BAYTEX REPORTS 2015 RESULTS, STRONG RESERVES GROWTH

IN THE EAGLE FORD AND REVISED 2016 BUDGET

CALGARY, ALBERTA (March 3, 2016) - Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its operating and financial results for the three months and year ended December 31, 2015 (all amounts are in Canadian dollars unless otherwise noted).

"Our 2015 results reflect the strong contribution from our Eagle Ford assets. The Eagle Ford generates the highest cash netbacks in our portfolio and has enhanced the quality of our production and reserves base. In 2015, 86% of our development activity was focused in the Eagle Ford, which contributed to strong reserves growth in our U.S. assets. The execution of our capital program has yielded impressive results as we advance the multi-zone development potential of our Eagle Ford acreage," commented James Bowzer, President and Chief Executive Officer.

Bowzer said, "Based on the current commodity price environment and our commitment to ensuring strong levels of financial liquidity, we are reducing our 2016 exploration and development capital budget to $225 to $265 million, a 33% reduction from initial expectations of $325 to $400 million. In addition, we are proactively shutting-in approximately 7,500 bbl/d of low or negative margin heavy oil production in order to optimize the value of the resource base and maximize our funds from operations. Should netbacks improve, we have the ability to restart these wells in relatively short order at minimal cost. Our 2016 program will remain flexible and allows for adjustments to spending and production based on changes in the commodity price environment."

Highlights

  • Generated production of 81,110 boe/d (81% oil and NGL) during Q4/2015 and 84,648 boe/d for the full-year 2015, in line with guidance;
  • Delivered funds from operations ("FFO") of $93.1 million ($0.44 per share) in Q4/2015 and $516.4 million ($2.61 per share) for the full-year 2015;
  • Produced 40,284 boe/d (78% oil and NGL) in the Eagle Ford during Q4/2015, an increase of 3% over Q3/2015 and 6% over Q4/2014;
  • Realized over $150 million in efficiencies in 2015 as we remained focused on cost reduction initiatives across all of our operations, including drilling and completions, production and operating expenses, transportation expenses, and general and administrative expenses;
  • Increased proved plus probable reserves (excluding thermal) by 2% to 347 mmboe. Year-end 2015 proved plus probable reserves are comprised of 81% oil and NGL and 19% natural gas;
  • In the Eagle Ford, replaced 205% of production and increased proved plus probable reserves 8% to 203 mmboe. From the time of acquisition in June 2014, proved plus probable reserves in the Eagle Ford have increased by 22%;
  • Recorded finding and development ("F&D") costs for proved plus probable reserves, including changes in future development costs, of $7.68/boe for 2015 and generated a recycle ratio (operating netback divided by F&D costs) of 2.1x;
  • Using the December 31, 2015 independent reserves evaluation, the present value of our reserves, discounted at 10% before tax, is estimated to be $4.3 billion; and
  • Our estimated net asset value at year-end 2015, discounted at 10%, is estimated to be $11.05 per share. This is based on the estimated reserves value of $4.3 billion plus a value for undeveloped acreage, net of long-term debt, asset retirement obligations and working capital.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 2

Three Months Ended

Years Ended

December 31,

September 30,

December 31,

December 31,

December 31,

2015

2015

2014

2015

2014

FINANCIAL

(thousands of Canadian dollars, except per

common share amounts)

Petroleum and natural gas sales

$

230,200

$

268,625

$

472,390

$

1,129,872

$

1,969,022

Funds from operations (1)

93,095

105,052

245,513

516,417

879,790

Per share - basic

0.44

0.51

1.47

2.61

5.91

Per share - diluted

0.44

0.51

1.47

2.61

5.91

Cash dividends declared (2)

-

17,248

72,509

96,624

301,118

Dividends declared per share

-

0.20

0.58

0.80

2.64

Net income (loss)

(412,924)

(517,856)

(361,816)

(1,133,651)

(132,807)

Per share - basic

(1.96)

