2013 Annual MD&A

EX-99.2 3 a2013annualmda.htm ANNUAL MD&A 2013 Annual MD&A

Baytex Energy Corp.

2013 MD&A Page 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the year ended December 31, 2013 and 2012

Dated March 12, 2014

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the year ended December 31, 2013.This information is provided as of March 12, 2014. 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 year to date results have been compared with the corresponding period in 2012. 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, 2013 and 2012, together with accompanying notes, and its Annual Information Form for the year ended December 31, 2013. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

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

NON-GAAP FINANCIAL MEASURES

In this MD&A, we refer to certain financial measures (such as funds from operations, payout ratio, total monetary debt, operating netback and earnings before interest, taxes, depreciation and amortization ("EBITDA")) which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). While funds from operations, payout ratio, 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.

Funds from Operations

We define funds from operations as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income. For a reconciliation of funds from operations to cash flow from operating activities, see "Funds from Operations, Payout Ratio, Dividends and EBITDA".

Payout Ratio

We define payout ratio as cash dividends (net of participation in our dividend reinvestment plan) divided by funds from operations. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments.

Total Monetary Debt

We define total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives, assets held for sale and liabilities related to assets held for sale)), the principal amount of long-term debt and long-term bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Operating Netback

We define operating netback as product revenue less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. As sales volumes are not materially different than production volumes, we believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

Baytex Energy Corp.

2013 MD&A Page 2

EBITDA

We define EBITDA as our consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items. This measure is used to measure compliance with certain contractual debt covenants.

RESULTS OF OPERATIONS

Production



	Years Ended December 31
Daily Production	2013		2012		Change
Light oil and NGL (bbl/d)	8,134		7,360		11	%
Heavy oil (bbl/d)⁽¹⁾	42,064		39,447		7	%
Natural gas (mcf/d)	41,989		43,076		(3	)%
Total production (boe/d)	57,196		53,986		6	%

Production Mix
Light oil and NGL	14	%	14	%	—
Heavy oil	74	%	73	%	—
Natural gas	12	%	13	%	—


(1)	Heavy oil sales volumes may differ from reported production volumes due to changes to Baytex's heavy oil inventory. For the year ended December 31, 2013, heavy oil sales volumes were the same as production volumes (year ended December 31, 2012 – 38 bbl/d lower).

Production for the year ended December 31, 2013 averaged 57,196 boe/d, an increase of 6% as compared to 53,986 boe/d for the same period in 2012. Light oil and NGL production for the year ended December 31, 2013 increased by 11% to 8,134 bbl/d, as compared to 7,360 bbl/d in same period in 2012, primarily due to successful development activities in the U.S., partially offset by the sale of 950 bbl/d associated with our non-operated position in North Dakota in the second quarter of 2012. Heavy oil production for the year ended December 31, 2013 increased by 7% to 42,064 bbl/d from 39,447 bbl/d for the same period in 2012, primarily due to successful development activities in the Peace River area. Natural gas production decreased by 3% to 42.0 mmcf/d for the year ended 2013, as compared to 43.1 mmcf/d for the same period in 2012, primarily due to natural declines as we focused our capital spending on oil projects.

Commodity Prices

Crude Oil

For the year ended December 31, 2013, the WTI oil prompt price averaged US$97.97/bbl, a 4% increase from the average WTI price of US$94.19/bbl for the same period in 2012, remaining relatively stable on the back of consistent supply and demand fundamentals. For the year ended December 31, 2012, WTI oil prompt price fluctuated between a low of US$77.69/bbl and a high of US$109.77/bbl, due to uneven global economic conditions and several periods of geopolitical tensions.

