
 
 
 
Basic
$
0.07

$
(0.04
)
$
(0.33
)
$
0.05

Diluted
$
0.07

$
(0.04
)
$
(0.33
)
$
0.05

 
 
 
 
 
Weighted average common shares (note 14)
 
 
 
 
Basic
375,435

235,451

283,302

234,563

Diluted
378,763

235,451

283,302

237,203


See accompanying notes to the condensed consolidated interim unaudited 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

Deficit

Total equity

Balance at December 31, 2016
$
4,422,661

$
21,405

$
629,863

$
(3,094,968
)
$
1,978,961

Vesting of share awards
20,914

(20,914
)
—

—

—

Share-based compensation
—

12,611

—

—

12,611

Comprehensive income (loss) for the period
—

—

(165,809
)
11,136

(154,673
)
Balance at September 30, 2017
$
4,443,575

$
13,102

$
464,054

$
(3,083,832
)
$
1,836,899

Balance at December 31, 2017
$
4,443,576

$
15,999

$
463,104

$
(3,007,794
)
$
1,914,885

Issued on corporate acquisition (note 4)
1,238,995

3,100

—

—

1,242,095

Issuance costs, net of tax (notes 4 and 11)
(316
)
—

—

—

(316
)
Vesting of share awards
19,272

(19,272
)
—

—

—

Share-based compensation
—

15,010

—

—

15,010

Comprehensive income (loss) for the period
—

—

77,096

(94,071
)
(16,975
)
Balance at September 30, 2018
$
5,701,527

$
14,837

$
540,200

$
(3,101,865
)
$
3,154,699


See accompanying notes to the condensed consolidated interim unaudited financial statements.
 

Page 3


Baytex Energy Corp.
Condensed Consolidated Statements of Cash Flows
(thousands of Canadian dollars) (unaudited)
 
Three Months Ended September 30
Nine Months Ended September 30
 
2018

2017

2018

2017

 
 
 
 
 
CASH PROVIDED BY (USED IN):
 
 
 
 
Operating activities
 
 
 
 
Net income (loss) for the period
$
27,412

$
(9,228
)
$
(94,071
)
$
11,136

Adjustments for:
 
 
 
 
Share-based compensation (note 13)
7,180

2,469

15,010

12,611

Unrealized foreign exchange loss (gain) (note 17)
(20,583
)
(44,006
)
38,136

(87,389
)
Exploration and evaluation (note 6)
510

497

3,887

5,505

Depletion and depreciation
144,501

117,670

364,654

371,156

Non-cash financing and accretion (note 16)
3,686

2,972

10,441

9,664

Unrealized financial derivatives loss (gain) (note 18)
46

21,145

65,140

(27,698
)
(Gain) loss on disposition of capital properties
(34
)
6,068

(1,764
)
6,592

Deferred income tax recovery
(4,427
)
(18,486
)
(51,905
)
(54,226
)
Payments on onerous contracts
(147
)
(1,761
)
(439
)
(5,506
)
Asset retirement obligations settled (note 10)
(3,028
)
(1,754
)
(9,215
)
(9,649
)
Change in non-cash working capital
(1,025
)
2,326

(23,633
)
(3,311
)
 
154,091

77,912

316,241

228,885

 
 
 
 
 
Financing activities
 
 
 
 
Increase (decrease) in bank loan
(38,305
)
(33,153
)
(43,348
)
46,328

Common share issuance costs (notes 4 and 11)
(433
)
—

(433
)
—

Redemption of long-term notes
—

(8,580
)
—

(8,580
)
 
(38,738
)
(41,733
)
(43,781
)
37,748

 
 
 
 
 
Investing activities
 
 
 
 
Additions to exploration and evaluation assets (note 6)
(2,462
)
(507
)
(3,864
)
(5,344
)
Additions to oil and gas properties (note 7)
(136,733
)
(61,037
)
(307,695
)
(230,766
)
Additions to other plant and equipment
(1,395
)
108

(1,902
)
(510
)
Property acquisitions
—

—

(187
)
(71,610
)
Proceeds from disposition of capital properties (notes 6 & 7)
—

7,436

2,234

7,816

Change in non-cash working capital
70,396

16,000

84,113

31,624

 
(70,194
)
(38,000
)
(227,301
)
(268,790
)
 
 
 
 
 
Change in cash
45,159

(1,821
)
45,159

(2,157
)
Cash, beginning of period
—

2,369

—

2,705

Cash, end of period
$
45,159

$
548

$
45,159

$
548

 
 
 
 
 
Supplementary information
 
 
 
 
Interest paid
$
20,708

$
21,973

$
70,406

$
72,167

Income taxes paid (recovered)
$
10

$
—

$
(71
)
$
44


See accompanying notes to the condensed consolidated interim unaudited financial statements.
 

Page 4


Baytex Energy Corp.
Notes to the Condensed Consolidated Interim Financial Statements
For the periods ended September 30, 2018 and 2017
(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.

The audited consolidated financial statements of the Company as at and for the year ended December 31, 2017 are available
through its filings on SEDAR at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov.

2.
BASIS OF PRESENTATION
The condensed consolidated interim unaudited financial statements ("consolidated financial statements") have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, under International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). These consolidated financial statements do not include all the necessary annual disclosures as prescribed by IFRS and should be read in conjunction with the annual audited consolidated financial statements as at and for the year ended December 31, 2017.