(2.49)

(2.16)

(5.72)

(0.89)

Per share - diluted

(1.96)

(2.49)

(2.16)

(5.72)

(0.89)

Exploration and development

140,796

126,804

214,697

521,039

766,070

Acquisitions, net of divestitures

(574)

(498)

(35,666)

1,648

2,545,156

Total oil and natural gas capital

$

140,222

$

126,306

$

179,031

$

522,687

$

3,311,226

expenditures

Bank loan (3)

$

256,749

$

208,195

$

666,886

$

256,749

$

666,886

Long-term notes (3)

1,623,658

1,581,002

1,418,685

1,623,658

1,418,685

Long-term debt

1,880,407

1,789,197

2,085,571

1,880,407

2,085,571

Working capital deficiency

169,498

160,539

210,409

169,498

210,409

Net debt (4)

$

2,049,905

$

1,949,736

$

2,295,980

$

2,049,905

$

2,295,980

Three Months Ended

Years Ended

December 31,

September 30,

December 31,

December 31,

December 31,

2015

2015

2014

2015

2014

OPERATING

Daily production

Heavy oil (bbl/d)

31,733

33,639

43,186

34,974

45,022

Light oil and condensate (bbl/d)

24,930

24,712

26,916

25,887

17,681

NGL (bbl/d)

8,996

8,507

8,098

8,492

4,819

Total oil and NGL (bbl/d)

65,659

66,858

78,200

69,353

67,522

Natural gas (mcf/d)

92,708

91,869

84,428

91,766

65,234

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

81,110

82,170

92,271

84,648

78,395

Average prices (before hedging)

WTI oil (US$/bbl)

42.18

46.43

73.14

48.79

92.97

WCS Heavy Oil (US$/bbl)

27.69

33.13

58.90

35.26

73.58

Edmonton par oil ($/bbl)

52.94

56.22

75.69

57.20

95.28

LLS oil (US$/bbl)

43.33

49.79

76.34

51.50

96.76

BTE heavy oil ($/bbl) (6)

24.41

30.90

53.34

32.23

69.64

BTE light oil and condensate ($/bbl)

50.17

55.46

77.20

55.75

91.37

BTE NGL ($/bbl)

17.23

15.35

28.07

16.91

35.28

BTE total oil and NGL ($/bbl)

33.21

38.00

58.93

39.13

72.88

BTE natural gas ($/mcf)

2.76

3.28

4.12

3.08

4.53

BTE oil equivalent ($/boe)

30.03

34.59

53.72

35.40

66.54

CAD/USD noon rate at period end

1.3840

1.3394

1.1601

1.3840

1.1601

CAD/USD average rate for period

1.3353

1.3094

1.1378

1.2811

1.1050

Baytex Energy Corp.

Press Release - March 3, 2016

Page 3

Three Months Ended

Years Ended

December 31,

September 30,

December 31,

December 31,

December 31,

2015

2015

2014

2015

2014

COMMON SHARE INFORMATION

TSX

Share price (Cdn$)

High

6.88

19.50

42.90

24.87

49.88

Low

3.50

3.92

14.56

3.50

14.56

Close

4.48

4.27

19.32

4.48

19.32

Volume traded (thousands)

283,619

165,674

133,365

652,044

273,743

NYSE

Share price (US$)

High

5.27

15.51

38.35

20.10

46.46

Low

2.50

2.92

12.63

2.50

12.63

Close

3.24

3.20

16.61

3.24

16.61

Volume traded (thousands)

153,763

109,902

20,255

375,660

33,170

Common shares outstanding (thousands)

210,583

210,225

168,107

210,583

168,107

Notes:

  1. Funds from operations is not a measurement based on generally accepted accounting principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. We define funds from operations as cash flow from operating activities adjusted for finance costs, changes in non-cash operating working capital and asset retirement obligations settled. 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, debt repayment and future dividends. For a reconciliation of funds from operations to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the year ended December 31, 2015.
  2. Cash dividends declared are net of participation in our dividend reinvestment plan.
  3. Principal amount of instruments.
  4. Net debt is a non-GAAP measure which we define to be the sum of working capital (which is current assets less current liabilities (excluding unrealized gains or losses on financial derivatives)) and the principal amount of long-term debt.
  5. Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
  6. Heavy oil prices exclude condensate blending.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 4

Operations Review

Our operating results for the fourth quarter and full-year 2015 were consistent with our expectations and reflect a reduced pace of drilling activity in response to the low crude oil price environment. Production averaged 81,110 boe/d (81% oil and NGL) in Q4/2015, as compared to 82,170 boe/d (81% oil and NGL) in Q3/2015. For the full-year 2015, production averaged 84,648 boe/d (82% oil and NGL), in line with our production guidance of 84,000 to 86,000 boe/d.

Capital expenditures for exploration and development activities totaled $140.8 million in Q4/2015 and $521.0 million for full-year 2015, in line with our annual guidance of $500 to $575 million. In 2015, we participated in the drilling of 228 (81.6 net) wells with a 99% success rate.

We realized over $150 million in efficiencies in 2015 as we remained focused on cost reduction initiatives across all of our operations. Drilling costs have been reduced by approximately 27% in the Eagle Ford as compared to 2014, operating expenses were reduced by 18% from budget, transportation expenses were reduced by 20% from budget and general and administrative expenses were down 22% from budget.

Wells Drilled - Three Months Ended December 31, 2015

Stratigraphic

Dry and

Crude Oil

Natural Gas

and Service

Abandoned

Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Heavy oil

Lloydminster

-

-

-

-

-

-

-

-

-

-

Peace River

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Light oil and natural gas

Eagle Ford

14

4.1

28

8.5

-

-

-

-

42

12.6

Western Canada

-

-

-

-

-

-

-

-

-

-

14

4.1

28

8.5

-

-

-

-

42

12.6

Total

14

4.1

28

8.5

-

-

-

-

42

12.6

Wells Drilled - Twelve Months Ended December 31, 2015

Stratigraphic

Dry and

Crude Oil

Natural Gas

and Service

Abandoned

Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Heavy oil

Lloydminster

26

17.4

-

-

1

1.0

-

-

27

18.4

Peace River

6

6.0

-

-

5

5.0

-

-

11

11.0

32

23.4

-

-

6

6.0

-

-

38

29.4

Light oil and natural gas

Eagle Ford

66

16.7

119

32.6

1

0.3

2

0.6

188

50.2

Western Canada

-

-

2

2.0

-

-

-

-

2

2.0

66

16.7

121

34.6

1

0.3

2

0.6

190

52.2

Total

98

40.1

121

34.6

7

6.3

2

0.6

228

81.6

Our performance in the Eagle Ford was strong during the fourth quarter as we maintained a consistent pace of development, averaging six drilling rigs and two frac crews on our lands. Production averaged 40,284 boe/d (78% oil and NGL) during Q4/2015, as compared to 38,941 boe/d in Q3/2015 and 39,548 boe/d in Q2/2015. Capital expenditures in the Eagle Ford totaled $132 million during Q4/2015 bringing full-year expenditures to $450 million. As at December 31, 2015, we had 36 (10.1 net) wells waiting on completion.

Significant advancements were made in 2015 to delineate the multi-zone development potential of our Sugarkane acreage. We continued to implement "stack and frac" pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk. In 2015, we drilled 188 (50.2 net) wells on Eagle Ford acreage, of which 56% targeted the Lower Eagle Ford, 26% targeted the Austin Chalk, 11% targeted the Upper Eagle Ford and 7% targeted the upper portion of the Lower Eagle Ford. Recent production data from one pad (a total of 4 wells) that targeted three zones achieved 30-day initial production rates

Baytex Energy Corp.

Press Release - March 3, 2016

Page 5

per well ranging from 1,400 to 1,875 boe/d. We currently have thirteen multi-zone projects in various stages of execution and production.