The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 26% for the year ended December 31, 2013 as compared to 22% for the same period in 2012. WCS differentials widened in the year ended December 31, 2013 due to capacity restrictions on Canadian crude export pipelines in much of the first and fourth quarters of 2013, which forced Western Canada crude into storage. This effect was partially offset by steady demand for heavy oil throughout the second and third quarters of 2013, as well as the increase in volumes transported by rail, which pulled heavy oil supply away from traditional heavy oil markets. For the year ended December 31, 2012, the WCS differential was volatile due to constrained access to U.S refineries, Canadian heavy oil production growth and maintenance at refineries; however, the capacity restrictions in 2013 far outweighed those experienced in 2012.

Baytex Energy Corp.

2013 MD&A Page 3

Natural Gas

For the year ended December 31, 2013, the AECO natural gas price averaged $3.13/mcf, a 30% increase, as compared to $2.40/mcf in the same period of 2012. In 2012, the natural gas price was driven down by high U.S. natural gas production and a relatively mild winter in major consuming areas, which set new records in both the U.S. and western Canada for natural gas storage levels. The recovery in the later half of 2012 from historic lows earlier in 2012 was driven, in part, by expectations of the 2012-2013 heating season and declining natural gas production, as natural gas drilling activity significantly declined in 2012.



	Years Ended December 31
	2013			2012			Change
Benchmark Averages
WTI oil (US$/bbl)⁽¹⁾	$	97.97		$	94.19		4	%
WCS heavy oil (US$/bbl)⁽²⁾	$	72.78		$	73.16		(1	)%
Heavy oil differential⁽³⁾	26		%	22		%
CAD/USD average exchange rate	1.0299			0.9991			3	%
Edmonton par oil ($/bbl)	$	93.24		$	86.53		8	%
AECO natural gas price ($/mcf)⁽⁴⁾	$	3.13		$	2.40		30	%

Baytex Average Sales Prices
Heavy oil ($/bbl)⁽⁵⁾	$	64.17		$	58.60		10	%
Physical forward sales contracts gain ($/bbl)	$	1.07		$	0.84
Heavy oil, net ($/bbl)	$	65.24		$	59.44		10	%
Light oil and NGL ($/bbl)⁽⁶⁾	$	79.61		$	74.07		7	%
Total oil and NGL, net ($/bbl)	$	67.57		$	61.74		9	%
Natural gas ($/mcf)⁽⁶⁾	$	3.32		$	2.45		36	%

Summary
Weighted average ($/boe)⁽⁶⁾	$	60.95		$	54.86		11	%
Physical forward sales contracts gain ($/boe)	0.79			0.62			27	%
Weighted average, net ($/boe)	$	61.74		$	55.48		11	%


(1)	WTI refers to the arithmetic average based on NYMEX prompt month WTI.


(2)	WCS refers to the average posting price for the benchmark WCS heavy oil.


(3)	Heavy oil differential refers to the WCS discount to WTI.


(4)	AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter.


(5)	Baytex’s realized heavy oil prices are calculated based on sales volumes, net of blending costs.


(6)	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.

Baytex Average Sales Prices

Baytex’s realized heavy oil price during the year ended December 31, 2013, was $65.24/bbl, or 87% of WCS. This compares to a realized heavy oil price in the year ended December 31, 2013 of $59.44/bbl, or 81% of WCS. The improvement in Baytex's discount to WCS over this period was mainly driven by higher volumes being transported by rail, which allows access to new markets and a stronger U.S. dollar. For the year ended December 31, 2013, Baytex’s average sales price for light oil and NGL was $79.61/bbl, up 7% from $74.07/bbl in the same period as 2012, in line with the increase in Edmonton par oil benchmark price. Baytex’s realized natural gas price for the year ended December 31, 2013 was $3.32/mcf, up from $2.45/mcf in the same period in 2012.

Baytex Energy Corp.

