EX-99.3 4 a2016yemda993.htm EXHIBIT 99.3
Baytex Energy Corp.
2016 MD&A Page 1

Exhibit 99.3
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the years ended December 31, 2016 and 2015
Dated March 6, 2017
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the years ended December 31, 2016 and 2015. This information is provided as of March 6, 2017. 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 results for the year ended December 31, 2016 ("2016") have been compared with the results for the year ended December 31, 2015 ("2015") and the results for the three months ended December 31, 2016 ("Q4/2016") have been compared with the results for the three months ended December 31, 2015 ("Q4/2015"). This MD&A should be read in conjunction with the Company’s audited consolidated financial statements (“consolidated financial statements”) for the years ended December 31, 2016 and 2015, together with the accompanying notes and the Annual Information Form for the year ended December 31, 2016. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. 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.
CAPITAL MANAGEMENT MEASURES
In this MD&A, we refer to certain capital management measures as outlined in note 22 to the consolidated financial statements, such as funds from operations and net debt which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). While funds from operations and net debt 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
We consider 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. We believe that this measure provides a meaningful assessment of our operations by eliminating certain non-cash charges. 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 to funds from operations.

| Years Ended December 31
($ thousands) | 2016 |  | 2015 |
Cash flow from operating activities | $ | 247,365 |  | $ | 549,420 |
Change in non-cash working capital | 23,270 |  | (43,891 | )
Asset retirement expenditures | 5,616 |  | 10,888 |
Funds from operations | $ | 276,251 |  | $ | 516,417 |

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Net Debt
We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity.
The following table summarizes our calculation of net debt.

($ thousands) | December 31, 2016 |  | December 31, 2015 |
Bank loan(1) | $ | 191,286 |  | $ | 256,749 |
Long-term notes(1) | 1,584,158 |  | 1,623,658 |
Working capital (surplus) deficiency(2) | (1,903 | ) | 169,498 |
Net debt | $ | 1,773,541 |  | $ | 2,049,905 |

(1) | Principal amount of instruments expressed in Canadian dollars.

(2) | Working capital is current assets less current liabilities (excluding current financial derivatives and onerous contracts).

NON-GAAP FINANCIAL MEASURES
In this MD&A, we refer to certain financial measures (such as operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by GAAP. While operating netback and EBITDA 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. We believe that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze against prior periods on a comparable basis.
Operating Netback
We define operating netback as oil and natural gas revenue, less royalties, operating expense and transportation expense. 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.

| Years Ended December 31
($ thousands) | 2016 | 2015
Petroleum and natural gas revenue | 780,095 |  | 1,121,424 |
Blending expense | (9,622 | ) | (27,830 | )
Oil and natural gas revenue | 770,473 |  | 1,093,594 |
Royalties | 178,116 |  | 241,425 |
Operating expense | 240,705 |  | 320,187 |
Transportation expense | 28,257 |  | 53,127 |
Operating netback | 323,395 |  | 478,855 |
Realized financial derivative gain | 96,929 |  | 197,545 |
Operating netback after realized financial derivatives gain | 420,324 |  | 676,400 |

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Bank EBITDA
Bank EBITDA is used to assess compliance with certain financial covenants. The following table reconciles net income (loss) to Bank EBITDA.

| Years Ended December 31
($ thousands) | 2016 |  | 2015 |
Net income (loss) | $ | (485,184 | ) | $ | (1,142,880 | )
Plus: |  |
Financing and interest | 114,199 |  | 111,660 |
Unrealized foreign exchange (gain) loss | (41,436 | ) | 213,999 |
Unrealized financial derivatives loss | 140,136 |  | 54,816 |
Current income tax (recovery) expense | (8,042 | ) | 8,907 |
Deferred income tax (recovery) | (264,561 | ) | (353,053 | )
Depletion and depreciation | 508,309 |  | 661,858 |
Impairment | 423,176 |  | 1,038,554 |
Disposition of oil and gas properties (gain) loss | (43,907 | ) | 1,519 |
Non-cash items(1) | 29,974 |  | 33,348 |
Bank EBITDA | $ | 372,664 |  | $ | 628,728 |

(1) Non-cash items include share-based compensation, exploration and evaluation expense and non-cash other expense.
YEAR END HIGHLIGHTS
2016 presented many challenges for the oil and gas industry and for Baytex. With the low commodity price environment, we made significant adjustments to our business to maintain strong levels of financial liquidity. We reduced our capital spending, emphasized cost reductions in all facets of the business, renegotiated our credit facilities, raised equity to fund an acquisition that closed in early 2017 and disposed of certain non-core assets.
Production for the year averaged 69,509 boe/d, which was consistent with our guidance of 68,000 - 70,000 boe/d. In the Eagle Ford, production averaged 36,573 boe/d, an 8% decrease from 2015. The reduced number of completions combined with the sale of approximately 1,000 boe/d of operated production contributed to the decrease on our Eagle Ford assets from 2015. In Canada, production was 32,936 boe/d for 2016 compared to 44,691 boe/d in 2015. Due to the low price environment, we deferred all operated heavy oil drilling including development and stratigraphic test wells. This reduced level of activity caused production to decrease from 2015. In addition, we shut in production with low or negative margins for part of the year which reduced annual average production by approximately 2,400 boe/d.
Oil prices were at multi-year low levels in 2016 with continued over supply and high inventory levels. In Q1/2016, the price of West Texas Intermediate light oil ("WTI") averaged US$33.45/bbl. Prices stabilized in Q2/2016 and Q3/2016 with WTI averaging approximately US$45/bbl before the Organization of the Petroleum Exporting Countries (“OPEC”) announcement on November 30, 2016 which resulted in WTI oil prices rising above US$50/bbl for the last part of 2016. WTI averaged US$43.33/bbl during 2016 compared to US$48.79/bbl in 2015 representing a decrease of $5.48/bbl. Natural gas prices also decreased from 2015 with AECO decreasing 24% from $2.74/mcf in 2015 to $2.09/mcf in 2016 and NYMEX decreasing 8% from US$2.66/mmbtu in 2015 to US$2.46/mmbtu in 2016. The large AECO discount to Henry Hub is due to the oversupply of gas in the Western Canadian Sedimentary Basin. The decrease in commodity prices during 2016 reduced our revenue per boe to $30.29/boe from $35.40/boe for 2015.
During 2016, we successfully reduced our cost structure to help mitigate some of the commodity price decrease. In the Eagle Ford, the costs to drill, complete and equip our wells decreased throughout the year and averaged approximately US$4.5 million per well in Q4/2016, as compared to US$8.2 million per well in late 2014. Operating expenses per boe were reduced 9% to $9.46/boe for 2016, as compared to $10.36/boe for 2015, and transportation expenses per boe decreased 35% to $1.11/boe in 2016, as compared to $1.72/boe in 2015. These reductions reflect a combination of a lower overall cost structure combined with the lower cost Eagle Ford assets representing a larger percentage of our total production. General and administrative expenses were reduced to $50.9 million in 2016 from $59.4 million in 2015.
Throughout 2016, we targeted our capital expenditures to approximate FFO in order to minimize additional bank borrowings. For 2016, our FFO totaled $276.3 million compared to capital expenditures of $224.8 million. Capital expenditures were focused on our Eagle Ford assets where we invested $198.9 million to drill 127 (36.9 net) wells and commenced production from 123 (36.3 net) wells. In Canada, capital expenditures were limited to $25.9 million with drilling limited to 15 (4.0 net) wells mainly focused on non-operated lands in Lloydminster.
In Q4/2016, we entered an agreement to acquire assets in the Peace River area of Alberta for approximately $65 million and also completed a $115 million equity financing to fund the acquisition. The equity financing closed on December 12, 2016 with 21.9 million

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shares being issued for proceeds of $109.9 million (net of issue costs). The acquisition closed subsequent to year end on January 20, 2017.
We generated FFO of $276.3 million ($1.30 per basic and diluted share) during 2016 compared to $516.4 million ($2.61 per basic and diluted share) in 2015. The decrease in FFO is primarily due to lower realized pricing, lower production volumes and lower realized hedging gains.
In 2016, our FFO exceeded our capital expenditures net of asset sales by $115 million. This, along with the proceeds from the equity financing and a decrease in the CAD/USD exchange rate, contributed to our net debt decreasing by $276 million from December 31, 2015 to $1.77 billion at December 31, 2016. We also had approximately $580 million of undrawn credit capacity and are in compliance with all of our financial covenants as at December 31, 2016.
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

| Years Ended December 31
| 2016 | 2015
Daily Production | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Liquids (bbl/d) |  |  |  |  |  |  |  |  |
Heavy oil | 23,586 |  | — |  | 23,586 |  | 34,974 |  | — |  | 34,974 |
Light oil and condensate | 1,407 |  | 19,970 |  | 21,377 |  | 1,828 |  | 24,059 |  | 25,887 |
NGL | 1,274 |  | 8,075 |  | 9,349 |  | 1,070 |  | 7,422 |  | 8,492 |
Total liquids (bbl/d) | 26,267 |  | 28,045 |  | 54,312 |  | 37,872 |  | 31,481 |  | 69,353 |
Natural gas (mcf/d) | 40,015 |  | 51,167 |  | 91,182 |  | 40,911 |  | 50,855 |  | 91,766 |
Total production (boe/d) | 32,936 |  | 36,573 |  | 69,509 |  | 44,691 |  | 39,957 |  | 84,648 |
Production Mix |  |  |  |  |  |
Heavy oil | 72 | % | — | % | 34 | % | 79 | % | — | % | 41 | %
Light oil and condensate | 4 | % | 55 | % | 31 | % | 4 | % | 61 | % | 31 | %
NGL | 4 | % | 22 | % | 13 | % | 2 | % | 19 | % | 10 | %
Natural gas | 20 | % | 23 | % | 22 | % | 15 | % | 20 | % | 18 | %

Production for 2016 averaged 69,509 boe/d, an 18% decrease from 2015. U.S. production averaged 36,573 boe/d in 2016, an 8% decrease from 2015 as a result of decreased capital investment and the sale of approximately 1,000 boe/d of operated production in the Eagle Ford. Canadian production of 32,936 boe/d decreased 26%, or 11,755 boe/d, from 2015 with minimal capital investment along with low or negative margin production that was shut-in for part of 2016. The shut-in volumes reduced 2016 average production by approximately 2,400 boe/d.
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
Crude oil was extremely volatile during 2016 as the global over supply of crude oil combined with elevated inventory levels weighed on the price. In Q1/2016, WTI crude oil prices hit a 13-year low of US$26.21/bbl. During Q2/2016 and Q3/2016, prices were stabilized and averaged approximately US$45/bbl. On November 30, 2016, OPEC and non-OPEC countries agreed to production cuts which resulted in oil prices rising above US$50/bbl for the last part of 2016. WTI averaged US$49.29/bbl for Q4/2016, a 10% increase compared to Q3/2016. For 2016, WTI averaged US$43.33/bbl, representing an 11% decrease from the average WTI price of US$48.79/bbl for 2015.
The discount for Canadian heavy oil is measured by the Western Canadian Select ("WCS") price differential to WTI. For 2016, the WCS heavy oil differential averaged US$13.84/bbl, as compared to US$13.53/bbl for 2015. Over the past year, increased pipeline capacity from Canada to the U.S. Gulf Coast combined with lower overall production levels have helped to stabilize the WCS heavy oil differential.