In Q4/2015, we participated in the drilling of 42 (12.6 net) wells in the Eagle Ford and commenced production from 61 (16.6 net) wells. Of the 61 gross wells that commenced production during the fourth quarter, 46 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,100 boe/d.

Production in Canada averaged 40,826 boe/d (84% oil and NGL) during Q4/2015, as compared to 43,229 boe/d in Q3/2015. The reduced volumes in Canada are due to the cancellation of the Canadian drilling program as a result of low crude oil prices. Capital expenditures for our Canadian assets in Q4/2015 totaled $8.8 million, a decrease from $33.5 million in Q3/2015.

Financial Review

We generated FFO of $93.1 million ($0.44 per share) in Q4/2015, compared to $105.1 million ($0.51 per share) in Q3/2015. Full- year FFO was $516.4 million ($2.61 per share), compared to $879.8 million ($5.91 per share) in 2014. The decline in FFO is largely due to a decline in commodity prices.

We recorded a net loss in Q4/2015 of $412.9 million ($1.96 per share) compared to a net loss of $517.9 million ($2.49 per share) in Q3/2015. The net loss in the quarter is largely attributable to non-cash impairment charges of $499.6 million ($419.0 million after-tax) related to our Eagle Ford operations and $45.7 million related to assets in Canada. These impairment charges are directly attributable to the decline in commodity prices.

In Q4/2015, the average price for West Texas Intermediate light oil ("WTI") decreased to US$42.18/bbl, as compared to US$46.43/bbl in Q3/2015. This 9% decline in the benchmark index resulted in our realized price for light oil and condensate decreasing 9% to $50.17/bbl. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, widened to US$14.49/bbl in Q4/2015, as compared to US$13.30/bbl in Q3/2015. The widening differential and lower WTI price resulted in a 16% decrease in the price of WCS and a 21% decrease in our realized heavy oil price to $24.41/bbl.

We generated an operating netback in Q4/2015 of $12.32/boe ($16.41/boe including financial derivatives gains). The Eagle Ford generated an operating netback of $18.77/boe while our Canadian operations generated an operating netback of $5.73/boe. Our Eagle Ford 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 strong pricing, combined with low cash costs, contributed positively to our operating netback in Q4/2015.

During the quarter, we continued to focus on cost reduction initiatives across all of our operations. Operating expenses decreased 25% on a per boe basis as compared to Q4/2014, despite the impact of fixed costs on lower production in Canada. We are also benefiting from the Eagle Ford assets which have lower costs and comprise a larger percentage of our production. Transportation expenses have been reduced by 30% on a per boe basis as compared to Q4/2014, due to overall cost reduction initiatives in Canada, which include the use of internal trucking and decreased fuel charges.

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

Three Months Ended December 31

2015

2014

($ per boe)

Canada

Eagle Ford

Total

Total

Change

Sales price

$

23.59

$

36.56

$

30.03

$

53.72

(44 )%

Other income

-

-

0.11

0.76

(86 )%

Less:

Royalties

2.72

10.56

6.61

11.90

(44 )%

Operating expenses

12.27

7.23

9.76

12.95

(25 )%

Transportation expenses

2.87

-

1.45

2.07

(30 )%

Operating netback

$

5.73

$

18.77

$

12.32

$

27.56

(55 )%

Financial derivatives gain

-

-

4.09

6.48

(37 )%

Operating netback after financial derivatives

$

5.73

$

18.77

$

16.41

$

34.04

(52 )%

Baytex Energy Corp.

Press Release - March 3, 2016

Page 6

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 financial derivative gains of $30.4 million in Q4/2015 and $197.5 million for the full-year 2015. These gains were primarily due to crude oil prices being at levels significantly below those set in our fixed price contracts, which were partially offset by the settlement of our foreign exchange contracts.