The consolidated financial statements were approved by the Board of Directors of Baytex on November 1, 2018.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. All financial information is rounded to the nearest thousand, except per share amounts or when otherwise indicated.

3.
SIGNIFICANT ACCOUNTING POLICIES

The accounting policies, critical accounting judgments and significant estimates used in preparation of the 2017 annual financial statements have been applied in the preparation of these consolidated financial statements, except for the adoption of IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments as described below.

Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd., Baytex Energy Limited Partnership, and Baytex Energy Partnership. Intercompany balances and transactions are eliminated in preparation of the consolidated financial statements.

Changes in significant accounting policies

Revenue Recognition

Baytex adopted IFRS 15 Revenue from Contracts with Customers with a date of initial application of January 1, 2018. For the year ended December 31, 2017, $8.3 million of commodity purchases related to heavy oil sales have been reclassified from petroleum and natural gas sales to blending and other expense to conform with the requirements of IFRS 15. There were no adjustments made to the January 1, 2018 opening statement of financial position on adoption. The additional disclosures required by IFRS 15 are provided in note 12 to these consolidated financial statements.

The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis if Baytex acts in the capacity of an agent rather than as a principal.

Revenue from the sale of heavy oil, light oil and condensate, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue when control of the product transfers to the customer and collection is reasonably assured. The amount of revenue recognized is based on the consideration specified in the contract. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon and collection is reasonably assured.

Page 5



The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative commodity price index, and may be adjusted for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.

Tariffs, tolls and fees charged to other entities for use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.

Financial Instruments

Baytex adopted IFRS 9 Financial Instruments, on January 1, 2018 using the retrospective method. The adoption of this standard did not result in a change in the recognition or measurement of any of the Company's financial instruments on transition.

IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost; fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. Financial assets are categorized based on the Company’s objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost.

The initial classification of financial liabilities under IFRS 9 is fundamentally unchanged from the requirements under IAS 39. A financial liability is measured at amortized cost or FVTPL. A financial liability is measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL at initial recognition. For liabilities measured at FVTPL, any change in value resulting from a change in Baytex’s credit risk is recorded through other comprehensive income or loss rather than net income or loss. Trade and other payables, bank loan and long-term notes are classified and measured as amortized cost.

Measurement Uncertainty and Judgments

Revenue - stand-alone selling price

Management is required to make estimates of the price at which the Company would sell the product separately to customers when allocating the transaction price realized in contracts using relative stand-alone selling prices. When making this estimate, management considers market prices and market conditions, as well as cash flows the Company intends to realize based on risk management policies, based on cost and margin objectives.

Future Accounting Pronouncements

Leases

In January 2016, the IASB issued IFRS 16 Leases which replaces IAS 17 Leases. IFRS 16 introduces a single recognition and measurement model for lessees, which will require recognition of lease assets and lease obligations on the balance sheet. Short-term leases and leases for low value assets are exempt from recognition and may be treated as operating leases and recognized through net income or loss. The standard is effective for annual periods beginning on or after January 1, 2019 with early adoption permitted if IFRS 15 has been adopted. The standard shall be applied retrospectively to each period presented or retrospectively as a cumulative-effect adjustment as of the date of adoption. The Company will adopt IFRS 16 on January 1, 2019. The Company has developed a plan to identify and review its various lease agreements in order to determine the impact that adoption of IFRS 16 will have on the consolidated financial statements. The Company is completing its review and analysis of the significant lease contracts that fall into the scope of the new standard and continues to work through scoping and completeness procedures in preparation for adoption on January 1, 2019.


Page 6


4.
BUSINESS COMBINATION

On August 22, 2018, Baytex completed a plan of arrangement whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Raging River Exploration Inc. (“Raging River”), a publicly traded oil and gas producer with light oil producing properties in southwest Saskatchewan and Alberta. Baytex is treated as the acquirer for accounting purposes. In identifying Baytex as the acquirer, Baytex considered, amongst other things, voting rights of all equity instruments, the intended corporate governance structure and composition of senior management of the combined company, in addition to various metrics used to evaluate the relative size of each company. All factors were considered in arriving at the conclusion that Baytex is the acquirer for accounting purposes. The acquisition increases Baytex’s position in southwest Saskatchewan and creates a well-capitalized, oil-weighted company.

The acquisition was accounted for as a business combination whereby the net assets acquired and liabilities assumed were recorded at fair value at the acquisition date. Consideration consisted of the issuance of 315.3 million Baytex common shares valued at approximately $1.2 billion (based on the closing price of Baytex’s common shares of $3.93 on the Toronto Stock Exchange on August 22, 2018). The preliminary estimate of fair value of oil and gas properties acquired was determined using internal estimates of proved plus probable reserves. Asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired using a market discount rate of 7.5% percent. The fair value of exploration and evaluation properties was estimated with reference to recent land sales in similar areas.

The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. The estimated fair value of exploration and evaluation assets, oil and gas properties, asset retirement obligations, and the deferred income tax liability are preliminary and subject to adjustment pending finalization of the annual reserves evaluation.
Consideration
 
Common shares issued
$
1,238,995

Share based compensation (1)
3,100

Total consideration
$
1,242,095

 
 
Fair value of net assets acquired
 
Exploration and evaluation assets
$
97,858

Oil and gas properties
1,748,368

Working capital deficiency excluding bank debt and financial derivatives
(46,773
)
Financial derivatives
(5,548
)
Bank debt (2)
(316,800
)
Asset retirement obligations
(39,960
)
Deferred income tax liability
(195,050
)
Net assets acquired
$
1,242,095

(1)
Following closing of the transaction, holders of units outstanding under Raging River's share based compensation plans are entitled to Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the exchange ratio for the Raging River shares. As a result, the fair value of the vested units was recognized by Baytex as additional consideration (see note 13).
(2)
On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River and converted outstanding principal amounts to a non-revolving term loan which matures on June 4, 2020 (see note 8).