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Natural Gas
Natural gas prices have been driven lower during 2016 compared to 2015 mainly due to production levels exceeding demand. For 2016, the AECO natural gas price averaged $2.09/mcf, a decrease of $0.65/mcf or 24% compared to $2.74/mcf in 2015. The NYMEX natural gas price averaged US$2.46/mmbtu during 2016, representing a decrease of US$0.20/mmbtu or 8% compared to US$2.66/mmbtu in 2015. AECO continues to trade at a significant discount to NYMEX due to the oversupply in Western Canada combined with pipeline constraints.
The following table compares selected benchmark prices and our average realized selling prices for the years ended December 31, 2016 and 2015.

| Years Ended December 31
| 2016 |  | 2015 |  | Change |
Benchmark Averages |  |  |
WTI oil (US$/bbl)(1) | 43.33 |  | 48.79 |  | (11 | )%
WTI oil (CAD$/bbl) | 57.44 |  | 62.50 |  | (8 | )%
WCS heavy oil (US$/bbl)(2) | 29.49 |  | 35.26 |  | (16 | )%
WCS heavy oil (CAD$/bbl) | 39.09 |  | 45.17 |  | (13 | )%
LLS oil (US$/bbl)(3) | 43.82 |  | 51.50 |  | (15 | )%
LLS oil (CAD$/bbl) | 58.08 |  | 65.98 |  | (12 | )%
CAD/USD average exchange rate | 1.3256 |  | 1.2811 |  | 3 | %
Edmonton par oil ($/bbl) | 53.01 |  | 57.20 |  | (7 | )%
AECO natural gas price ($/mcf)(4) | 2.09 |  | 2.74 |  | (24 | )%
NYMEX natural gas price (US$/mmbtu)(5) | 2.46 |  | 2.66 |  | (7 | )%

(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.

| Years Ended December 31
| 2016 | 2015
| Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Average Realized Sales Prices(1) |  |  |  |  |  |
Canadian heavy oil ($/bbl)(2) | $ | 26.46 |  | $ | — |  | $ | 26.46 |  | $ | 32.23 |  | $ | — |  | $ | 32.23 |
Light oil and condensate ($/bbl) | 46.21 |  | 50.60 |  | 50.32 |  | 52.52 |  | 55.99 |  | 55.75 |
NGL ($/bbl) | 17.77 |  | 17.06 |  | 17.16 |  | 20.80 |  | 16.35 |  | 16.91 |
Natural gas ($/mcf) | 2.01 |  | 3.21 |  | 2.69 |  | 2.59 |  | 3.47 |  | 3.08 |
Weighted average ($/boe)(2) | $ | 24.06 |  | $ | 35.89 |  | $ | 30.29 |  | $ | 30.24 |  | $ | 41.16 |  | $ | 35.40 |

(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.

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Average Realized Sales Prices
During 2016, we realized $50.60/bbl for our U.S. light oil and condensate. This was down from $55.99/bbl or approximately 10% from 2015, which is slightly less than the 12% decrease in the LLS benchmark (expressed in Canadian dollars) over the same period. Reduced supply along with increased pipeline capacity have tightened the pricing differential between our realized U.S. light oil and condensate pricing to LLS during 2016 compared to 2015.
Our realized Canadian light oil and condensate price averaged $46.21/bbl for 2016 compared to $52.52/bbl for 2015. This represents a 12% decrease in 2016 which is higher than the 7% decrease in the benchmark Edmonton par price over the same period. Our Canadian realized price decreased slightly more than the benchmark when comparing 2016 to 2015 as a higher percentage of our Canadian light oil production in 2016 was comprised of medium grade crude which has a higher discount to the benchmark price.
In 2016, our realized heavy oil price was $26.46/bbl, a $5.77/bbl decrease from 2015. The decrease in our realized heavy oil price during 2016 is generally consistent with the decrease in the WCS benchmark price (expressed in Canadian dollars) of $6.08/bbl over the same period. Our heavy oil is generally sold at a fixed dollar differential to the benchmark price. Our realized price decreased slightly less than the benchmark as the volumes that were shut-in during part of 2016 had a higher discount to the benchmark price resulting in slightly better price realizations during 2016.
Our Canadian average realized natural gas price was $2.01/mcf for 2016, down 22% from the same period in 2015. The decrease in our realized prices during 2016 was consistent with the decrease in the AECO benchmark of 24% over the same period.
Our U.S. realized natural gas price was $3.21/mcf for 2016, down 7% from 2015 which is consistent with the decrease in the NYMEX benchmark of 7% over the same period.
For 2016, our realized NGL price was $17.16/bbl or 30% of WTI (expressed in Canadian dollars) compared to $16.91/bbl or 27% of WTI in 2015. The change in our realized price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes.
Gross Revenues

| Years Ended December 31
| 2016 | 2015
($ thousands) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Oil revenue |  |  |  |  |  |  |  |  |  |
Heavy oil | $ | 228,425 |  | $ | — |  | $ | 228,425 |  | $ | 411,386 |  | $ | — |  | $ | 411,386 |
Light oil and condensate | 23,792 |  | 369,869 |  | 393,661 |  | 35,044 |  | 491,700 |  | 526,744 |
NGL | 8,287 |  | 50,416 |  | 58,703 |  | 8,121 |  | 44,286 |  | 52,407 |
Total liquids revenue | 260,504 |  | 420,285 |  | 680,789 |  | 454,551 |  | 535,986 |  | 990,537 |
Natural gas revenue | 29,506 |  | 60,178 |  | 89,684 |  | 38,723 |  | 64,334 |  | 103,057 |
Total oil and natural gas revenue | 290,010 |  | 480,463 |  | 770,473 |  | 493,274 |  | 600,320 |  | 1,093,594 |
Heavy oil blending revenue | 9,622 |  | — |  | 9,622 |  | 27,830 |  | — |  | 27,830 |
Total petroleum and natural gas revenues | $ | 299,632 |  | $ | 480,463 |  | $ | 780,095 |  | $ | 521,104 |  | $ | 600,320 |  | $ | 1,121,424 |

Total oil and natural gas revenues for 2016 of $770.5 million decreased by $323.1 million or 30% from 2015 due to a combination of lower commodity prices and reduced production volumes. Oil and natural gas revenues per boe decreased 14% in 2016 compared to 2015, which accounted for $158 million of the reduction in oil and natural gas revenue year over year. The decrease in production accounts for the remaining $165 million difference in revenue from 2015. Oil and natural gas revenues of $480.5 million in the U.S. decreased $119.9 million from 2015 mainly due to the $5.27/boe decrease in oil and gas revenues per boe resulting from lower commodity prices. In Canada, oil and natural gas revenues for 2016 totaled $290.0 million, a $203.3 million decrease compared to 2015 due to lower production volumes and lower realized prices.
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. Heavy oil blending revenue of $9.6 million for 2016 decreased $18.2 million compared to 2015. This decrease is a result of lower heavy oil production in Canada combined with lower overall prices for diluent in 2016 compared to 2015.

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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 the years ended December 31, 2016 and 2015.

| Years Ended December 31
| 2016 | 2015
($ thousands except for % and per boe) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Royalties | $ | 37,720 |  | $ | 140,396 |  | $ | 178,116 |  | $ | 67,323 |  | $ | 174,102 |  | $ | 241,425 |
Average royalty rate(1) | 13.0 | % | 29.2 | % | 23.1 | % | 13.6 | % | 29.0 | % | 22.1 | %
Royalty rate per boe | $ | 3.13 |  | $ | 10.49 |  | $ | 7.00 |  | $ | 4.13 |  | $ | 11.94 |  | $ | 7.81 |

(1) | Average royalty rate excludes sales of heavy oil blending diluents and financial derivatives gain (loss).

Total royalties for 2016 of $178.1 million decreased by $63.3 million or 26%, from 2015, primarily due to the 29% decline in oil and natural gas revenues. Total royalties decreased less than revenues as the Eagle Ford, which has a higher royalty rate, represented approximately 62% of oil and natural gas revenues in 2016 compared to approximately 55% in 2015. Canadian royalties, which vary with price, decreased to 13.0% of oil and natural gas revenue for 2016 compared to 13.6% of revenue in 2015, primarily due to lower commodity prices. The royalty percentage on our U.S. assets does not vary with price and as a result the 2016 U.S. royalty rate has remained fairly consistent with the 2015 rate.
Operating Expense

| Years Ended December 31
| 2016 | 2015
($ thousands except for per boe) | Canada |  | U.S.(1) |  | Total |  | Canada |  | U.S.(1) |  | Total |
Operating expense | $ | 142,242 |  | $ | 98,463 |  | $ | 240,705 |  | $ | 210,945 |  | $ | 109,242 |  | $ | 320,187 |
Operating expense per boe | $ | 11.80 |  | $ | 7.36 |  | $ | 9.46 |  | $ | 12.93 |  | $ | 7.49 |  | $ | 10.36 |

(1) | Operating expense related to the Eagle Ford assets includes transportation expense.

Operating expense of $240.7 million for 2016 decreased by $79.5 million or 25%, compared to 2015. Overall operating costs are down as production has decreased in 2016 compared to 2015. Operating expense are also down on a unit of production basis with operating costs decreasing to $9.46/boe for 2016, compared to $10.36/boe for 2015 representing a 9% decrease. In Canada, the impact of our cost savings initiatives along with the benefit of shutting-in higher cost properties for part of 2016 resulted in lower operating expenses per unit of production for 2016 compared to 2015. Also, the lower cost Eagle Ford assets comprise a larger proportion of our overall volumes which has helped reduce our overall operating costs per boe.
U.S. operating expense of $98.5 million for 2016 decreased by $10.8 million compared to 2015 primarily due to the decrease in production. On a unit of production basis, U.S operating expenses for 2016 decreased slightly to $7.36/boe compared to $7.49/boe for 2015. On a U.S. dollar basis, operating expenses per boe decreased 5% in 2016 compared to 2015 but the Canadian dollar weakened against the U.S. dollar which partially mitigated the impact of the operating cost savings expressed in Canadian dollars.
Canadian operating expense of $142.2 million for 2016, decreased by $68.7 million or 33%, compared to 2015. The decrease is a result of lower production volumes combined with realized cost savings across all of our operations. On a per boe basis, Canadian operating expense was $11.80/boe for 2016 down 9% compared to $12.93/boe in 2015. The decrease in 2016 reflects the cost savings initiatives during the year combined with the impact of higher cost production being shut-in for part of 2016.