For 2016, we have entered into hedges on approximately 45% of our net WTI exposure with 19% fixed at US$61.50/bbl and 26% hedged utilizing a 3-way collar structure (as described in the table below). We have also entered into hedges on approximately 35% of our net WCS differential exposure and 41% of our net natural gas exposure. The unrealized financial derivatives gain with respect to our hedges as at February 25, 2016 was $152.2 million. The following table summarizes our hedges in place as at March 3, 2016.

Q1/2016

Q2/1016

Q3/2016

Q4/2016

Full-Year 2016

Full-Year 2017

CRUDE OIL

WTI Fixed Hedges

Volumes (bbl/d)

9,000

8,000

5,000

5,000

6,750

-

Price (US$/bbl)

$60.45

$59.84

$63.79

$63.79

$61.50

-

WTI 3-Way Option

Volumes (bbl/d)

9,500

9,500

9,500

9,500

9,500

2,000

Average Ceiling/Floor/Sold Floor (US$/bbl) (2)

$60/$50/$40

$60/$50/$40

$60/$50/$40

$60/$50/$40

$60/$50/$40

$60/$50/$40

Total WTI Hedge Volumes (bbl/d)

18,500

17,500

14,500

14,500

16,250

2,000

Hedge (%) (1)

50%

49%

40%

40%

45%

6%

WCS Differential Hedges

Volumes (bbl/d)

4,333

8,000

7,000

7,000

6,583

1,500

WCS Price Relative to WTI (US$/bbl)

($13.33)

($13.26)

($13.32)

($13.40)

($13.33)

($13.42)

Hedge % (1)

23%

42%

37%

37%

35%

8%

NATURAL GAS

AECO Fixed Hedges

Volumes (gj/d)

18,333

20,000

20,000

20,000

19,583

5,000

Price ($/gj)

$2.88

$2.85

$2.85

$2.85

$2.86

$2.81

NYMEX Fixed Hedges

Volumes (mmbtu/d)

13,333

15,000

15,000

15,000

14,583

10,000

Price (US$/mmbtu)

$3.04

$2.98

$2.98

$2.98

$3.00

$2.83

Total Hedge Volume (mmbtu/d)

30,711

33,975

33,957

33,957

33,146

14,739

Hedge % (1)

38%

42%

42%

42%

41%

18%

Notes:

  1. Percentage of hedged volumes is based on the mid-point of our revised 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 December 31, 2015 was $1.88 billion, comprised of a bank loan of $257 million and senior unsecured notes of $1.62 billion. The increase in total long-term debt at December 31, 2015, as compared to September 30, 2015, was primarily due to the amount of our U.S. dollar denominated debt increasing when converted to Canadian dollars.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 7

We have unsecured revolving credit facilities consisting of an $800 million Canadian facility and a US$200 million U.S. facility. As at December 31, 2015, we had approximately $820 million in undrawn capacity on these facilities, which do not mature until June 2019.

Our bank lending syndicate agreed to relax the financial covenants contained in our unsecured revolving credit facilities twice during 2015. In each case, these amendments were obtained pro-actively, as we remained in compliance with our un-amended financial covenants throughout 2015. We will continue to manage our credit facilities and, if the outlook for commodity prices remains low or further deteriorates, we may seek further covenant relief. This could include granting our bank lending syndicate security over our assets. The indentures governing our senior unsecured notes provide that we may secure up to US$575 million of indebtedness in priority to the senior unsecured notes.

The following table lists the covenants under the revolving credit facilities and the senior unsecured notes, and our compliance therewith as at December 31, 2015.