These consolidated financial statements include the results of operations of Raging River for the period following closing of the transaction on August 22, 2018. For the three months ended September 30, 2018, the acquisition contributed revenues of $67.0 million and net income before tax of $33.9 million. Had the acquisition occurred on January 1, 2018, revenues would have increased by $379.5 million and net income before income taxes would have increased by $82.1 million for the nine months ended September 30, 2018.

Transaction costs of $13.1 million were expensed as incurred and share issuance costs of $0.3 million were recorded in shareholders' capital in the nine months ended September 30, 2018.


Page 7


5.
SEGMENTED FINANCIAL INFORMATION

Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:

•
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 United States; and
•
Corporate includes corporate activities and items not allocated between operating segments.
 
Canada
U.S.
Corporate
Consolidated
Three Months Ended September 30
2018

2017

2018

2017

2018

2017

2018

2017

 
 
 
 
 
 
 
 
 
Revenue, net of royalties
 
 
 
 
 
 
 
 
Petroleum and natural gas sales
$
217,805

$
122,307

$
218,956

$
136,313

$
—

$
—

$
436,761

$
258,620

Royalties
(26,139
)
(14,973
)
(65,806
)
(40,203
)
—

—

(91,945
)
(55,176
)
 
191,666

107,334

153,150

96,110

—

—

344,816

203,444

 
 
 
 
 
 
 
 
 
Expenses
 
 
 
 
 
 
 
 
Operating
54,710

43,525

22,988

20,866

—

—

77,698

64,391

Transportation
9,520

9,312

—

—

—

—

9,520

9,312

Blending and other
19,548

16,069

—

—

—

—

19,548

16,069

General and administrative
—

—

—

—

10,158

11,074

10,158

11,074

Transaction costs
—

—

—

—

13,066

—

13,066

—

Exploration and evaluation
510

497

—

—

—

—

510

497

Depletion and depreciation
77,671

51,526

66,830

66,035

—

109

144,501

117,670

Share-based compensation
—

—

—

—

7,180

2,469

7,180

2,469

Financing and interest
—

—

—

—

30,029

27,498

30,029

27,498

Financial derivatives loss (gain)
—

—

—

—

30,900

18,350

30,900

18,350

Foreign exchange loss (gain)
—

—

—

—

(20,943
)
(42,475
)
(20,943
)
(42,475
)
(Gain) loss on disposition of oil and gas properties
(34
)
6,068

—

—

—

—

(34
)
6,068

Other (income) expense
—

—

—

—

(302
)
283

(302
)
283

 
161,925

126,997

89,818

86,901

70,088

17,308

321,831

231,206

Net income (loss) before income taxes
29,741

(19,663
)
63,332

9,209

(70,088
)
(17,308
)
22,985

(27,762
)
Income tax expense (recovery)
 
 
 
 
 
 
 
 
Current income tax expense (recovery)
—

—

—

(48
)
—

—

—

(48
)
Deferred income tax expense (recovery)
4,134

5,402

9,278

(8,774
)
(17,839
)
(15,114
)
(4,427
)
(18,486
)
 
4,134

5,402

9,278

(8,822
)
(17,839
)
(15,114
)
(4,427
)
(18,534
)
Net income (loss)
$
25,607

$
(25,065
)
$
54,054

$
18,031

$
(52,249
)
$
(2,194
)
$
27,412

$
(9,228
)
 
 
 
 
 
 
 
 
 
Total oil and natural gas capital expenditures(1)
$
94,523

$
7,051

$
44,718

$
47,057

$
—

$
—

$
139,241

$
54,108

(1)
Includes acquisitions, net of proceeds from divestitures.



Page 8


 
Canada
U.S.
Corporate
Consolidated
Nine Months Ended September 30
2018

2017

2018

2017

2018

2017

2018

2017

 
 
 
 
 
 
 
 
 
Revenue, net of royalties
 
 
 
 
 
 
 
 
Petroleum and natural gas sales
$
471,742

$
352,522

$
598,691

$
444,184

$
—

$
—

$
1,070,433

$
796,706

Royalties
(55,471
)
(41,725
)
(178,518
)
(130,642
)
—

—

(233,989
)
(172,367
)
 
416,271

310,797

420,173

313,542

—

—

836,444

624,339

 
 
 
 
 
 
 
 
 
Expenses
 
 
 
 
 
 
 