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Transportation Expense
Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of heavy oil in Canada to pipeline and rail terminals. The following table compares our transportation expense for the years ended December 31, 2016 and 2015.

| Years Ended December 31
| 2016 | 2015
($ thousands except for per boe) | Canada |  | U.S.(1) |  | Total |  | Canada |  | U.S.(1) |  | Total |
Transportation expense | $ | 28,257 |  | $ | — |  | $ | 28,257 |  | $ | 53,127 |  | $ | — |  | $ | 53,127 |
Transportation expense per boe | $ | 2.34 |  | $ | — |  | $ | 1.11 |  | $ | 3.26 |  | $ | — |  | $ | 1.72 |

(1) Transportation expense related to the Eagle Ford assets have been included in operating expenses.
Transportation expense for 2016 totaled $28.3 million representing a decrease of 47% from $53.1 million in 2015. The decrease is due to lower heavy oil volumes being transported combined with the increased use of lower cost internal trucking. Transportation expense is also down on a per unit of production basis in 2016 to $2.34/boe in Canada compared to $3.26/boe in 2015. The use of lower cost internal trucking and shut-in volumes, which were generally subject to higher transportation charges explains the decrease from 2015.
Blending Expense
Blending expense for 2016 of $9.6 million decreased $18.2 million or 67% compared to $27.8 million for 2015. Consistent with the 65% decrease in heavy oil blending revenue, blending expense decreased due to lower volumes of blending diluent being used combined with the decrease in diluent prices in 2016 compared to 2015.
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 the year ended December 31, 2016 and 2015.

| Years Ended December 31
($ thousands) | 2016 |  | 2015 |  | Change |
Realized financial derivatives gain (loss) |  |  |
Crude oil | $ | 88,860 |  | $ | 235,393 |  | $ | (146,533 | )
Natural gas | 8,069 |  | 8,549 |  | (480 | )
Foreign currency | — |  | (46,397 | ) | 46,397 |
Total | $ | 96,929 |  | $ | 197,545 |  | $ | (100,616 | )
Unrealized financial derivatives gain (loss) |  |  |
Crude oil | $ | (122,249 | ) | $ | (70,354 | ) | $ | (51,895 | )
Natural gas | (17,887 | ) | 968 |  | (18,855 | )
Foreign currency | — |  | 15,068 |  | (15,068 | )
Interest and financing(1) | — |  | (498 | ) | 498 |
Total | $ | (140,136 | ) | $ | (54,816 | ) | $ | (85,320 | )
Total financial derivatives gain (loss) |  |  |
Crude oil | $ | (33,389 | ) | $ | 165,039 |  | $ | (198,428 | )
Natural gas | (9,818 | ) | 9,517 |  | (19,335 | )
Foreign currency | — |  | (31,329 | ) | 31,329 |
Interest and financing | — |  | (498 | ) | 498 |
Total | $ | (43,207 | ) | $ | 142,729 |  | $ | (185,936 | )

(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 $96.9 million for 2016 is a result of crude oil prices being at levels below those set in our fixed price contracts.

Baytex Energy Corp.
2016 MD&A Page 9

The unrealized financial derivatives loss of $140.1 million for 2016 is due to the realization, or reversal, of previous unrealized gains recorded at December 31, 2015 and from the increase in WTI futures price subsequent to December 31, 2015. At December 31, 2016, the fair value of our financial derivative contracts represent a net liability of $29.1 million compared to a net asset of $111.0 million at December 31, 2015.
For 2017, we have entered into hedges on approximately 51% of our net WTI exposure with 10% fixed at US$54.46/bbl and 41% hedged utilizing a 3-way option structure that provide us with downside price protection at approximately US$47/bbl and upside participation to approximately US$59/bbl. We have also entered into hedges on approximately 33% of our net WCS differential exposure and 57% of our net natural gas exposure.
Baytex had the following commodity financial derivative contracts as at March 6, 2017.

| Period | Volume | Price/Unit(1) |  | Index
Oil |  |  |  |
3-way option(2) | Jan 2017 to Dec 2017 | 14,500 bbl/d | US$58.60/US$47.17/US$37.24 |  | WTI
Basis swap | Jan 2017 to Dec 2017 | 1,500 bbl/d | WTI less US$13.42 |  | WCS
Fixed - Sell | Jan 2017 to Dec 2017 | 3,500 bbl/d |  | US$54.46 |  | WTI
Fixed - Sell | Jan 2018 to Dec 2018 | 2,000 bbl/d |  | US$54.40 |  | WTI
Basis swap(3) | Mar 2017 to Jun 2017 | 1,000 bbl/d | WTI less US$14.30 |  | WCS
Basis swap(3) | Apr 2017 to Jun 2017 | 2,000 bbl/d | WTI less US$13.50 |  | WCS
Basis swap(3) | Jul 2017 to Sep 2017 | 2,000 bbl/d | WTI less US$14.25 |  | WCS
Natural Gas |  |  |  |
Fixed - Sell | Jan 2017 to Dec 2017 | 22,500 mmBtu/d |  | US$2.98 |  | NYMEX
Fixed - Sell | Jan 2018 to Dec 2018 | 7,500 mmBtu/d |  | US$3.00 |  | NYMEX
Fixed - Sell | Jan 2017 to Dec 2017 | 22,500 GJ/d |  | $2.85 |  | AECO
Fixed - Sell | Jan 2018 to Dec 2018 | 5,000 GJ/d |  | $2.67 |  | AECO

(1) | Based on the weighted average price/unit for the remainder of the contract.

(2) | 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$60/US$50/US$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 the market price 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) | Contracts entered subsequent to December 31, 2016.

A full description of our financial derivatives can be found in note 18 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:

| Years Ended December 31
| 2016 | 2015
($ per boe except for volume) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Sales volume (boe/d) | 32,936 |  | 36,573 |  | 69,509 |  | 44,691 |  | 39,957 |  | 84,648 |
Operating netback: |  |  |  |  |  |
Oil and natural gas revenues | $ | 24.06 |  | $ | 35.89 |  | $ | 30.29 |  | $ | 30.24 |  | $ | 41.16 |  | $ | 35.40 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Royalties | 3.13 |  | 10.49 |  | 7.00 |  | 4.13 |  | 11.94 |  | 7.81 |
Operating expenses | 11.80 |  | 7.36 |  | 9.46 |  | 12.93 |  | 7.49 |  | 10.36 |
Transportation expenses | 2.34 |  | — |  | 1.11 |  | 3.26 |  | — |  | 1.72 |
Operating netback | $ | 6.79 |  | $ | 18.04 |  | $ | 12.72 |  | $ | 9.92 |  | $ | 21.73 |  | $ | 15.51 |
Realized financial derivatives gain | — |  | — |  | 3.81 |  | — |  | — |  | 6.39 |
Operating netback after financial derivatives gain | $ | 6.79 |  | $ | 18.04 |  | $ | 16.53 |  | $ | 9.92 |  | $ | 21.73 |  | $ | 21.90 |

Baytex Energy Corp.
2016 MD&A Page 10

Exploration and Evaluation Expense
Exploration and evaluation expense will vary from period to period depending on the expiry of leases and assessment of our exploration programs and assets. Exploration and evaluation expense was $6.0 million for 2016, as compared to $8.8 million for 2015. The decrease in expense in 2016 compared to 2015 is due to lower expiries of undeveloped land.
Depletion and Depreciation

| Years Ended December 31
| 2016 | 2015
($ thousands except for per boe) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Depletion and depreciation(1) | $ | 210,778 |  | $ | 294,854 |  | $ | 508,309 |  | $ | 279,744 |  | $ | 377,847 |  | $ | 661,858 |
Depletion and depreciation per boe | $ | 17.49 |  | $ | 22.03 |  | $ | 20.04 |  | $ | 17.15 |  | $ | 25.91 |  | $ | 21.42 |

(1) | Total includes corporate depreciation.

Depletion and depreciation expense of $508.3 million for 2016, decreased by $153.5 million or 23% from 2015 mainly due to lower production. On a per boe basis, depletion and depreciation expense for 2016 was also down coming in at $20.04/boe, compared to $21.42/boe for 2015. The overall depletion rate has decreased in 2016 as we recorded $709.9 million of impairments on U.S. oil and gas properties in 2015 which reduced the depletable asset base along with the depletion rate per boe.
Impairment
In 2016, we recorded total impairment expense of $423.2 million. This impairment expense includes a $166.6 million impairment on our exploration and evaluation assets in the Eagle Ford, $230.0 million impairment on our oil and gas assets in Peace River and $26.6 million of impairments on an asset located near Lloydminster, which was subsequently disposed of in Q3/2016.
In 2016, we derecognized $166.6 million of exploration and evaluation assets in the Eagle Ford due to changes to our development plan, which resulted in possible reserves being reclassified to contingent resources. The derecognition of exploration and evaluation assets was recorded as an impairment charge.
In our Peace River CGU, we recorded a $230.0 million impairment expense on our oil and gas properties. Due to the low oil price environment, we did not engage in any reserves generating activity on our heavy oil assets in Canada, deferring all operated drilling activity, including development wells and stratigraphic test wells. This reduced level of activity resulted in limited reserves additions, which, when combined with production, economic factors and technical revisions, resulted in a 21% reduction in proved plus probable reserve volumes associated with our Peace River CGU, which resulted in an impairment. The recoverable amount of the Peace River CGU was determined based on their fair value less costs of disposal at December 31, 2016 using the discounted cash flows for proved and probable reserves. In computing the future cash flows of the assets, we made certain assumptions, most significantly about future commodity prices and the discount rate. We assumed a WTI price of approximately US$55.00/bbl in 2017, US$65.00/bbl in 2018 and US$70.00/bbl in 2019. It is possible that commodity prices in those years may be lower than the current estimate which could result in further impairments. Discount rates ranging from 10% to 15% before tax were applied to the cash flows.
In Q3/2016, we recorded a $26.6 million impairment expense in our Lloydminster CGU on assets that were reclassified from oil and gas properties to assets held for sale. The carrying value of the assets that were transferred to assets held for sale, exceeded their fair value, being the sale price, resulting in the impairment.
For 2015, we recorded an impairment expense totaling $1,038.6 million, which was comprised of a $992.9 million impairment on our Eagle Ford assets and $45.7 million impairment related to assets in our Lloydminster CGU. The impairment charge on our Eagle Ford assets were directly attributable to lower commodity prices. The Eagle Ford assets were originally recorded at their fair value at the time of acquisition in June 2014 when the WTI oil price was above US$100/bbl. Commodity prices declined in 2015 along with the future market prices which reduced the estimated future cash flows for our Eagle Ford assets below the carrying amount of the assets. The total impairment for 2015 on our Eagle Ford assets included $282.9 million of remaining goodwill associated with this acquisition along with $710.0 million related to oil and gas properties. In our Lloydminster CGU, we identified certain lands that we no longer anticipated the ability to access, develop and explore, therefore, we recorded an impairment charge of $45.7 million on these assets. The lands were subsequently disposed of in November 2015.
General and Administrative Expense

| Years Ended December 31
($ thousands except for % and per boe) | 2016 |  | 2015 |  | Change |
General and administrative expense | $ | 50,866 |  | $ | 59,406 |  | (14 | )%
General and administrative expense per boe | $ | 2.00 |  | $ | 1.92 |  | 4 | %