Position as at

Covenant Description

December 31, 2015

Revolving Credit Facilities - Financial Covenants

Maximum Ratio

Senior Debt to Capitalization(1) (2)

0.65:1.00

0.44:1.00

Senior Debt to Bank EBITDA(1) (5)

5.25:1.00

2.97:1.00

Total Debt to Bank EBITDA(3) (5)

5.25:1.00

2.97:1.00

Senior Unsecured Notes - Debt Incurrence Covenant

Minimum Ratio

Fixed Charge Coverage(4)

2.50:1.00

5.63:1.00

Notes:

  1. "Senior debt" is defined as our principal amount of bank loan and long-term notes.
  2. "Capitalization" is defined as the sum of our principal amount of bank loan and long-term notes and shareholders' equity.
  3. "Total debt" is defined as the sum of our principal amount of bank loan and long-term notes, and certain other liabilities identified in the credit agreement.
  4. Fixed charge coverage is computed as the ratio of financing costs (excluding accretion on asset retirement obligations) to trailing twelve month adjusted income, as defined in the note indentures. Adjusted income for the trailing twelve months ended December 31, 2015 was $629 million.
  5. Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income for financing costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, amortization, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange, and stock based compensation) and acquisition and disposition activity (excluding acquisition-related costs incurred) and is calculated based on a trailing twelve month basis.

Outlook for 2016

As an industry, we continue to face unprecedented challenges due to the continued global oversupply of crude oil. We are committed to preserving financial liquidity through this downturn. In 2016, we are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings. In addition, we may contemplate minor non-core asset sales.

Our original 2016 production guidance was 74,000 to 78,000 boe/d with budgeted exploration and development expenditures of $325 to $400 million. This budget contemplated ramping up activity in Canada in the second half of 2016.

Based on the forward strip for the remainder of 2016, we do not plan to execute our heavy oil development program this year. We will forgo drilling 12 net wells at Peace River and 24 net wells at Lloydminster. In addition, we are proactively shutting-in approximately 7,500 bbl/d of 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. We currently anticipate that this production will be brought back on-linemid-year.

In the Eagle Ford, we now anticipate a reduced pace of development in 2016 with approximately four to five drilling rigs (six drilling rigs in Q4/2015) and one to two frac crews (two frac crews in Q4/2015) working on our lands. At this pace, we anticipate bringing approximately 30 net wells on production in 2016 (previously 35 to 40 net wells).

We now anticipate 2016 exploration and development expenditures of $225 to $265 million, of which approximately 95% will be invested in the Eagle Ford. At the mid-point, this reflects a 33% reduction in capital spending for 2016 relative to our initial expectation of $325 to $400 million and a 53% reduction relative to 2015 capital expenditures of $521 million. Our 2016 program will remain flexible and allows for adjustments to spending based on changes in the commodity price environment.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 8

Taking into account the shut-in heavy oil volumes and a reduced capital program, we have revised our production guidance range for 2016 to 68,000 to 72,000 boe/d. Our revised production guidance represents an approximate 5% reduction to our original guidance, excluding the impact of shut-in volumes. This compares to a 33% reduction in our capital budget, demonstrating the continued strong performance of our assets. Based on the mid-point of our production guidance range, approximately 55% of our production is expected to be generated in the Eagle Ford with the remaining 45% coming from our Canadian assets.

Production during the first quarter of 2016 is expected to average 73,000 to 75,000 boe/d.

Year-end 2015 Reserves

Baytex's year-end 2015 proved and probable reserves were evaluated by Sproule Unconventional Limited ("Sproule") and Ryder Scott Company, L.P. ("Ryder Scott"), both independent qualified reserves evaluators. Sproule prepared our reserves report by consolidating the Canadian properties evaluated by Sproule with the United States properties evaluated by Ryder Scott, in each case using Sproule's December 31, 2015 forecast price and cost assumptions. Ryder Scott also evaluated the possible reserves associated with our Eagle Ford assets. All of Baytex's oil and gas properties were evaluated or audited in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101"). Reserves associated with our thermal heavy oil projects at Peace River, Gemini (Cold Lake) and Kerrobert have been classified as bitumen. Finding and development ("F&D") and finding, development and acquisition ("FD&A") costs are all reported inclusive of future development costs ("FDC"). Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2015, which will be filed on or before March 30, 2016.