2013 MD&A Page 4

Gross Revenues



	Years Ended December 31
($ thousands except for %)	2013		2012		Change
Oil revenue
Light oil and NGL	$	236,328	$	199,518	18	%
Heavy oil	1,001,707		857,320		17	%
Total oil revenue	1,238,035		1,056,838		17	%
Natural gas revenue	50,954		38,667		32	%
Total oil and natural gas revenue	1,288,989		1,095,505		18	%
Heavy oil blending revenue	78,470		123,979		(37	)%
Total petroleum and natural gas revenues	$	1,367,459	$	1,219,484	12	%

Petroleum and natural gas revenues increased 12% to $1,367.5 million for the year ended December 31, 2013 from $1,219.5 million for the same period in 2012. The increase in revenues was driven by a 17% increase in heavy oil revenues due to higher heavy oil volumes in the Peace River area, higher realized heavy oil pricing, an 18% increase in light oil and NGL revenues due to higher production in the U.S. and higher realized light oil and NGL pricing and a 32% increase in natural gas revenues due to significant increases in realized natural gas pricing, partially offset by the decrease in heavy oil blending revenue, which was down 37% from the same period last year due to an increase in contracted volumes of heavy oil being transported by rail. Unlike transportation through oil pipelines, transportation of heavy oil by rail does not require condensate blending. The decrease in heavy oil blending revenue is offset by a corresponding decrease in heavy oil blending costs.

Royalties



	Years Ended December 31
($ thousands except for % and per boe)	2013			2012			Change
Royalties	$	252,049		$	194,535		30	%
Royalty rates:
Light oil, NGL and natural gas	20.7		%	19.0		%
Heavy oil	19.2		%	17.4		%
Average royalty rates⁽¹⁾	19.6		%	17.8		%
Royalty expenses per boe	$	12.07		$	9.85		23	%


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

Total royalties for the year ended December 31, 2013 increased to $252.0 million from $194.5 million in the year ended December 31, 2012. Total royalties for the year ended December 31, 2013 were 19.6% of oil and natural gas revenue, as compared to 17.8% for the same period in 2012.

Royalty rates for light oil, NGL and natural gas increased from 19.0% in the year ended December 31, 2012 to 20.7% in the year ended December 31, 2013 primarily due to higher royalties on U.S. properties resulting from a carry obligation and higher realized pricing in the year ended December 31, 2013, partially offset by a higher number of wells qualifying under lower royalty rates and a gas cost allowance credit related to prior years. Royalty rates for heavy oil increased from 17.4% in the year ended December 31, 2012, to 19.2% in the year ended December 31, 2013 due to certain farm-in agreements and higher commodity prices which impact sliding scale royalty rates.

Baytex Energy Corp.

2013 MD&A Page 5

Financial Derivatives



	Years Ended December 31
($ thousands)	2013			2012			Change
Realized gain (loss) on financial derivatives⁽¹⁾
Crude oil	$	4,877		$	21,080		$	(16,203	)
Natural gas	1,646			5,223			(3,577		)
Foreign currency	(491		)	5,545			(6,036		)
Interest rate	(7,259		)	(3,102		)	(4,157		)
Total	$	(1,227	)	$	28,746		$	(29,973	)

Unrealized gain (loss) on financial derivatives⁽²⁾
Crude oil	$	(7,671	)	$	31,171		$	(38,842	)
Natural gas	(1,658		)	(2,920		)	1,262
Foreign currency	(9,518		)	1,084			(10,602		)
Interest rate	6,942			3,473			3,469
Total	$	(11,905	)	$	32,808		$	(44,713	)

Total gain (loss) on financial derivatives
Crude oil	$	(2,794	)	$	52,251		$	(55,045	)
Natural gas	(12		)	2,303			(2,315		)
Foreign currency	(10,009		)	6,629			(16,638		)
Interest rate	(317		)	371			(688		)
Total	$	(13,132	)	$	61,554		$	(74,686	)


(1)	Realized gain (loss) on financial derivatives represents actual cash settlement or receipts for the financial derivatives.


(2)	Unrealized gain (loss) on financial derivatives represents the change in fair value of the financial derivatives during the period.