 
Operating
147,054

132,908

66,681

66,538

—

—

213,735

199,446

Transportation
25,875

26,327

—

—

—

—

25,875

26,327

Blending and other
55,077

42,554

—

—

—

—

55,077

42,554

General and administrative
—

—

—

—

31,729

37,672

31,729

37,672

Transaction costs
—

—

—

—

13,066

—

13,066

—

Exploration and evaluation
3,887

5,505

—

—

—

—

3,887

5,505

Depletion and depreciation
172,442

153,392

192,212

216,003

—

1,761

364,654

371,156

Share-based compensation
—

—

—

—

15,010

12,611

15,010

12,611

Financing and interest
—

—

—

—

86,825

85,296

86,825

85,296

Financial derivatives loss (gain)
—

—

—

—

135,243

(33,417
)
135,243

(33,417
)
Foreign exchange loss (gain)
—

—

—

—

40,023

(86,016
)
40,023

(86,016
)
(Gain) loss on disposition of oil and gas properties
(1,764
)
6,592

—

—

—

—

(1,764
)
6,592

Other (income) expense
—

—

—

—

(869
)
1,192

(869
)
1,192

 
402,571

367,278

258,893

282,541

321,027

19,099

982,491

668,918

Net income (loss) before income taxes
13,700

(56,481
)
161,280

31,001

(321,027
)
(19,099
)
(146,047
)
(44,579
)
Income tax expense (recovery)
 
 
 
 
 
 
 
 
Current income tax expense (recovery)
—

—

(71
)
(1,489
)
—

—

(71
)
(1,489
)
Deferred income tax expense (recovery)
(197
)
(5,372
)
15,951

(27,336
)
(67,659
)
(21,518
)
(51,905
)
(54,226
)
 
(197
)
(5,372
)
15,880

(28,825
)
(67,659
)
(21,518
)
(51,976
)
(55,715
)
Net income (loss)
$
13,897

$
(51,109
)
$
145,400

$
59,826

$
(253,368
)
$
2,419

$
(94,071
)
$
11,136

 
 
 
 
 
 
 
 
 
Total oil and natural gas capital expenditures(1)
$
174,609

$
135,202

$
134,949

$
164,702

$
—

$
—

$
309,558

$
299,904

(1)
Includes acquisitions, net of proceeds from divestitures.

As at
September 30, 2018

December 31, 2017

Canadian assets
$
3,746,034

$
1,677,821

U.S. assets
2,735,867

2,684,816

Corporate assets
9,402

9,474

Total consolidated assets
$
6,491,303

$
4,372,111


6.
EXPLORATION AND EVALUATION ASSETS

September 30, 2018

December 31, 2017

Balance, beginning of period
$
272,974

$
308,462

Capital expenditures
3,864

7,118

Corporate acquisition (note 4)
97,858

—

Divestitures
(872
)
(1,276
)
Exploration and evaluation expense
(3,887
)
(8,253
)
Transfer to oil and gas properties
(9,895
)
(20,198
)
Foreign currency translation
5,193

(12,879
)
Balance, end of period
$
365,235

$
272,974



Page 9


7.
OIL AND GAS PROPERTIES

Cost

Accumulated depletion

Net book value

Balance, December 31, 2016
$
7,764,037

$
(3,611,868
)
$
4,152,169

Capital expenditures
319,148

—

319,148

Property acquisitions
136,007

—

136,007

Transferred from exploration and evaluation assets
20,198

—

20,198

Transferred from other assets
5,124

—

5,124

Change in asset retirement obligations
42,808

—

42,808

Divestitures
(105,272
)
49,291

(55,981
)
Foreign currency translation
(249,723
)
68,641

(181,082
)
Depletion
—

(480,082
)
(480,082
)
Balance, December 31, 2017
$
7,932,327

$
(3,974,018
)
$
3,958,309

Capital expenditures
307,695

—

307,695

Corporate acquisition (note 4)
1,748,368

—

1,748,368

Property acquisitions
202

—

202

Transferred from exploration and evaluation assets
9,895

—

9,895

Change in asset retirement obligations (note 10)
145,883

—

145,883

Divestitures
(15
)
—

(15
)
Foreign currency translation
114,808

(35,293
)
79,515

Depletion
—

(362,726
)
(362,726
)
Balance, September 30, 2018
$
10,259,163

$
(4,372,037
)
$
5,887,126


At the end of each reporting period, the Company performs an assessment to determine whether there is any indication of impairment or reversal of previously recorded impairments for the cash generating units ("CGU") that comprise oil and gas properties. The assessment of indicators is subjective in nature and requires management to make judgments based on the information available at the reporting date. The Company determined that there were no indicators of impairment or impairment reversals for any of the Company's CGUs as at September 30, 2018.

8.
BANK LOAN
 
September 30, 2018

December 31, 2017

Bank loan - U.S. dollar denominated (1)
$
175,417

$
166,489

Bank loan - Canadian dollar denominated
315,148

46,887

Bank loan - principal
490,565

213,376

Unamortized debt issuance costs
(1,761
)
(1,238
)
Bank loan
$
488,804

$
212,138

(1)
U.S. dollar denominated bank loan balance as at September 30, 2018 was US$136.0 million (US$133.0 million as at December 31, 2017).

Baytex has credit facilities that include US$575 million of revolving credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving term loan (the "Term Loan"). On April 25, 2018, Baytex amended its credit facilities to extend maturity from June 4, 2019 to June 4, 2020. On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging River (note 4) and converted outstanding principal amounts to the Term Loan which matures on June 4, 2020.

The amended extendible secured Revolving Facilities are comprised of a US$35 million operating loan (previously US$25 million) and a US$340 million syndicated revolving loan for Baytex (previously US$350 million) and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. and matures on June 4, 2020. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership and matures on June 4, 2020.


Page 10


The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity on June 4, 2020 which could be extended upon Baytex's request. Advances (including letters of credit) under the credit 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 breaches any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.

At September 30, 2018, Baytex had $15.0 million of outstanding letters of credit (December 31, 2017 - $14.6 million) under the credit facilities.