2015 Highlights

The addition of the Eagle Ford assets to our portfolio in 2014 provided us with exposure to one of the premier oil resource plays in North America. The high quality Eagle Ford assets provide the highest cash netbacks in our portfolio and contain a significant inventory of development prospects. In 2015, we focused our development activity in the Eagle Ford, where we directed 86% of our exploration and development expenditures. Our 2015 reserves report reflect this investment profile with significant growth in Eagle Ford reserves, offset by reduced heavy oil and thermal reserves.

  • Excluding thermal reductions, our proved plus probable reserves increased 2% to 347 mmboe and we replaced 122% of production. Year-end 2015 proved plus probable reserves are comprised of 81% oil and NGL and 19% natural gas.
  • In the Eagle Ford, proved plus probable reserves increased 8% to 203 mmboe and we replaced 205% of production. From the time of acquisition in June 2014, we have increased our proved plus probable reserves by 22%.
  • In aggregate, proved reserves decreased 3% to 275 mmboe and proved plus probable reserves decreased 3% to 417 mmboe, due largely to shifting thermal reserves to contingent resources at Cliffdale as activities fall outside our five year investment plan and the removal of heavy oil reserves due to reduced commodity prices and other technical revisions.
  • Proved developed producing ("PDP") reserves represent 40% of our proved reserves (versus 43% at year-end 2014) and proved reserves represent 66% of proved plus probable reserves (unchanged from year-end 2014).
  • We realized F&D costs of $7.68/boe on a proved plus probable basis, and a three-year average (2013-2015) of $17.59/boe. Based on our 2015 operating netback (excluding financial derivative gains) of $15.78/boe, we generated a strong recycle ratio of 2.1x in 2015.
  • We realized FD&A costs of $7.75/boe on a proved plus probable basis, and a three-year average (2013-2015) of $26.33/boe. Based on our 2015 operating netback (excluding financial derivative gains) of $15.78/boe, we generated a strong recycle ratio of 2.0x in 2015.
  • We achieved a significant reduction in our future development costs from $3.4 billion at year-end 2014 to $3.0 billion at year-end 2015. This was mainly attributable to decrease in drilling, completions and facility capital costs, as well as the removal of capital associated with a reduction in our thermal reserves.
  • Strong reserves life index ("RLI") of 9.3 years on a proved basis and 14.1 years on a proved plus probable basis, which is calculated using annualized Q4/2015 production.
  • Using the December 31, 2015 independent reserves evaluation, the present value of our reserves, discounted at 10% before tax, is estimated to be $4.3 billion.
  • Our estimated net asset value at year-end 2015, discounted at 10%, is estimated to be $11.05 per share. This is based on the estimated reserves value of $4.3 billion plus a value for undeveloped acreage, net of long-term debt, asset retirement obligations and working capital.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 9

The following tables reconcile the change in reserves during 2015 by reserves category and operating area.

Total

Canada

Excluding

(gross reserves, mmboe)

Eagle Ford

Heavy Oil

Conventional

Thermal

Thermal

Total

Proved Developed Producing

54.8

45.2

10.9

110.9

9.8

120.7

December 31, 2014

Additions, net of revisions

20.1

4.4

2.8

27.3

(8.4)

18.8

Production

(14.6)

(12.4)

(3.1)

(30.1)

(0.9)

(30.9)

December 31, 2015

60.3

37.2

10.6

108.1

0.5

108.6

% Change

10%

(18%)

(3%)

(3%)

(95%)

(10%)

Proved

167.3

81.5

16.4

265.2

18.1

283.3

December 31, 2014

Additions, net of revisions

22.2

(0.7)

4.3

25.8

(3.4)

22.4

Production

(14.6)

(12.4)

(3.1)

(30.1)

(0.9)

(30.9)

December 31, 2015

174.9

68.4

17.6

260.9

13.8

274.8

% Change

5%

(16%)

7%

(2%)

(24%)

(3%)