The realized loss of $1.2 million for the year ended December 31, 2013 on derivative contracts relates to losses on interest rate swaps as LIBOR remained low, offset by gains on commodity contracts due to low WTI prices in the first half of the year and the addition of new contracts during the year when WTI prices were favourable. The unrealized mark-to-market loss of $11.9 million for the year ended December 31, 2013 relates to a weakening Canadian dollar against the U.S. dollar at December 31, 2013, as compared to December 31, 2012, and settlement of previously recorded unrealized gains on crude oil and natural gas contracts. This was partially offset by settlement of previously recorded unrealized losses on interest rate contracts.

A summary of the risk management contracts in place as at December 31, 2013 and the accounting treatment of the Company’s financial instruments are disclosed in note 16 to the consolidated financial statements.

Production and Operating Expenses



	Years Ended December 31
($ thousands except for % and per boe)	2013		2012		Change
Production and operating expenses	$	275,519	$	232,375	19	%
Production and operating expenses per boe:
Heavy oil	$	12.72	$	11.02	15	%
Light oil, NGL and natural gas	$	14.53	$	13.81	5	%
Total	$	13.20	$	11.77	12	%

Production and operating expenses for the year ended December 31, 2013 increased to $275.5 million from $232.4 million for the same period in 2012. This increase is due to higher production volumes and higher costs per unit of production. Production and operating expenses increased to $13.20/boe for the year ended December 31, 2013, as compared to $11.77/boe for the same period in 2012 due to increased labour costs, higher repairs and maintenance, in large part due to the harsh weather conditions in the first half of 2013 and increased energy and chemical costs, resulting from higher costs for natural gas, diesel and other hydrocarbons which are used as inputs.

Baytex Energy Corp.

2013 MD&A Page 6

Transportation and Blending Expenses



	Years Ended December 31
($ thousands except for % and per boe)	2013		2012		Change
Blending expenses	$	78,470	$	123,979	(37	)%
Transportation expenses	80,371		83,261		(3	)%
Total transportation and blending expenses	$	158,841	$	207,240	(23	)%
Transportation expenses per boe⁽¹⁾:
Heavy oil	$	4.98	$	5.54	(10	)%
Light oil, NGL and natural gas	$	0.71	$	0.63	13	%
Total	$	3.85	$	4.22	(9	)%


(1)	Transportation expenses per boe exclude the purchase of blending diluent.

Transportation and blending expenses for the year ended December 31, 2013 were $158.8 million, as compared to $207.2 million for the same period in 2012.

The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications and to facilitate its marketing. The cost of blending diluent is recovered in the sale price of the blended product. For the year ended December 31, 2013, blending expenses were $78.5 million for the purchase of 2,056 bbl/d of condensate at $104.54/bbl, as compared to $124.0 million for the purchase of 3,316 bbl/d at $102.17/bbl for the same period last year. This decrease in blending for the year ended December 31, 2013, as compared to the respective periods in 2012, is due to higher volumes of heavy oil being transported by rail which does not require blending diluent.

Transportation expenses decreased 9% to $3.85/boe for the year ended December 31, 2013, as compared to $4.22/boe for the same period of 2012. The decrease is primarily driven by shorter trucking distances to rail terminals, as compared to pipeline delivery distances in the previous period, and lower wait times at rail terminals, partially offset by harsh winter conditions which caused delays and re-routings in the early part of 2013.

Operating Netback



	Years Ended December 31
($ per boe except for % and volume)	2013		2012		Change
Sales volume (boe/d)	57,196		53,948		6	%
Operating netback⁽¹⁾:
Sales price⁽²⁾	$	61.74	$	55.48	11	%
Less:
Royalties	12.07		9.85		23	%
Production and operating expenses	13.20		11.77		12	%
Transportation expenses	3.85		4.22		(9	)%
Operating netback before financial derivatives	$	32.62	$	29.64	10	%
Financial derivatives gain⁽³⁾	0.29		1.61
Operating netback after financial derivatives gain	$	32.91	$	31.25	5	%


(1)	Operating netback table includes revenues and costs associated with sulphur production.