Baytex Energy Corp.
2016 MD&A Page 11

General and administrative ("G&A") expense for 2016 of $50.9 million decreased $8.5 million or 14% from $59.4 million in 2015. The decrease is attributable to reductions in staffing levels commensurate with lower activity levels combined with cost saving efforts. On a per boe basis, G&A expense increased 4% to $2.00/boe from $1.92/boe as production decreased 18% over the period compared to the 14% reduction in G&A expense.
Share-Based Compensation Expense
Compensation expense associated with the Share Award Incentive Plan is recognized in net 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 was $13.9 million for 2016, compared to $24.6 million for 2015. For 2016, compensation expense decreased $10.7 million due to the lower fair value of share awards granted late in 2015 and early in 2016. This lower fair value is a result of a reduction in the Company's share price at grant date for the new grants compared to those issued prior to 2015.
During the year, the Company identified an immaterial error relating to share-based compensation expense in our previously issued financial statements. The estimated forfeiture rate was improperly applied to share awards that had previously vested and transferred to share capital, thereby understating share-based compensation expense. The Company concluded that the error is not material to the Company’s previously filed financial statements and the corrected adjustments have been applied to the comparative financial information in the consolidated financial statements.
For the year ended December 31, 2015 an adjustment of $9.2 million of share-based compensation has been recorded resulting in a revised expense of $24.6 million. Net loss per share (basic and diluted) increased by $0.05 to $5.77 per share from $5.72 per share for the year ended December 31, 2015. For the year ended December 31, 2014 an additional $4.2 million of share-based compensation has been recorded resulting in a revised expense of $31.7 million. Net loss per share (basic and diluted) increased by $0.03 to $0.92 from $0.89 per share for the year ended December 31, 2014. As at December 31, 2014, both deficit and contributed surplus were increased by $8.2 million. A summary of the adjustments are disclosed in note 13 to the consolidated financial statements.
Financing and Interest Expense
Financing and interest expense includes interest on our bank loan and long-term notes, non-cash financing costs and the accretion on our asset retirement obligations.
Financing and interest expense increased slightly to $114.2 million for 2016, compared to $111.7 million in 2015. This increase relates to the interest on our U.S. dollar denominated long-term notes. The Canadian dollar was weaker against the U.S. dollar during 2016 averaging 1.3256 CAD/USD, as compared to 2015 when the exchange rate averaged 1.2811 CAD/USD, which increased the expense during 2016.
Foreign Exchange
Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and bank loan denominated in U.S. dollars. The long-term notes and bank loan are translated to Canadian dollars on the balance sheet date. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in the Canadian operations.

| Years Ended December 31
($ thousands except for % and exchange rates) | 2016 |  | 2015 |  | Change |
Unrealized foreign exchange loss (gain) | $ | (41,436 | ) | $ | 213,999 |  | (119 | )%
Realized foreign exchange (gain) | (1,242 | ) | (3,286 | ) | (62 | )%
Foreign exchange loss (gain) | $ | (42,678 | ) | $ | 210,713 |  | (120 | )%
CAD/USD exchange rates: |  |  |
At beginning of period | 1.3840 |  | 1.1601 |  |
At end of period | 1.3427 |  | 1.3840 |  |

Baytex Energy Corp.
2016 MD&A Page 12

The Company recorded an unrealized foreign exchange gain of $41.4 million for 2016 as the Canadian dollar at December 31, 2016 strengthened against the U.S. dollar with a CAD/USD exchange rate of 1.3427 compared to the exchange rate of 1.3840 at December 31, 2015.
The Company realizes foreign exchange gains and losses from day-to-day U.S. dollar denominated transactions in its Canadian entities. For 2016, the Company recorded realized foreign exchange gains of $1.2 million, compared to gains of $3.3 million for 2015.
Other Income/Expense
For 2016, we have other expense of $8.2 million, compared to other income of $8.4 million for 2015. In 2016, we entered into agreements to sublease a portion of our firm transportation commitment and a portion of our office space at a loss. We recorded an expense of $6.7 million on the transportation agreement and $3.5 million on our office space. These expenses represent the difference between the minimum future payments that we are required to make and the estimated recoveries. This was offset by miscellaneous income of $2.0 million. In 2015, we subleased our firm transportation commitment at a higher rate than our contract rate and recognized other income of $8.4 million.
Income Taxes

| Years Ended December 31
($ thousands) | 2016 |  | 2015 |  | Change |
Current income tax (recovery) expense | $ | (8,042 | ) | $ | 8,907 |  | $ | (16,949 | )
Deferred income tax (recovery) | (264,561 | ) | (353,053 | ) | 88,492 |
Total income tax (recovery) | $ | (272,603 | ) | $ | (344,146 | ) | $ | 71,543 |

In 2016, available tax deductions exceeded taxable income which allowed the Company to recover a portion of the prior year current income tax expense. For 2016, this resulted in a current income tax recovery of $8.0 million, an increase of $16.9 million over the current income tax expense of $8.9 million for 2015.
The 2016 deferred income tax recovery of $264.6 million decreased $88.5 million from $353.1 million in 2015. The decrease during 2016 compared to 2015 is due to the higher impairment expense on oil and gas properties recorded in 2015, partially offset by an increase in unrealized loss on financial derivatives and a decrease in the amount of tax pool claims required to shelter the lower taxable income.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments follow the previously disclosed letter which we received in November 2014 from the CRA, proposing to issue such reassessments.
We remain confident that the tax filings of the affected entities are correct and are vigorously defending our tax filing positions. The reassessments do not require us to pay any amounts in order to participate in the appeals process.
In September 2016, we filed a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of the CRA; a process that we estimate could take up to two years. If the Appeals Division upholds the notices of reassessment, we have the right to appeal to the Tax Court of Canada; a process that we estimate could take a further two years. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (the “Losses”). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, we will owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years available for “carry back” to the years 2012 through 2015.
Tax Pools
The Company has Canadian and U.S. tax pools, which are available to reduce future taxable income. Our cash income tax liability is dependent upon many factors, including the prices at which we sell our production, available income tax deductions and the legislative environment in place during the taxation year. Based upon the current forward commodity price outlook, projected production and cost levels, and currently enacted tax laws in Canada and the United States, we do not expect to pay material amounts of cash income taxes prior to 2020.

Baytex Energy Corp.
2016 MD&A Page 13

The income tax pools detailed below are deductible at various rates as prescribed by law:

($ thousands) | December 31, 2016 |  | December 31, 2015 |
Canadian Tax Pools |  |
Canadian oil and natural gas property expenditures | $ | 198,525 |  | $ | 231,168 |
Canadian development expenditures | 250,239 |  | 347,014 |
Canadian exploration expenditures | 210 |  | 94 |
Undepreciated capital costs | 256,549 |  | 339,635 |
Non-capital losses | 151,959 |  | 63,064 |
Financing costs and other | 69,025 |  | 84,734 |
Total Canadian tax pools | $ | 926,507 |  | $ | 1,065,709 |
U.S. Tax Pools |  |
Depletion | $ | 297,252 |  | $ | 383,551 |
Intangible drilling costs | 388,727 |  | 439,380 |
Tangibles | 136,969 |  | 149,971 |
Non-capital losses | 1,039,782 |  | 1,046,951 |
Other | 201,896 |  | 65,669 |
Total U.S. tax pools | $ | 2,064,626 |  | $ | 2,085,522 |

Net Income (Loss) and Funds from Operations
Net loss for 2016 totaled $485.2 million ($2.29 per basic and diluted share) compared to a net loss of $1,142.9 million ($5.77 per basic and diluted share) for 2015. Funds from operations for 2016 totaled $276.3 million ($1.30 per basic and diluted share) as compared to $516.4 million ($2.61 per basic and diluted share) for 2015. The components of the change in net income (loss) and funds from operations from 2015 to 2016 are detailed in the following table:

| Years Ended December 31
($ thousands) | Net income (loss) |  | Funds from operations |
2015 | $ | (1,142,880 | ) | $ | 516,417 |
Increase (decrease) in revenues |  |
Revenue, net of royalties | (278,020 | ) | (278,020 | )
(Increase) decrease in expenses |  |
Operating | 79,482 |  | 79,482 |
Transportation | 24,870 |  | 24,870 |
Blending | 18,208 |  | 18,208 |
General and administrative | 8,540 |  | 8,540 |
Exploration and evaluation | 2,799 |  | — |
Depletion and depreciation | 153,549 |  | — |
Impairment | 615,378 |  | — |
Share-based compensation | 10,691 |  | — |
Financing and interest | (2,539 | ) | (281 | )
Financial derivatives | (185,936 | ) | (100,616 | )
Foreign exchange | 253,391 |  | (2,044 | )
Other(1)(2) | 28,826 |  | (7,254 | )
Current income tax | 16,949 |  | 16,949 |
Deferred income tax | (88,492 | ) | — |
2016 | $ | (485,184 | ) | $ | 276,251 |

(1) For net income (loss), "other" includes gain (loss) on disposition and other income/expense.
(2) For funds from operations, "other" includes the cash component of other income/expense and payments on onerous contracts.