At September 30, 2018, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at September 30, 2018.
Covenant Description
Position as at September 30, 2018
Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)
0.55:1.00
3.50:1.00
Interest Coverage(3) (Minimum Ratio)
9.00:1.00
2.00:1.00
(1)
Senior Secured Debt is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at September 30, 2018, the Company's Senior Secured Debt totaled $505.6 million.
(2)
Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, unrealized gains and losses on financial derivatives, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2018 was $911.1 million.
(3)
Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended September 30, 2018 were $101.2 million.

9.
LONG-TERM NOTES
 
September 30, 2018

December 31, 2017

6.75% notes (US$150,000 – principal) due February 17, 2021
$
193,853

$
187,770

5.125% notes (US$400,000 – principal) due June 1, 2021
516,940

500,720

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
516,940

500,720

Total long-term notes - principal
1,527,733

1,489,210

Unamortized debt issuance costs
(13,274
)
(15,026
)
Total long-term notes - net of unamortized debt issuance costs
$
1,514,459

$
1,474,184


The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing Facilities and long-term notes unless the Company maintains a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 8) to financing and interest expenses on a trailing twelve month basis) of 2.50:1.00. As at September 30, 2018, the fixed charge coverage ratio was 9.00:1.00.


Page 11


10.
ASSET RETIREMENT OBLIGATIONS
 
September 30, 2018

December 31, 2017

Balance, beginning of period
$
368,995

$
331,517

Liabilities incurred
6,856

5,825

Liabilities settled
(9,215
)
(13,471
)
Liabilities assumed from corporate acquisition (note 4)
39,960

—

Liabilities acquired from property acquisitions
132

22,264

Liabilities divested
(580
)
(19,940
)
Accretion (note 16)
7,450

8,682

Change in estimate
2,193

(24,028
)
Changes in discount rates and inflation rates(1)
136,834

61,011

Foreign currency translation
999

(2,865
)
Balance, end of period
$
553,624

$
368,995

(1)
Change in discount rates and inflation rates includes $136.8 million to revalue the liabilities acquired in the Raging River acquisition (note 4) using the risk-free discount rate. At the date of acquisition, acquired asset retirement obligation liabilities are fair valued using the market rate.

11.
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 September 30, 2018, no preferred shares have been issued by the Company and all common shares issued were fully paid.

The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meetings of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.
 
Number of Common Shares
(000s)

Amount

Balance, December 31, 2016
233,449

$
4,422,661

Transfer from contributed surplus on vesting and conversion of share awards
2,002

20,915

Balance, December 31, 2017
235,451

$
4,443,576

Transfer from contributed surplus on vesting and conversion of share awards
3,233

19,272

Issued on corporate acquisition (note 4)
315,266

1,238,995

Issuance costs, net of tax (note 4)
—

(316
)
Balance, September 30, 2018
553,950

$
5,701,527


12.
PETROLEUM AND NATURAL GAS SALES

Petroleum and natural gas sales primarily consists of revenues earned from the sale of produced oil and natural gas volumes pursuant to fixed or variable price contracts, including the physical delivery contracts for fixed volumes outlined in note 18. The activities that generate petroleum and natural gas sales for the Canadian and U.S. operating segments are described below.

Canada Segment

Petroleum and natural gas sales for Baytex's Canadian operating segment primarily consists of revenues generated from the Company's interest in operated oil and natural gas properties and production taken in-kind from its interest in non-operated oil and natural gas properties.

Under its contracts with customers, Baytex is required to deliver volumes of heavy oil, light oil and condensate, natural gas liquids and natural gas to agreed upon locations where control over the delivered volumes is transferred to the customer. Revenue is recognized when control of each unit of product is transferred to the customer with revenues due on the 25th day of the month following delivery.

Baytex's customers are primarily oil and natural gas marketers and partners in joint operations in the oil and natural gas industry. Concentration of credit risk is mitigated by marketing production to several oil and natural gas marketers under customary industry

Page 12


and payment terms. Baytex reviews the credit worthiness and, when prudent, obtains certain financial assurances from customers prior to entering sales contracts. The financial strength of the Company's customers is reviewed on a routine basis.

U.S. Segment

Petroleum and natural gas sales for Baytex's U.S. operating segment primarily consists of revenues generated from the Company's interest in non-operated oil and natural gas properties where the Company has not elected its right to take its production in-kind. The operator of the oil and natural gas properties that comprise the U.S. operating segment enters contracts with customers, conducts the activities required to transfer control of light oil and condensate, natural gas liquids and natural gas volumes to the customer, and collects and remits payments from the customer to Baytex.

The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the following table.
 
Three Months Ended September 30
 
2018
2017
($ thousands)
Canada

U.S.

Total

Canada

U.S.

Total

Light oil and condensate
$
69,557

$
170,402

$
239,959

$
6,024

$
101,320

$
107,344

Heavy oil
139,305

—

139,305

107,972

—

107,972

NGL
4,147

30,508

34,655

2,596

18,116

20,712

Natural gas sales
4,796

18,046

22,842

5,715

16,877

22,592

Total petroleum and natural gas sales
$
217,805

$
218,956

$
436,761

$
122,307

$
136,313

$
258,620

 
Nine Months Ended September 30
 
2018
2017
($ thousands)
Canada

U.S.

Total

Canada

U.S.