(2)	Sales price is shown net of blending costs and gains on physical delivery contracts.


(3)	Financial derivatives reflect realized gains on commodity related contracts only and exclude the impact of interest rate swaps.

Evaluation and Exploration Expense

Evaluation and exploration expense for the year ended December 31, 2013 decreased to $10.3 million from $12.2 million for the same period in 2012 due to a decrease in the expiration of undeveloped land leases, partially offset by an increase in the impairment of evaluation and exploration assets that will not be developed.

Baytex Energy Corp.

2013 MD&A Page 7

Depletion and Depreciation

Depletion and depreciation for the year ended December 31, 2013 increased to $329.0 million from $297.8 million for the same period in 2012. The increase is a result of overall increased production volumes and higher estimated future development costs, as well as lower reserves in certain non-core areas. On a sales-unit basis, the provision for the year ended December 31, 2013 was $15.76/boe, as compared to $15.08/boe for the year ended December 31, 2012.

General and Administrative Expenses



	Years Ended December 31
($ thousands except for % and per boe)	2013		2012		Change
General and administrative expenses	$	45,461	$	44,646	2	%
General and administrative expenses per boe	$	2.18	$	2.26	(4	)%

General and administrative expenses for the year ended December 31, 2013 increased to $45.5 million from $44.6 million for the same period in 2012 due to higher salary and professional service costs, partially offset by higher capital and operating recoveries. On a sales-unit basis, general and administrative expenses decreased from $2.26/boe in the year ended December 31, 2012, to $2.18/boe in the year ended December 31, 2013 due to increased production in 2013.

Share-based Compensation Expense

On January 1, 2011, Baytex adopted a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards may be granted to directors, officers and employees of the Company and its subsidiaries. Concurrent with the adoption of the Share Award Incentive Plan, Baytex ceased making grants under the Common Share Rights Incentive Plan (the "Share Rights Plan").

Compensation expense related to the Share Award Incentive Plan decreased to $30.7 million for the year ended December 31, 2013, as compared to $33.8 million for the year ended December 31, 2012, mainly due to an increase in the estimated forfeiture rate on outstanding awards and a lower payout multiplier. Compensation expense related to the Share Rights Plan decreased to $1.6 million for the year ended December 31, 2013, as compared to $2.9 million for the year ended December 31, 2012, as fewer share rights vested in 2013. As at December 31, 2013, all outstanding share rights are fully expensed and exercisable.

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

Financing Costs



	Years Ended December 31
($ thousands except for %)	2013		2012		Change
Bank loan and other	$	10,139	$	11,074	(8	)%
Long-term debt	30,945		28,623		8	%
Accretion on asset retirement obligations	7,011		6,631		6	%
Debt financing costs	2,240		863		160	%
Financing costs	$	50,335	$	47,191	7	%

Financing costs for the year ended December 31, 2013 increased to $50.3 million, as compared to $47.2 million in 2012. The increase in financing costs for the year ended December 31, 2013 was primarily attributable to higher interest rates on borrowings and higher credit facility amendment fees, partially offset by lower debt levels as compared to the year ended December 31, 2012.

Baytex Energy Corp.

2013 MD&A Page 8

Foreign Exchange



	Years Ended December 31
($ thousands except for % and exchange rates)	2013			2012			Change
Unrealized foreign exchange loss (gain)	$	9,828		$	(1,533	)	(741	)%
Realized foreign exchange gain	(5,922		)	(3,206		)	85	%
Foreign exchange loss (gain)	$	3,906		$	(4,739	)	(182	)%
CAD/USD exchange rates:
At beginning of period	0.9949			1.0170
At end of period	1.0636			0.9949

The unrealized foreign exchange gains and losses for the years ended December 31, 2013 and 2012 are mainly due to foreign exchange translation of the U.S. dollar denominated debt outstanding and the effect of movement of the Canadian dollar against the U.S. dollar in the period. The U.S. dollar denominated debt is comprised of the US$150 million Series B senior unsecured debentures and, in 2012, the US$180 million portion of the bank loan which was repaid in July 2012.