Baytex Energy Corp.
2016 MD&A Page 14

Dividends
In response to the prolonged low price commodity environment and in an effort to preserve liquidity, we suspended our monthly dividend beginning in September of 2015. During 2015, we declared monthly dividends of $0.10 per common share from January to August totaling $0.80 per common share. In total, $96.6 million of the dividends were paid in cash and $57.3 million were settled by issuing 4,707,914 common shares under our dividend reinvestment plan during 2015. No dividends have been declared or paid subsequent to 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 $75.5 million foreign currency translation loss for 2016 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the strengthening of the Canadian dollar against the U.S. dollar at December 31, 2016 (1.3427 CAD/USD) as compared to December 31, 2015 (1.3840 CAD/USD).
Capital Expenditures
Capital expenditures for the years ended December 31, 2016 and 2015 are summarized as follows:

| Years Ended December 31
| 2016 | 2015
($ thousands except for # of wells drilled) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Land | $ | 4,053 |  | $ | 6,098 |  | $ | 10,151 |  | $ | 4,704 |  | $ | 276 |  | $ | 4,980 |
Seismic | 638 |  | — |  | 638 |  | 300 |  | — |  | 300 |
Drilling, completion and equipping | 13,618 |  | 178,412 |  | 192,030 |  | 45,937 |  | 420,559 |  | 466,496 |
Facilities | 7,564 |  | 14,400 |  | 21,964 |  | 20,309 |  | 28,954 |  | 49,263 |
Total exploration and development | $ | 25,873 |  | $ | 198,910 |  | $ | 224,783 |  | $ | 71,250 |  | $ | 449,789 |  | $ | 521,039 |
Total acquisitions, net of proceeds from divestitures | (8,883 | ) | (54,237 | ) | (63,120 | ) | 1,641 |  | 7 |  | 1,648 |
Total oil and natural gas expenditures | $ | 16,990 |  | $ | 144,673 |  | $ | 161,663 |  | $ | 72,891 |  | $ | 449,796 |  | $ | 522,687 |
Wells drilled (net) | 4.0 |  | 36.9 |  | 40.9 |  | 31.4 |  | 50.2 |  | 81.6 |

2016 capital expenditures totaled $224.8 million as compared to $521.0 million in 2015. Capital spending has been focused on our Eagle Ford assets which accounted for 88% of 2016 capital expenditures. In the U.S., capital spending decreased to $198.9 million in 2016 from $449.8 million in 2015 due to lower activity levels associated with lower commodity prices combined with significant cost savings achieved on our Eagle Ford capital program. We drilled 127 (36.9 net) wells in the Eagle Ford in 2016 compared to 188 (50.2 net) wells in 2015. Total costs in the Eagle Ford have continued to decrease with wells now being drilled, completed and equipped for approximately US$4.5 million per well as compared to US$6.2 million per well in 2015 representing a 28% decrease year over year. In Canada, all operated heavy oil drilling was deferred due to the low price environment. For 2016 we drilled 15 (4.0 net) wells and spent $25.9 million compared to 2015 when we drilled 40 (31.4 net) wells and spent $71.3 million.
On July 27, 2016, the Company disposed of its operated interest in certain Eagle Ford properties for proceeds of $54.2 million, which consisted of $11.8 million of oil and gas properties and $2.3 million of exploration and evaluation assets, resulting in a gain on disposition of $40.1 million.
During 2016, the Company disposed of certain non-core assets in Canada for total proceeds of $9.0 million. The divestitures consisted of $5.1 million of oil and gas properties and $0.1 million of exploration and evaluation assets, resulting in a gain on dispositions of $3.8 million.
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 and, in certain circumstances, we will seek enhanced credit protection from these counterparties.
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 40% from our initial plans and working with our lending syndicate to secure our bank credit facilities. We also shut-in low or negative margin production for part of 2016 and sold non-core assets during the year for proceeds of $63.6 million that were applied to our credit facilities. On December 12, 2016, we closed an equity financing and issued 21,907,500 common shares for aggregate gross proceeds of approximately $115 million. The net proceeds, after issuance costs, of approximately $109.9 million were applied to our credit facilities and subsequently used to fund the acquisition of assets in the Peace River area of Alberta for approximately $65 million on January 20, 2017.
If commodity prices decline from current levels, 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 December 31, 2016, net debt was $1,773.5 million, as compared to $2,049.9 million at December 31, 2015, representing a decrease of $276.4 million. Funds from operations for 2016 exceeded capital spending by $51.5 million which reduced net debt. We also applied the proceeds of $63.6 million from non-core asset sales along with the $109.9 million from the equity financing late in 2016 to reduce our debt levels. The strengthening Canadian dollar against the U.S. dollar at December 31, 2016 compared to December 31, 2015 reduced the carrying value of our U.S. dollar denominated long-term notes and bank loans further reducing our net debt.
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 and 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. We 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 2016 was 3.5%, as compared to 4.2% for 2015.
Covenants
On March 31, 2016, we amended our credit facilities and restructured 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 December 31, 2016.

|  | Ratio for the Quarter(s) ending:
Covenant Description | Position as at December 31, 2016 | December 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) | 0.6:1.00 | 5.00:1.00 | 4.50:1.00 | 4.00:1.00 | 3.50:1.00
Interest Coverage (3) (Minimum Ratio) | 3.6:1.00 | 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 the bank loan and other secured obligations identified in the credit agreement. As at December 31, 2016, our Senior Secured Debt totaled $204 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 expenses, income tax, 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. Bank EBITDA for the twelve months ended December 31, 2016 was $373 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 December 31, 2016 were $104 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 taking on further debt or paying dividends to our shareholders.
Long-Term Notes
We have five series of long-term notes outstanding that total $1.58 billion as at December 31, 2016. The long-term 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 existing credit facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA to financing and interest expenses on a trailing twelve month basis) of 2.5:1. As at December 31, 2016, the fixed charge coverage ratio was 3.6:1.00.
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. As of February 17, 2016, these notes are redeemable at our option, in whole or in part, 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 our 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. As of April 1, 2016, the remaining Aurora notes (US$6.4 million principal amount) are redeemable at our option, in whole or in part, 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 particularly reduce the volatility in our funds from operations.
A summary of the risk management contracts in place as at December 31, 2016 and the accounting treatment thereof is disclosed in note 18 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. In Q4/2016, we entered an agreement to acquire assets in the Peace River area of Alberta for approximately $65 million and completed an equity financing for approximately $115 million to fund the acquisition. The financing closed on December 12, 2016 and we issued 21,907,500 common shares for total proceeds of $109.9 million (net of issue costs). We also issued 958,516 common shares pursuant to our share-based compensation program during the year. As at March 1, 2017, we had 234,204,090 common shares and no preferred shares issued and outstanding.
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 our funds from operations in an ongoing manner. A significant portion of these obligations will be funded by funds from operations. These obligations as of December 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 | $ | 112,973 |  | $ | 112,973 |  | $ | — |  | $ | — |  | $ | — |
Bank loan(1) (2) | 191,286 |  | — |  | 191,286 |  | — |  | — |
Long-term notes(2) | 1,584,158 |  | — |  | — |  | 747,078 |  | 837,080 |
Interest on long-term notes(3) | 404,769 |  | 64,325 |  | 128,650 |  | 127,847 |  | 83,947 |
Operating leases | 38,982 |  | 8,164 |  | 15,511 |  | 12,679 |  | 2,628 |
Processing agreements | 48,833 |  | 9,631 |  | 11,130 |  | 9,043 |  | 19,029 |
Transportation agreements | 59,172 |  | 10,998 |  | 23,670 |  | 22,674 |  | 1,830 |
Total | $ | 2,440,173 |  | $ | 206,091 |  | $ | 370,247 |  | $ | 919,321 |  | $ | 944,514 |

(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.

(3) | Excludes interest on bank loan as interest payments on bank loans fluctuate based on interest rate and bank loan balance.

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

($ thousands, except per common share amounts) | 2016 |  | 2015 |  | 2014 |
Revenues, net of royalties | $ | 601,979 |  | $ | 879,999 |  | $ | 1,529,897 |
Net income (loss) | $ | (485,184 | ) | $ | (1,142,880 | ) | $ | (136,998 | )
Per common share - basic | $ | (2.29 | ) | $ | (5.77 | ) | $ | (0.92 | )
Per common share - diluted | $ | (2.29 | ) | $ | (5.77 | ) | $ | (0.92 | )
Total assets | $ | 4,594,085 |  | $ | 5,488,498 |  | $ | 6,230,596 |
Total bank loan and long-term notes | $ | 1,754,070 |  | $ | 1,854,929 |  | $ | 2,062,344 |
Cash dividends or distributions declared per common share | $ | — |  | $ | 0.80 |  | $ | 2.64 |
Average wellhead prices, net of blending costs ($/boe) | $ | 30.29 |  | $ | 35.40 |  | $ | 66.54 |
Total production (boe/d) | 69,509 |  | 84,648 |  | 78,395 |