Total

Light oil and condensate
$
79,894

$
476,086

$
555,980

$
18,808

$
335,190

$
353,998

Heavy oil
364,957

—

364,957

301,663

—

301,663

NGL
11,595

71,480

83,075

8,040

52,395

60,435

Natural gas sales
15,296

51,125

66,421

24,011

56,599

80,610

Total petroleum and natural gas sales
$
471,742

$
598,691

$
1,070,433

$
352,522

$
444,184

$
796,706


Included in accounts receivable at September 30, 2018 is $146.3 million (December 31, 2017 - $91.6 million) of accrued production revenue related to deliveries for periods ended prior to the reporting date.


Page 13


13.
SHARE AWARD INCENTIVE PLAN
The Company recorded compensation expense related to the share awards of $7.2 million and $15.0 million for the three and nine months ended September 30, 2018 ($2.5 million and $12.6 million for the three and nine months ended September 30, 2017).
 
The weighted average fair value of share awards granted was $4.04 per restricted and performance award for the nine months ended September 30, 2018 and $5.68 per restricted and performance award for the nine months ended September 30, 2017.

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, 2016
1,508

1,737

3,245

Granted
1,636

1,584

3,220

Vested and converted to common shares
(959
)
(1,043
)
(2,002
)
Forfeited
(157
)
(25
)
(182
)
Balance, December 31, 2017
2,028

2,253

4,281

Granted
2,793

2,591

5,384

Issued on corporate acquisition(2)
302

257

559

Vested and converted to common shares
(1,604
)
(1,629
)
(3,233
)
Forfeited
(180
)
(154
)
(334
)
Balance, September 30, 2018
3,339

3,318

6,657

(1)
Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.
(2)
Following closing of the acquisition of Raging River (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance awards are entitled to Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards outstanding based on the exchange ratio. The fair value of the vested awards was included in consideration (note 4).

Share Options

On August 22, 2018, Baytex became the successor to Raging River's 2012 Option Plan and Raging River's 2016 Option Plan (collectively, the "Option Plans"). Although no new grants will be made under the Option Plans following completion of the Arrangement, share options held under the Option Plans in existence at August 22, 2018 were converted to share options to purchase shares in Baytex.

The Company accounts for share options using the fair value method. Under this method, compensation is expensed over the vesting period for the stock options, with a corresponding increase to contributed surplus.

Share options granted under the Option Plans have a maximum term of 3.5 years to expiry. One third of the options granted will vest on each of the first, second, and third anniversaries of the date of grant. At September 30, 2018, 8.7 million share options with a weighted average exercise price of $6.66 were outstanding. The following tables summarize the information about the share options.
(000s, except per common share amounts)
Number of options

Weighted average exercise price

Balance, December 31, 2017
—

$
—

Granted
—

—

Issued on corporate acquisition
9,187

6.63

Forfeited/Expired
(453
)
6.13

Balance, September 30, 2018
8,734

$
6.66


Page 14


 
Options outstanding
Options exercisable
Exercise price
Number outstanding at September 30, 2018 (000s)

Weighted average remaining life (years)

Weighted average exercise price

Number exercisable at September 30, 2018 (000s)

Weighted average exercise price

$5.00 - $6.00
1,044

1.66

$
5.68

459

$
5.77

$6.01 - $7.00
5,728

0.69

6.47

4,430

6.44

$7.01 - $8.00
1,924

0.97

7.72

1,343

7.73

$8.01 - $9.00
38

1.37

8.26

25

8.26

Total
8,734

0.87

$
6.66

6,257

$
6.67


14.
NET INCOME (LOSS) PER SHARE
Baytex calculates basic income per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards and share options were converted. The treasury stock method is used to determine the dilutive effect of share awards and share options whereby the potential conversion of share awards and share options and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the period.
 
Three Months Ended September 30
 
2018
2017
 
Net income

Weighted average common shares (000s)

Net income per share

Net loss

Weighted average common shares (000s)

Net loss per share

Net income (loss) - basic
$
27,412

375,435

$
0.07

$
(9,228
)
235,451

$
(0.04
)
Dilutive effect of share awards
—

3,328

—

—

—

—

Dilutive effect of share options
—

—

—

—

—

—

Net income (loss) - diluted
$
27,412

378,763

$
0.07

$
(9,228
)
235,451

$
(0.04
)
 
Nine Months Ended September 30
 
2018
2017
 
Net loss

Weighted average common shares (000s)

Net loss per share

Net income

Weighted average common shares (000s)

Net income per share

Net income (loss) - basic
$
(94,071
)
283,302

$
(0.33
)
$
11,136

234,563

$
0.05

Dilutive effect of share awards
—

—

—

—

2,640

—

Dilutive effect of share options
—

—

—

—

—

—

Net income (loss) - diluted
$
(94,071
)
283,302

$
(0.33
)
$
11,136

237,203

$
0.05


For the three months ended September 30, 2018 no share awards were considered to be anti-dilutive (2017 - 1.6 million). For the nine months ended September 30, 2018, 6.7 million share awards were excluded from the calculation of diluted earnings per share as they were determined to be anti-dilutive. For the three and nine months ended September 30, 2018, 8.7 million share options were excluded from the calculation of diluted earnings per share as they were out of the money.