The unrealized loss of $9.8 million for the year ended December 31, 2013, as compared to an unrealized gain of $1.5 million for the year ended December 31, 2012, was mainly the result of the weaker Canadian dollar against the U.S. dollar at December 31, 2013 (as compared to December 31, 2012) and the stronger Canadian dollar against the U.S. dollar at December 31, 2012 (as compared to December 31, 2011). The realized gain in the year ended December 31, 2013 and 2012 was mainly due to our day-to-day U.S. dollar denominated transactions.

Income Taxes

For the year ended December 31, 2013, income tax expense was $52.8 million, consisting of $6.8 million of current income tax recovery and $59.6 million of deferred income tax expense, as compared to $117.8 million for the year ended December 31, 2012 consisting of $10.2 million of current income tax expense and $107.6 million of deferred income tax expense.

When compared to the prior year, the decrease in income tax expense is primarily the result of a decrease in the amount of gain on divestiture of oil and gas properties.

The recovery of $6.8 million of current income tax expense reflects a true-up of current taxes previously estimated in the U.S.

Tax Pools

We have accumulated the Canadian and US tax pools as noted in the table below, which will be 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, Baytex does not expect to pay cash income taxes in Canada or in the United States in 2014.

Baytex Energy Corp.

2013 MD&A Page 9

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



($ thousands)	December 31, 2013		December 31, 2012
Canadian Tax Pools
Canadian oil and natural gas property expenditures	$	281,892	$	357,918
Canadian development expenditures	496,847		387,451
Canadian exploration expenditures	487		1,065
Undepreciated capital costs	380,704		311,335
Non-capital losses	160,203		335,566
Financing costs and other	10,874		13,583
Total Canadian tax pools	$	1,331,007	$	1,406,918
US Tax Pools
Taxable depletion	$	45,334	$	54,055
Intangible drilling costs	8,869		15,452
Tangibles	18,843		13,836
Non-capital losses	64,936		—
Other	7,182		7,237
Total US tax pools	$	145,164	$	90,580

Net Income

Net income for the year ended December 31, 2013 was $164.8 million, as compared to $258.6 million for the same period in 2012. The decrease in net income was due to a gain on disposition of U.S. properties of $172.5 million in 2012 which was not repeated in 2013, financial instrument losses in 2013 as compared to gains in 2012 and higher depletion and depreciation, partially offset by higher operating netbacks and lower current and deferred income tax expenses.

Other Comprehensive Income (Loss)

Revenues and expenses of foreign operations are translated to Canadian dollars using average foreign currency exchange rates for the period. Monetary assets and liabilities which form part of the net investment in the foreign operation are translated at the period-end foreign currency exchange rate. Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in shareholders’ equity and are recognized in net income when there has been a disposal or partial disposal of the foreign operation.

The $1.5 million balance of accumulated other comprehensive income at December 31, 2013 is the sum of a $12.5 million foreign currency translation loss incurred as at December 31, 2012 and a $13.9 million foreign currency translation gain related to the year ended December 31, 2013 due to the strengthening of the U.S. dollar against the Canadian dollar at December 31, 2013, as compared to December 31, 2012.

Business Combination

On February 6, 2014, Baytex entered an agreement to acquire all of the ordinary shares of Aurora Oil & Gas Ltd. ("Aurora") for A$4.10 (Australian dollars) per share by way of a scheme of arrangement under Part 5.1 of the Corporations Act 2001 (Australia) (the "Arrangement"). The total purchase price for Aurora is estimated at $2.6 billion (including the assumption of approximately $0.7 billion of indebtedness). Aurora’s primary asset is 22,200 net contiguous acres in the prolific Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford shale. Aurora’s fourth quarter 2013 gross production was 24,678 boe/d (82% liquids) of predominantly light, high-quality crude oil. The Sugarkane Field has been largely delineated with infrastructure in place which is expected to facilitate low-risk future annual production growth. In addition, these assets have significant future reserves upside potential from well downspacing, improving completion techniques and new development targets in additional zones.