Baytex Energy Corp.
2016 MD&A Page 15

QUARTERLY FINANCIAL INFORMATION

| 2016 | 2015
($ thousands, except per common share amounts) | Q4 |  | Q3 |  | Q2 |  | Q1 |  | Q4 |  | Q3 |  | Q2 |  | Q1 |
Petroleum and natural gas sales | 233,116 |  | 197,648 |  | 195,733 |  | 153,598 |  | 229,361 |  | 265,876 |  | 342,802 |  | 283,384 |
Net income (loss) | (359,424 | ) | (39,430 | ) | (86,937 | ) | 607 |  | (419,175 | ) | (519,247 | ) | (27,096 | ) | (177,362 | )
Per common share - basic | (1.66 | ) | (0.19 | ) | (0.41 | ) | — |  | (1.99 | ) | (2.50 | ) | (0.13 | ) | (1.05 | )
Per common share - diluted | (1.66 | ) | (0.19 | ) | (0.41 | ) | — |  | (1.99 | ) | (2.50 | ) | (0.13 | ) | (1.05 | )
Funds from operations | 77,239 |  | 72,106 |  | 81,261 |  | 45,645 |  | 93,095 |  | 105,052 |  | 158,049 |  | 160,221 |
Per common share - basic | 0.36 |  | 0.34 |  | 0.39 |  | 0.22 |  | 0.44 |  | 0.51 |  | 0.77 |  | 0.95 |
Per common share - diluted | 0.36 |  | 0.34 |  | 0.39 |  | 0.22 |  | 0.44 |  | 0.51 |  | 0.77 |  | 0.95 |
Exploration and development | 68,029 |  | 39,579 |  | 35,490 |  | 81,685 |  | 140,796 |  | 126,804 |  | 106,010 |  | 147,429 |
Canada | 12,151 |  | 6,120 |  | 2,747 |  | 4,855 |  | 8,804 |  | 33,484 |  | 7,690 |  | 21,272 |
U.S. | 55,878 |  | 33,459 |  | 32,743 |  | 76,830 |  | 131,992 |  | 93,320 |  | 98,320 |  | 126,157 |
Acquisitions, net of divestitures | (322 | ) | (62,752 | ) | (37 | ) | (9 | ) | (574 | ) | (498 | ) | 1,170 |  | 1,550 |
Net debt | 1,773,541 |  | 1,864,022 |  | 1,942,538 |  | 1,981,343 |  | 2,049,905 |  | 1,949,736 |  | 1,822,511 |  | 2,455,995 |
Total assets | 4,594,085 |  | 4,995,876 |  | 5,089,280 |  | 5,197,913 |  | 5,488,498 |  | 5,893,759 |  | 6,189,417 |  | 6,419,922 |
Common shares outstanding | 233,449 |  | 211,542 |  | 210,715 |  | 210,689 |  | 210,583 |  | 210,225 |  | 206,193 |  | 169,001 |
Daily production |  |  |  |  |  |  |  |
Total production (boe/d) | 65,136 |  | 67,167 |  | 70,031 |  | 75,776 |  | 81,110 |  | 82,170 |  | 84,812 |  | 90,710 |
Canada (boe/d) | 31,704 |  | 33,615 |  | 31,722 |  | 34,709 |  | 40,826 |  | 43,229 |  | 45,264 |  | 49,634 |
U.S. (boe/d) | 33,432 |  | 33,552 |  | 38,309 |  | 41,067 |  | 40,284 |  | 38,941 |  | 39,548 |  | 41,076 |
Benchmark prices |  |  |  |  |  |  |  |
WTI oil (US$/bbl) | 49.29 |  | 44.94 |  | 45.60 |  | 33.45 |  | 42.18 |  | 46.43 |  | 57.94 |  | 48.64 |
WCS heavy (US$/bbl) | 34.97 |  | 31.44 |  | 32.29 |  | 19.22 |  | 27.69 |  | 33.13 |  | 46.35 |  | 33.91 |
CAD/USD avg exchange rate | 1.3339 |  | 1.3051 |  | 1.2885 |  | 1.3748 |  | 1.3353 |  | 1.3094 |  | 1.2294 |  | 1.2308 |
AECO gas ($/mcf) | 2.81 |  | 2.20 |  | 1.25 |  | 2.11 |  | 2.65 |  | 2.70 |  | 2.67 |  | 2.95 |
NYMEX gas (US$/mmbtu) | 2.98 |  | 2.81 |  | 1.95 |  | 2.09 |  | 2.27 |  | 2.77 |  | 2.64 |  | 2.98 |
Sales price ($/boe) | 38.16 |  | 31.73 |  | 30.52 |  | 21.93 |  | 30.03 |  | 34.59 |  | 43.34 |  | 33.54 |
Royalties ($/boe) | 9.28 |  | 7.37 |  | 6.65 |  | 5.02 |  | 6.61 |  | 7.61 |  | 10.10 |  | 6.95 |
Operating expense ($/boe) | 9.96 |  | 9.07 |  | 8.67 |  | 10.11 |  | 9.76 |  | 10.25 |  | 10.64 |  | 10.75 |
Transportation expense ($/boe) | 1.30 |  | 1.38 |  | 0.81 |  | 0.98 |  | 1.45 |  | 1.52 |  | 1.94 |  | 1.95 |
Operating netback ($/boe) | 17.62 |  | 13.91 |  | 14.39 |  | 5.82 |  | 12.21 |  | 15.21 |  | 20.66 |  | 13.89 |
Financial derivatives gain ($/boe) | 1.62 |  | 3.04 |  | 3.74 |  | 6.47 |  | 4.09 |  | 3.33 |  | 5.19 |  | 12.48 |
Operating netback after financial derivatives ($/boe) | 19.24 |  | 16.95 |  | 18.13 |  | 12.29 |  | 16.30 |  | 18.54 |  | 25.85 |  | 26.37 |

Our operating results over the last eight quarters have been consistent with our expectations and have varied primarily in response to the changes in oil prices. Oil prices have been at multi-year lows in the last eight quarters as the WTI oil price averaged less than US$50/bbl for seven out of the last eight quarters with a low of US$33.45/bbl in Q1/2016. Production has declined since Q1/2015 with reduced capital spending over the last two years in response to the lower price environment. Production in Canada has declined more than our U.S. production as there have been no operated heavy oil wells drilled in Canada since Q3/2015. Capital expenditures have been directed primarily to our Eagle Ford assets over the last two years as these assets generate our highest netbacks and highest rates of return. FFO has decreased coinciding with the declining oil price and lower production. Despite the lower FFO, our net debt has decreased to $1.8 billion in Q4/2016 down from $2.5 billion in Q1/2015. Over the last two years we have completed two equity financings raising gross proceeds of $633 million in Q2/2015 and $115 million in Q4/2016. In addition, we disposed of our operated assets in the Eagle Ford for proceeds of $54 million in Q3/2016 and sold other non-core assets for proceeds of approximately $9 million. Total assets have decreased from $6.4 billion in Q1/2015 to $4.6 billion in Q4/2016. Over the last two years the Company has recorded total impairment losses of $1.5 billion primarily related to the reduction in oil prices. These impairments have reduced the carrying value of our assets.

Baytex Energy Corp.
2016 MD&A Page 16

FOURTH QUARTER OF 2016
Our operating results for the fourth quarter were consistent with our expectations. Production averaged 65,136 boe/d in Q4/2016, as compared to 67,167 boe/d in Q3/2016 which resulted in annual average production of 69,509 boe/d, in line with our production guidance range of 69,000 to 70,000 boe/d.
In the Eagle Ford, production was stable during the fourth quarter, averaging 33,432 boe/d as compared to 33,552 boe/d in Q3/2016. During the fourth quarter, drilling activity increased as we averaged 3-4 drilling rigs and 1-2 completion crew on our lands, with two additional rigs being added by the end of the quarter. In Canada, production averaged 31,704 boe/d as compared to 33,615 boe/d in Q3/2016. Canadian production has decreased as we continued to limit capital expenditures on our Canadian assets during the fourth quarter due to the low oil price.
Capital expenditures for exploration and development activities totaled $68.0 million in Q4/2016 and $224.8 million for full-year 2016, in line with our guidance range of $200-225 million. In the Eagle Ford, we participated in the drilling of 27 (7.4 net) wells and placed 39 (11.6 net) wells on stream during Q4/2016. We have continued to realize cost reduction with wells being drilled, completed and equipped for approximately US$4.5 million per well in Q4/2016, down 20% from approximately US$5.6 million per well in Q1/2016. In Canada, we participated in the drilling of 14 (2.98 net) non-operated vertical wells at Lindbergh during Q4/2016.
In Q4/2016, we entered an agreement to acquire assets in the Peace River area of Alberta for approximately $65 million and also completed a $115 million equity financing to fund the acquisition. The equity financing closed on December 12, 2016 with 21.9 million shares issued for proceeds of $109.9 million (net of issue costs). The Peace River acquisition closed subsequent to year end on January 20, 2017.
We generated FFO of $77.2 million ($0.36 per share) in Q4/2016, compared to $72.1 million ($0.34 per share) in Q3/2016. The increase in FFO was primarily driven by a higher oil price which averaged US$49.29/bbl in Q4/2016 compared to US$44.94/bbl in Q3/2016. The oil price increased to more than US$50/bbl in December of 2016 after OPEC and non-OPEC countries announced their intentions to cut production levels on November 30, 2016. The higher oil prices increased oil and natural gas revenue for Q4/2016 by $33 million to $229 million, up from $196 million in Q3/2016. This was offset by higher royalties, higher operating expense and lower financial derivative gains which reduced FFO, contributing to the $5 million overall increase in FFO from Q3/2016.
Operating netback per boe increased to $17.62/boe in Q4/2016 compared to $13.91/boe in Q3/2016. The increase in netback per boe is directly attributable to higher oil prices which resulted in higher oil and gas revenues per boe of $38.16/boe in Q4/2016 compared to $31.73/boe in Q3/2016. The increased revenue per boe was slightly offset by higher royalty rates and higher operating costs per boe in Q4/2016 compared to Q3/2016. Royalty rates increased to 24.3% of revenue in Q4/2016 from 23.2% of revenue in Q3/2016 due to higher pricing and minor prior period adjustments. Operating expense averaged $9.96/boe in Q4/2016 up from $9.07/boe in Q3/2016. In Canada, operating expense increased to $13.10/boe in Q4/2016 from $12.32/boe in Q3/2016 with increased maintenance and the effect of fixed costs on lower production volumes. In the U.S., operating expense increased to $6.98/boe in Q4/2016 from $5.82/boe in Q3/2016 due to minor prior period adjustments and foreign exchange as the CAD/USD exchange rate increased.
We recorded a net loss in Q4/2016 of $359.4 million ($1.66 per share) compared to a net loss of $39.4 million ($0.19 per share) in Q3/2015. The net loss in the quarter is largely attributable to impairment charges of $396.6 million. In Q4/2016, we recorded an impairment charge of $166.6 million on our exploration and evaluation assets in the Eagle Ford along with a $230.0 million impairment charge on our oil and gas properties in Peace River.
In Q4/2016, our FFO exceeded our capital expenditures by $9.2 million. This along with the proceeds from the equity financing contributed to our net debt decreasing by $90.5 million from Q3/2016. As at December 31, 2016 our net debt was $1.77 billion and we had approximately $580 million of undrawn credit capacity on our revolving credit facilities. We were also in compliance with all of our financial covenants as at December 31, 2016.