Page 15


15.
INCOME TAXES
The provision for income taxes has been computed as follows:
 
Nine Months Ended September 30
 
2018

2017

Net loss before income taxes
$
(146,047
)
$
(44,579
)
Expected income taxes at the statutory rate of 27.00% (2017 – 26.93%)(1)
(39,433
)
(12,007
)
(Increase) decrease in income tax recovery resulting from:
 
 
Share-based compensation
3,963

3,397

Non-taxable portion of foreign exchange loss (gain)
5,201

(11,719
)
Effect of rate adjustments for foreign jurisdictions
(27,400
)
(34,303
)
Effect of change in deferred tax benefit not recognized(2)
5,201

(11,719
)
Adjustments and assessments (3)
492

10,636

Income tax recovery
$
(51,976
)
$
(55,715
)
(1)
Expected income tax rate increased due to an increase in the corporate income tax rate in Saskatchewan from 11.75% to 12.00%, effective January 1, 2018.
(2)
A deferred income tax asset has not been recognized for allowable capital losses of $105 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ($86 million as at December 31, 2017).
(3)
The Company is regularly subject to audit by the revenue authorities in the jurisdictions in which it operates. During the year ended December 31, 2017, the Company accepted an audit proposal from the Canada Revenue Agency which reduced certain non-capital loss tax pools by $39.3 million and resulted in a $10.6 million increase in deferred tax expense.

As disclosed in the 2017 annual financial statements, Baytex received several reassessments from the Canada Revenue Agency
(the “CRA”) in June 2016 which denied $591 million of non-capital loss deductions that Baytex had previously claimed. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. In July 2018, an Appeals Officer was assigned to its file. Baytex remains confident that its original tax filings are correct and intends to defend those tax filings through the appeals process.

16.
FINANCING AND INTEREST
 
Three Months Ended September 30
Nine Months Ended September 30
 
2018

2017

2018

2017

Interest on bank loan
$
4,108

$
2,985

$
10,297

$
8,573

Interest on long-term notes
22,235

21,541

66,087

67,059

Non-cash financing
866

1,008

2,991

3,288

Accretion on asset retirement obligations (note 10)
2,820

1,964

7,450

6,376

Financing and interest
$
30,029

$
27,498

$
86,825

$
85,296


17.
FOREIGN EXCHANGE
 
Three Months Ended September 30
Nine Months Ended September 30
 
2018

2017

2018

2017

Unrealized foreign exchange loss (gain)
$
(20,583
)
$
(44,006
)
$
38,136

$
(87,389
)
Realized foreign exchange loss (gain)
(360
)
1,531

1,887

1,373

Foreign exchange loss (gain)
$
(20,943
)
$
(42,475
)
$
40,023

$
(86,016
)


Page 16


18.
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, bank loan and long-term notes.

Categories of Financial Instruments

The estimated fair values of the financial instruments have been determined based on the Company's assessment of available market information. To estimate fair values of its financial instruments, Baytex uses quoted market prices when available, or third-party models and valuation methodologies that use observable market data. Baytex aims to maximize the use of observable inputs, where practical. The fair values of financial instruments, other than financial derivatives, bank loan and long-term notes, are equal to their carrying amounts due to the short-term maturity of these instruments. The fair value of financial derivatives are based on mark-to-market values of the underlying financial derivative contracts. The fair value of the bank loan is based on the principal amount of borrowings outstanding. The fair value of the long-term notes is based on the trading value of the notes.

Fair Value of Financial Instruments

Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

•
Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

•
Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

•
Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories:

 
September 30, 2018
December 31, 2017
 
 
Carrying value

Fair value

Carrying value

Fair value

Fair Value Measurement Hierarchy

Financial Assets
 
 
 
 
 
FVTPL(1)
 
 
 
 
 
Cash
$
45,159

$
45,159

$
—

$
—

Level 1

Financial derivatives
$
6,214

$
6,214

$
18,510

$
18,510

Level 2

Total
$
51,373

$
51,373

$
18,510

$
18,510

 
 
 
 
 
 
 
Assets at amortized cost
 
 
 
 
 
Trade and other receivables
$
178,167

$
178,167

$
112,844

$
112,844

—

Total
$
178,167

$
178,167

$
112,844

$
112,844

 
 
 
 
 
 
 
Financial Liabilities
 
 
 
 
 
FVTPL(1)
 
 
 
 
 
Financial derivatives
$
(108,487
)
$
(108,487
)
$
(50,095
)
$
(50,095
)
Level 2

Total
$
(108,487
)
$
(108,487
)
$
(50,095
)
$
(50,095
)
 
 
 
 
 
 
 
Financial liabilities at amortized cost
 
 
 
 
 
Trade and other payables
$
(317,118
)
$
(317,118
)
$
(144,542
)
$
(144,542
)
—

Bank loan
(488,804
)
(490,565
)
(212,138
)
(213,376
)
—

Long-term notes
(1,514,459
)
(1,501,610
)
(1,474,184
)
(1,430,902
)
Level 1

Total
$
(2,320,381
)
$
(2,309,293
)
$
(1,830,864
)
$
(1,788,820
)
 
(1)
FVTPL means fair value through profit or loss.

Page 17



There were no transfers between Level 1 and Level 2 during the nine months ended September 30, 2018 and 2017.