Proved Plus Probable

188.0

122.1

30.4

340.5

91.1

431.6

December 31, 2014

Additions, net of revisions

29.9

(2.9)

9.5

36.5

(20.6)

15.9

Production

(14.6)

(12.4)

(3.1)

(30.1)

(0.9)

(30.9)

December 31, 2015

203.4

106.8

36.8

347.0

69.6

416.6

% Change

8%

(13%)

21%

2%

(24%)

(3%)

Eagle Ford

  • The success of our 2015 capital development program and the significant advancements made to delineate the multi- zone development potential of our Sugarkane acreage, resulted in strong reserves additions in the Eagle Ford. In the Eagle Ford, we replaced 205% of production, and increased our proved plus probable reserves by 8% to 203.4 mmboe.
  • Ryder Scott assigned a total of 184 net proved undeveloped and probable well locations in the year-end reserves report. Approximately 87% of the well locations are targeting the Lower Eagle Ford formation with the remainder attributable to the Austin Chalk. We have not assigned any undeveloped locations to the Upper Eagle Ford formation in our proved plus probable reserves.
  • In addition to our proved plus probable reserves, we have recognized 144 mmboe of possible reserves. The possible reserves reflect the significant upside potential of the Austin Chalk and Upper Eagle Ford formations. Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves

Heavy Oil

  • Reserves associated with our heavy oil assets are located at Peace River and Lloydminster. Proved plus probable heavy oil reserves at year-end 2015 totalled 106.8 mmboe, down 13% from 122.1 mmboe at year-end 2014. In 2015, our development activity was significantly curtailed due to low crude oil prices. At Peace River, we drilled 6 (6.0 net) cold horizontal production wells and 5 (5.0 net) stratigraphic test wells. At Lloydminster, we drilled 26 (17.4 net) oil wells.
  • We realized 7.5 mmboe of reserves additions at Peace River and Lloydminster in 2015. These reserves additions were offset by the removal of reserves due to the decrease in commodity prices since year-end 2014 and other technical revisions. On a proved plus probable basis, negative technical revisions amounted to 6.9 mmboe and a further 3.6 mmboe were removed due to lower commodity prices.

Conventional - Canada

  • Reserves associated with our conventional light oil and natural gas assets in Canada increased 21% to 36.8 mmboe, resulting in production replacement of 306%. Reserves additions were driven by strong well performance and the identification of additional drilling locations from our liquids-rich natural gas development in the Pembina/O'Chiese region of west-central Alberta.

Baytex Energy Corp.

Press Release - March 3, 2016

Page 10

Bitumen (Thermal)

  • Reserves associated with our thermal heavy oil projects at Peace River, Gemini (Cold Lake) and Kerrobert are classified as bitumen, in accordance with NI 51-101. Proved plus probable bitumen reserves at year-end 2015 totalled 69.6 mmbbls, down 24% from 91.1 mmbbls at year-end 2014, and now represent 17% of our proved plus probable reserves, compared to 21% at year-end 2014 and 32% at year-end 2013.
  • During the third quarter of 2015, as crude oil prices continued to deteriorate, we suspended operations at our Cliffdale Cyclical Steam Stimulation project. With no production at Cliffdale at year-end 2015, 7.0 mmbbls of proved developed producing reserves were reclassified as proved developed non-producing. In addition, we transferred 19.3 mmbbls of proved plus probable reserves associated with Pads 3 and 4 to contingent resources as this development is now expected to occur outside our five-year business plan.
  • At Gemini, we decommissioned our steam-assisted gravity drainage pilot project in the second quarter of 2015. Through the pilot we confirmed reservoir production capacity to support a commercial 5,000 bbl/d project. Any subsequent sanctioning decision will be considered in the context of the project economics in a higher commodity price environment. Our proved plus probable bitumen reserves at Gemini were unchanged at year-end 2015 at 43.4 mmbbls.

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Baytex Energy Corp. published this content on 13 December 2023 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 13 December 2023 14:20:09 UTC.