Baytex Energy Corp.
2016 MD&A Page 17

The following table provides select operating results for Q4/2016.

| Three Months Ended December 31
| 2016 | 2015
($ thousands, except as noted) | Canada |  | U.S. |  | Total |  | Canada |  | U.S. |  | Total |
Daily Production |  |  |  |  |  |
Heavy oil (bbl/d) | 22,982 |  | — |  | 22,982 |  | 31,733 |  | — |  | 31,733 |
Light oil and condensate (bbl/d) | 1,281 |  | 18,882 |  | 20,163 |  | 1,600 |  | 23,330 |  | 24,930 |
NGL (bbl/d) | 1,307 |  | 7,012 |  | 8,319 |  | 973 |  | 8,023 |  | 8,996 |
Natural gas (mcf/d) | 36,804 |  | 45,228 |  | 82,032 |  | 39,122 |  | 53,586 |  | 92,708 |
Total production (boe/d) | 31,704 |  | 33,432 |  | 65,136 |  | 40,826 |  | 40,284 |  | 81,110 |
Baytex Average Sales Prices |  |  |  |  |  |
Canadian heavy oil ($/bbl)(1) | $ | 34.33 |  | $ | — |  | $ | 34.33 |  | $ | 24.41 |  | $ | — |  | $ | 24.41 |
Light oil and condensate ($/bbl) | 55.16 |  | 60.45 |  | 60.12 |  | 47.84 |  | 50.33 |  | 50.17 |
NGL ($/bbl) | 18.50 |  | 23.41 |  | 22.64 |  | 19.93 |  | 16.90 |  | 17.23 |
Natural gas ($/mcf) | 2.78 |  | 4.28 |  | 3.61 |  | 2.36 |  | 3.05 |  | 2.76 |
Weighted average ($/boe)(2) | $ | 31.10 |  | $ | 44.84 |  | $ | 38.16 |  | $ | 23.59 |  | $ | 36.56 |  | $ | 30.03 |
Operating netback ($/boe) |  |  |  |  |  |
Oil and natural gas revenues | $ | 31.10 |  | $ | 44.84 |  | $ | 38.16 |  | $ | 23.59 |  | $ | 36.56 |  | $ | 30.03 |
Less: |  |  |  |  |  |
Royalties | 4.82 |  | 13.52 |  | 9.28 |  | 2.72 |  | 10.56 |  | 6.61 |
Operating expenses | 13.10 |  | 6.98 |  | 9.96 |  | 12.27 |  | 7.23 |  | 9.76 |
Transportation expenses | 2.67 |  | — |  | 1.30 |  | 2.87 |  | — |  | 1.45 |
Operating netback | $ | 10.51 |  | $ | 24.34 |  | $ | 17.62 |  | $ | 5.73 |  | $ | 18.77 |  | $ | 12.21 |
Financial derivatives gain | $ | — |  | $ | — |  | $ | 1.62 |  | $ | — |  | $ | — |  | $ | 4.09 |
Operating netback after financial derivatives | $ | 10.51 |  | $ | 24.34 |  | $ | 19.24 |  | $ | 5.73 |  | $ | 18.77 |  | $ | 16.30 |
Capital Expenditures |  |  |  |  |  |
Exploration and development | $ | 12,151 |  | $ | 55,878 |  | $ | 68,029 |  | $ | 8,804 |  | $ | 131,992 |  | $ | 140,796 |
Acquisitions, net of divestitures | $ | (218 | ) | $ | (104 | ) | $ | (322 | ) | $ | (593 | ) | $ | 19 |  | $ | (574 | )

(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.

2017 GUIDANCE
In Canada, we have initiated an active first quarter drilling program in 2017 after limited activity over the past two years. In the Eagle Ford, we expect to maintain a consistent pace of development on our lands throughout 2017. We have designed our 2017 budget to be flexible should we continue to experience a volatile commodity price environment.
Our 2017 capital budget currently reflects a range of $300 to $350 million, which is designed to generate average annual production of 66,000 to 70,000 boe/d. For the full-year, approximately 70% of our planned capital expenditures will be directed to our Eagle Ford operations. The balance of the spending will be in Canada, largely toward our heavy oil assets at Peace River and Lloydminster. Our 2017 capital budget will be heavily weighted to drilling and completion activities (approximately 89%) with the balance for facilities (approximately 10%) and land and seismic (approximately 1%).
In the Eagle Ford, we expect to have four to five drilling rigs and two completion crews working on our lands, up from two to three rigs in the fourth quarter of 2016. At this pace of development, we expect to bring approximately 34 net wells on production in 2017. Our costs in the Eagle Ford continue to decrease with wells now being drilled, completed and equipped for approximately US$4.5 million.

Baytex Energy Corp.
2016 MD&A Page 18

In Canada, after two years of reduced activity and declining production, we are planning an active drilling program designed to stabilize production and ultimately, to position for growth. At Peace River, our capital budget includes drilling 11 net multi-lateral horizontal wells and 8 net stratigraphic wells. At Lloydminster, we plan to drill 52 net wells, of which approximately 55% will be horizontal wells. At Pembina, we expect to drill 2 net natural gas wells. Based on the mid-point of our 2017 annual average production guidance range of 68,000 boe/d, our production is expected to be equally split between Canada and the Eagle Ford. Our 2017 guidance includes an annual contribution of approximately 3,000 boe/d from our recently completed heavy oil acquisition at Peace River. Our production mix is forecast to be approximately 78% liquids (35% heavy oil, 31% light oil and condensate and 12% natural gas liquids) and 22% natural gas, based on a 6:1 natural gas-to-oil equivalency. Similar to 2016, we are targeting our 2017 capital expenditures to approximate funds from operations in order to minimize additional bank borrowings and will remain flexible.

2017 Guidance |
Exploration and development capital | $300-$350 million
Production | 66,000 to 70,000 boe/d
Expenses: |
Royalty rate | approximately 23%
Operating | $11.00-$12.00/boe
Transportation | $1.10-$1.30/boe
General and administrative | approximately $50 million or $2.00/boe
Interest | approximately $100 million or $4.00/boe

OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at December 31, 2016, nor are any such arrangements outstanding as of the date of this MD&A.
CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS
The preparation of the consolidated financial statements requires management to make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenue and expenses during the reporting period. Accordingly, actual results can differ from those estimates. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, expenses, and disclosure of contingencies are discussed below.
Oil and Gas Activities
Reserves estimates can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion, asset retirement obligations, asset impairments and business combinations. The estimation of reserves is a complex process requiring significant judgment. The Company's reserves are estimated annually by independent reserves evaluators and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate a 50 percent or greater statistical probability of being recovered (total proved plus probable reserves) or a 10 percent or greater statistical probability of being recovered (total possible reserves). Changes to estimates such as forward price estimates, production costs, recovery rates and, accordingly, economic status of reserves may have a material impact on the consolidated financial statements.
The Company's capital assets are aggregated into cash-generating units based on management's judgment of their ability to generate largely independent cash flows. The cash-generating units are used to assess impairment and, accordingly, can directly impact the recoverability of the assets therein. Impairment of assets and groups of assets are calculated based on the higher of value-in-use calculations and fair value less cost to sell. These calculations require the use of estimates and assumptions on highly uncertain matters such as future commodity prices, royalty rates, effects of inflation and technology improvements on operating expenses, production profiles and the outlook of market supply-and-demand conditions for oil and natural gas products. Any changes to these estimates and assumptions could impact the carrying value of assets. Management applies judgment when it assesses internal and external factors to determine if indicators of impairment or indicators of impairment reversal exist.
The determination of technical feasibility and commercial viability of exploration and evaluation assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment.

Baytex Energy Corp.
2016 MD&A Page 19

Depletion and Depreciation
The amounts recorded for depletion of oil and gas properties are based on a unit-of-production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account the level of development required to produce the reserves. See "Oil and Gas Activities" above for discussion of estimates and judgments involved in reserve estimation.
Amounts recorded for depreciation are based on the estimated useful lives of depreciable assets which are reviewed by management at each reporting date.
Business Combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value of assets and liabilities acquired often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of oil and gas properties and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net income (loss) can be affected as a result of changes in future depletion, depreciation, asset impairment or goodwill impairment.
Joint Control
Judgment is required to determine when the Company has joint control over a joint operation, which requires an assessment of the capital and operating activities of the projects undertaken with partners and when decisions in relation to those activities require unanimous consent.
Fair Value of Financial Instruments
Fair values of financial instruments, where active market quotes are not available, are estimated using the Company's assessment of available market inputs. These estimates may vary from the actual prices achieved upon settlement of the financial instruments.
Share-based Compensation
Compensation expense related to awards granted under the Company's Share Award Incentive Plan is dependent on estimated fair values, forfeiture rates and, for performance awards, a payout multiplier based on past performance. Compensation expense may fluctuate due to changes in management's estimates.
Asset Retirement Obligations
The amounts recorded for asset retirement obligations are based on the Company's net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and the facilities, the estimated time period during which these costs will be incurred in the future and the discount and inflation rates. Any changes to these estimates could change the amount recorded for asset retirement obligations and may materially impact the consolidated financial statements of future periods.
Legal
The Company is engaged in litigation and claims arising in the normal course of operations where the actual outcome may vary from the amount recognized in the consolidated financial statements. None of these claims are expected to materially affect the Company's financial position or reported results of operations.
Income Taxes
Regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and differing interpretations require management judgment. Income tax filings are subject to audits and re-assessments and changes in facts, circumstances and interpretations of the standards may result in a material change in the Company's provision for income taxes. As such, income taxes are subject to measurement uncertainty.
We employ individuals skilled in making such estimates and ensure those responsible have the most accurate information available. Further, approved budgets and prior period estimates are also reviewed and analyzed against actual results to ensure appropriate decisions are made for future estimates and outlooks. Actual results could differ materially if various assumptions or estimates do not turn out as expected.
CURRENT AND FUTURE CHANGES IN ACCOUNTING POLICIES
Revenue from Contracts with Customers
In April 2016, the International Accounting Standards Board (the "IASB") issued its final amendments to IFRS 15 Revenue from Contracts with Customers, which will replace IAS 11 Construction Contracts and IAS 18 Revenue and the related interpretations on revenue recognition. The new standard moves away from a revenue recognition model based on an earnings process to an approach that is based on transfer of control of a good or service to a customer. The standard also requires extensive new disclosures, as to the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. IFRS 15 shall be applied retrospectively to each period presented or retrospectively as a cumulative-effect adjustment as of the date of adoption. The new standard is effective for annual periods beginning on or after January 1, 2018 with early adoption permitted. We will adopt IFRS 15