Foreign Currency Risk

The carrying amount of the Company’s U.S. dollar denominated monetary assets and liabilities at the reporting date are as follows:

Assets
Liabilities

September 30, 2018
December 31, 2017
September 30, 2018
December 31, 2017
U.S. dollar denominated

US$77,387


US$51,665


US$1,221,797


US$1,294,615


Page 18


Commodity Price Risk

Financial Derivative Contracts

Baytex had the following financial derivative contracts outstanding as of November 1, 2018:
 
Period
Volume
Price/Unit(1)

Index
Fair Value(2) 
($ millions)

Oil
 
 
 
 
 
Basis swap
Oct 2018 to Dec 2018
6,000 bbl/d
WTI less US$14.24/bbl

WCS
$
8.4

3-way option(3)
Oct 2018 to Dec 2018
2,000 bbl/d
US$60.00/US$54.40/US$40.00

WTI
$
(3.1
)
Fixed - Sell
Oct 2018 to Dec 2018
16,500 bbl/d
 US$52.28/bbl

WTI
$
(43.1
)
Fixed - Sell
Oct 2018 to Dec 2018
4,000 bbl/d
 US$61.31/bbl

Brent
$
(11.6
)
Fixed - Sell
Jan 2019 to Jun 2019
2,000 bbl/d
 US$62.85/bbl

WTI
$
(4.3
)
Fixed - Sell
Jan 2019 to Dec 2019
2,000 bbl/d
 US$61.70/bbl

WTI
$
(9.4
)
Swaption(4)
Jan 2019 to Dec 2019
2,000 bbl/d
US$61.70/bbl

WTI
$
(9.8
)
Swaption(4)
Jan 2019 to Dec 2019
2,000 bbl/d
US$59.60/bbl

WTI
$
(10.9
)
3-way option(3)
Jan 2019 to Dec 2019
2,000 bbl/d
US$70.00/US$60.00/US$50.00

WTI
$
(4.5
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
US$72.60/US$65.00/US$55.00

WTI
$
(1.3
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
US$72.50/US$66.00/US$56.00

WTI
$
(1.2
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
US$73.00/US$66.00/US$56.00

WTI
$
(1.1
)
3-way option(3)
Jan 2019 to Dec 2019
2,000 bbl/d
US$73.00/US$67.00/US$57.00

WTI
$
(2.1
)
3-way option(3)
Jan 2019 to Dec 2019
2,000 bbl/d
 US$74.00/US$68.00/US$58.00

WTI
$
(2.1
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$75.00/US$69.90/US$60.00

WTI
$
(0.3
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$76.00/US$71.00/US$61.00

WTI
$
(0.1
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$75.50/US$65.50/US$55.50

Brent
$
(3.4
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$77.55/US$70.00/US$60.00

Brent
$
(2.6
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$83.00/US$73.00/US$63.00

Brent
$
(1.1
)
3-way option(3)
Jan 2019 to Dec 2019
1,000 bbl/d
 US$78.00/US$73.00/US$63.00

WTI
$
—

 





 
Natural Gas
 
 
 
 
 
Fixed - Sell
Oct 2018 to Dec 2018
15,000 mmbtu/d

US$3.01

NYMEX
$
(0.1
)
Fixed - Sell
Oct 2018 to Dec 2018
5,000 GJ/d

$2.67

AECO
$
0.4

Fixed - Sell
Nov 2018 to Mar 2019
5,000 GJ/d

$2.25

AECO
$
—

Total
 
 
 
 
$
(103.3
)
Current asset
 
 
 
 
5.2

Non-current asset
 
 
 
 
—

Current liability
 
 
 
 
(98.5
)
Non-current liability
 
 
 
 
(10.0
)
(1)
Based on the weighted average price per unit for the period.
(2)
Fair values as at September 30, 2018. For the purposes of the table, contracts entered subsequent to September 30, 2018 will have no fair value assigned.
(3)
Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$70/US$60/US$50 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50/bbl; Baytex receives US$60.00/bbl when WTI is between US$50/bbl and US$60/bbl; Baytex receives the market price when WTI is between US$60/bbl and US$70/bbl; and Baytex receives US$70/bbl when WTI is above US$70/bbl.
(4)
For these contracts, the counterparty has the right, if exercised on December 31, 2018, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

Physical Delivery Contracts

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 and, as a result, no asset or liability has been recognized in the consolidated statements of financial position.


Page 19


As at November 1, 2018, Baytex had committed to deliver the following volumes of raw bitumen to market on rail:
Period

Volume
Oct 2018 to Dec 2018

8,340 bbl/d
Nov 2018 to Oct 2019
 
1,000 bbl/d
Oct 2018 to Dec 2019

2,500 bbl/d
Jan 2019 to Dec 2019
 
2,500 bbl/d
Jan 2019 to Dec 2020 

5,000 bbl/d

Interest Rate Risk

Interest Rate Swaps

Baytex had the following interest rate swaps outstanding as of November 1, 2018:
Contract Type
Notional Amount
Maturity Date
Fixed Contract Price
Reference(1)
Fair Value
($ millions)

Interest rate swap
$100 million
October 2020
2.02%
CDOR
$
1.0

Total
 
 
 
 
$
1.0

Current asset
 
 
 
 
0.5

Non-current asset
 
 
 
 
0.5

(1)
Canadian Dollar Offered Rate.

Financial derivatives are marked-to-market at the end of each reporting period, with the following reflected in the consolidated statements of income or loss:
 
Three Months Ended September 30
Nine Months Ended September 30
 
2018

2017

2018

2017

Realized financial derivatives loss (gain)
$
30,854

$
(2,795
)
$
70,103

$
(5,719
)
Unrealized financial derivatives loss (gain)
46

21,145

65,140

(27,698
)
Financial derivatives loss (gain)
$
30,900

$
18,350

$
135,243

$
(33,417
)


Page 20