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on January 1, 2018 and are currently in the process of creating a plan to identify and review our various revenue streams and underlying contracts and assessing the impact on our consolidated financial statements.
Financial Instruments
In July 2014, the IASB issued IFRS 9 Financial Instruments which is intended to replace IAS 39 Financial Instruments: Recognition and Measurement. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classifications: amortized cost and fair value. Under IFRS 9, where the fair value option is applied to financial liabilities, any change in fair value resulting from an entity’s own credit risk is recorded through other comprehensive income (loss) rather than net income (loss). The new standard also introduces a credit loss model for evaluating impairment of financial assets. In addition, IFRS 9 provides a hedge accounting model that is more in line with risk management activities. We currently do not apply hedge accounting to our derivative contracts nor do we intend to apply hedge accounting upon adoption of IFRS 9. The standard is effective for annual periods beginning on or after January 1, 2018 with early adoption permitted. We will adopt IFRS 9 on January 1, 2018 and are currently evaluating its impact on our consolidated financial statements.
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 (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. We will adopt IFRS 16 on January 1, 2019 and are currently evaluating the impact of the standard on the consolidated financial statements.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of December 31, 2016, an evaluation was conducted of the effectiveness of our “disclosure controls and procedures” (as defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) and in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109")) under the supervision of and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of Baytex (collectively the "certifying officers"). Based on that evaluation, the certifying officers concluded that our disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that we file or submit under the Exchange Act or under Canadian securities legislation is (i) recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and communicated to our management, including the certifying officers, to allow timely decisions regarding the required disclosure.
It should be noted that while the certifying officers believe that our disclosure control and procedures provide a reasonable level of assurance that they are effective, they do not expect that our disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met.
Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting. Internal control over our financial reporting is a process designed under the supervision of and with the participation of management, including the certifying officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.
Management has assessed the effectiveness of our "internal control over financial reporting" as defined in the Exchange Act and as defined by NI 52-109. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that our internal control over financial reporting was effective as of December 31, 2016. The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by KPMG LLP, as reflected in their report for 2016. No changes were made to our internal control over financial reporting during the year ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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RISK FACTORS
We are focused on long-term strategic planning and have identified key risks, uncertainties and opportunities associated with our business that can impact the financial results. Listed below is a description of these risk and uncertainties. Further information regarding risks and uncertainties affecting our business is contained in our Annual Information Form for the year ended December 31, 2016 under the "Risk Factors" section.
Volatility of Oil and Natural Gas Prices
Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. If crude oil and natural gas prices decline or fail to increase from their current levels it could have a material adverse effect on our operations, financial condition and the value and amount of our reserves.
Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, the condition of the Canadian, United States, European and Asian economies, government regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil, the price of foreign imports, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Natural gas prices realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.
Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium oil and heavy oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions, refining demand, the availability and cost of diluents used to blend and transport product and the quality of the oil produced, all of which are beyond our control. The supply of Canadian crude oil with demand from the refinery complex and access to those markets through various transportation outlets is currently finely balanced and, therefore, very sensitive to pipeline and refinery outages, which contributes to this volatility.
Decreases to or a prolonged period of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of currently producing wells, a delay or cancellation of existing or future drilling, development or construction programs, unutilized long-term transportation commitments and a reduction in the value and amount of our reserves.
Our reserves as at December 31, 2016 are estimated using forecast prices and costs. These prices are above current market prices for crude oil and natural gas. If crude oil and natural gas prices stay at current levels, our reserves may be substantially reduced as economic limits of developed reserves are reached earlier and undeveloped reserves become uneconomic at such prices. Even if some reserves remain economic at lower price levels, sustained low prices may compel us to re-evaluate our development plans and reduce or eliminate various projects with marginal economics.
We conduct assessments of the carrying value of our assets in accordance with Canadian GAAP. If crude oil and natural gas forecast prices decline further, it could result in downward revisions to the carrying value of our assets and our net earnings could be adversely affected.
Debt Service and Refinancing
We are required to comply with covenants under the Revolving Facilities and our long-term notes. In the event that we do not comply with these covenants, our access to capital (including our ability to make borrowings under our Revolving Facilities) could be restricted or repayment could be required on an accelerated basis by our lenders.
Our existing Revolving Facilities and any replacement facilities may not provide sufficient liquidity. We currently have Revolving Facilities in the amount of US$575 million. The amounts available under our existing Revolving Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. There can be no assurance that the amount of our Revolving Facilities will be adequate for our future financial obligations, including our future capital expenditure program, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund our ongoing operations. In the event that the Revolving Facilities are not extended before June 2019, indebtedness under the Revolving Facilities will be repayable at that time. In addition, we are required to repay the long-term notes on maturity. There is a risk that the Revolving Facilities will not be renewed for the same amount or on the same terms.

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Access to Capital Markets
The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital markets on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired. Should the lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be issued resulting in a dilutive effect on current and future shareholders.
Our ability to obtain additional capital is dependent on, among other things, investor interest in the energy industry in general, interest in our securities in particular and our ability to maintain our credit ratings. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate, our credit ratings could be downgraded, which would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing and may increase our borrowing costs.
Non-operating Agreements in the U.S.
Marathon Oil EF LLC ("Marathon Oil"), a wholly-owned subsidiary of Marathon Oil Corporation, is the operator of our Eagle Ford acreage and we will be reliant upon Marathon Oil to operate successfully. Marathon Oil will make decisions based on its own best interests and the collective best interests of all of the working interest owners of this acreage, which may not be in our best interests. We have a limited ability to exercise influence over the operational decisions of Marathon Oil, including the setting of capital expenditure budgets and determination of drilling locations and schedules. The success and timing of development activities operated by Marathon Oil will depend on a number of factors that will largely be outside of our control, including:

• | the timing and amount of capital expenditures;

• | Marathon Oil's expertise and financial resources;

• | approval of other participants in drilling wells;

• | selection of technology; and

• | the rate of production and development of reserves, if any.

To the extent that the capital expenditure requirements related to our Eagle Ford acreage exceeds our budgeted amounts, it may reduce the amount of capital we have available to invest in our other assets. We have the ability to elect whether or not to participate in well locations proposed by Marathon Oil on an individual basis. If we elect to not participate in a well location, we forgo any revenue from such well until Marathon Oil has recouped, from our working interest share of production from such well, 300% to 500% of our working interest share of the cost of such operation.
Variations in Interest Rates
There is a risk that the interest rates will increase given the current historical low level of interest rates. An increase in interest rates could result in a significant increase in the amount we pay to service debt and could have an adverse effect on our financial condition, results of operations and future growth, potentially resulting in a decrease to the market price of our common shares.
Variations in Foreign Exchange Rates
World oil prices are quoted in U.S. dollars and the price received by Canadian producers is therefore affected by the Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our revenues. A substantial portion of our operations and production are in the United States and, as such, we are exposed to foreign currency risk on both revenues and costs to the extent the value of the Canadian dollar decreases relative to the U.S. dollar. In addition, we are exposed to foreign currency risk as our Revolving Facilities and a large portion of our long-term notes are denominated in U.S. dollars and the interest and principal payable thereon is payable in U.S. dollars. Future Canada/U.S. foreign exchange rates could also impact the future value of our reserves as determined by our independent evaluator.
Credit Risk
We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to us may adversely affect our results of operations, cash flows and financial position.

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Risk Management
In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial instruments and physical sales contracts to manage our exposure under a risk management program. We also use derivative instruments in various operational markets to optimize our supply or production chain. The terms of these arrangements may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production, and may also result in royalties being paid on a reference price which is higher than the hedged price. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also increased exposure to counterparty credit risk due to the volatile commodity environment.
Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies, historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of which may vary considerably from actual results.
All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material.
Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves.
Additional Business Risks
Our business involves many operating risks related to acquiring, developing and exploring for oil and natural gas which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our operational risks include, but are not limited to: operational and safety considerations; pipeline transportation and interruptions; reservoir performance and technical challenges; partner risks; competition; technology; land claims; our ability to hire and retain necessary skilled personnel; the availability of drilling and related equipment; information systems; seasonality and access restrictions; timing and success of integrating the business and operations of acquired assets and companies; phased growth execution; risk of litigation, regulatory issues, increases in government taxes and changes to royalty or mineral/severance tax regimes; and risk to our reputation resulting from operational activities that may cause personal injury, property damage or environmental damage.
Environmental Regulation and Risk
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of federal, provincial and state legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties. Further, environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Although we believe that we will be in material compliance with current applicable environmental legislation, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.

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Climate Change Regulation
Both Canada and the United States are signatories to the United Nations Framework Convention on Climate Change (the "UNFCCC") and are participants in the Copenhagen Accord (a non-binding agreement created by the UNFCCC which represents a broad political consensus and reinforces commitments to reducing greenhouse gas ("GHG") emissions). Both governments agreed to an economy-wide target to reduce GHG emissions by 17% from 2005 levels. Both governments also signed the Paris Agreement in December of 2015, which included a commitment to keep any increase in global temperatures below two degrees Celsius. Additionally, Canada pledged to reduce GHG emissions by 30% by 2030 from 2005 levels and the United States pledged to reduce GHG emissions by 26% to 28% by 2025 from 2005 levels.
The United States has not yet announced or enacted any mechanisms or legislation to implement the Paris Agreement. The Government of Canada has announced that it intends to implement a carbon tax in 2018 starting at $10/tonne rising by $10/tonne a year to $50/tonne by 2022. This federal carbon tax is intended to be implemented in concert with the Provinces and territories and would only be implemented in those Provinces and territories that do not have their own carbon tax.
The Province of Alberta announced and implemented a broad range of plans targeting GHG emissions, that include: a carbon levy of $20/tonne that became effective January 1, 2017 that will increase to $30/tonne in 2018; a cap on GHG emissions from the oil sands of 100 mega tonnes per year; and a plan to introduce regulations that will reduce methane emissions from oil and gas operations by 45% by 2025. The Province of Saskatchewan has set forth similar legislation that is not yet in force for facilities that emit more than 50,000 tonnes of GHGs. At present, we do not operate any facilities in Alberta or Saskatchewan that exceed these thresholds. We expect a minimal increase in operating costs through internal trucking and supplier rate increases as a result of the implementation of the carbon levy for our Alberta properties.
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", "plan", "project", "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; crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our ability to reduce the volatility in our funds from operations by utilizing financial derivative contracts; the percentage of our net exposure to WTI, the WCS differential and natural gas that is hedged for 2017; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; the length of time it would take to resolve the reassessments; that we would owe cash taxes and late payment interest if the reassessment is successful; our expectation regarding the payment of cash income taxes prior to 2020; 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; our belief that the amended credit facilities provide increased financial flexibility; the existence, operation and strategy of our risk management program; our capital budget for 2017; our annual average production rate for 2017; the breakdown of our 2017 capital budget by geographic area and expenditure type; our plan for developing our properties in 2017, including the number of rigs and completion crews in the Eagle Ford, the number of wells to be brought on production in the Eagle Ford, the cost to drill, complete and equip a well in the Eagle Ford, the number and type of wells to be drilled at Peace River, Lloydminster and Pembina; the geographic breakdown of our 2017 annual production and the production expected from our recently completed heavy oil acquisition at Peace River; our production mix for 2017; our target of funding our capital expenditures with funds from operations to minimize additional bank borrowings; our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2017; and the effect that Alberta’s carbon tax will have on our operating costs. 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.

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Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices; a decline or an extended period of the currently low oil and natural gas prices; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; availability and cost of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; we may lose access to our information technology systems; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2016, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.