The Arrangement is subject to a number of customary closing conditions, including the receipt of required regulatory approvals and court approvals, as well as the approval of the shareholders of Aurora. Regulatory approvals include approval of the Australian Foreign Investment Review Board and the applicable approvals required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 ("HSR"), as amended. On March 4, 2014, the Company received approval from the Federal Trade Commission with respect to HSR. The Arrangement must be approved by: (i) at least 75% of the votes cast by Aurora shareholders; and (ii) by a majority, in number, of the Aurora shareholders who cast votes. The Arrangement is expected to close in late May 2014.

To finance the acquisition of Aurora, Baytex has completed a subscription receipt financing and entered into a commitment letter with a Canadian chartered bank to establish new credit facilities, as described in more detail below.

Baytex Energy Corp.

2013 MD&A Page 10

On February 6, 2014, Baytex entered into an agreement, on a “bought-deal” basis, with a syndicate of underwriters for an offering of 33,420,000 subscription receipts (“Subscription Receipts”) at a price of $38.90 per Subscription Receipt with each Subscription Receipt entitling the holder thereof to receive, on closing of the Arrangement, one common share of the Company for aggregate gross proceeds of approximately $1.3 billion. The Company granted the underwriters an over-allotment option to purchase, on the same terms, up to an additional 5,013,000 Subscription Receipts. At the closing of the offering of the Subscription Receipts on February 24, 2014, Baytex issued 38,433,000 subscription receipts for aggregate gross proceeds of approximately $1.5 billion, which have been placed in escrow.

On February 6, 2014, Baytex entered into a commitment letter with a Canadian chartered bank for the provision of new revolving credit facilities in the amount of $1.0 billion (to replace the $850 million revolving credit facilities of Baytex Energy), new non-revolving facilities consisting of a $200 million term facility and a $1.3 billion equity bridge loan and a new borrowing base facility in the amount of US$300 million for a U.S. subsidiary of Aurora (to be established upon closing of the Arrangement as a replacement for an existing facility). As a result of the completion of the Subscription Receipt financing, the $1.3 billion equity bridge loan is no longer available.

FUNDS FROM OPERATIONS, PAYOUT RATIO, DIVIDENDS AND EBITDA

Funds from operations, payout ratio and EBITDA are non-GAAP measures. Funds from operations represents cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Payout ratio is calculated as cash dividends (net of participation in the Dividend Reinvestment Plan (“DRIP”)) divided by funds from operations. EBITDA is calculated to measure compliance with our contractual debt covenants. Baytex considers these to be key measures of performance as they demonstrate its ability to generate the cash flow necessary to fund dividends and capital investments.

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



	Years Ended December 31
($ thousands except for %)	2013			2012
Cash flow from operating activities	$	638,476		$	577,305
Change in non-cash working capital	(3,447		)	(11,570		)
Asset retirement expenditures	12,076			6,905
Financing costs	(50,335		)	(47,191		)
Accretion on asset retirement obligations	7,011			6,631
Accretion on debentures and long-term debt	657			645
Funds from operations	$	604,438		$	532,725
Dividends declared	$	327,029		$	317,110
Reinvested dividends	(89,366		)	(101,926		)
Cash dividends declared (net of DRIP)	$	237,663		$	215,184
Payout ratio	54		%	60		%
Payout ratio (net of DRIP)	39		%	40		%

Baytex does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of petroleum and natural gas assets, certain levels of capital expenditures are required to minimize production declines. In the petroleum and natural gas industry, due to the nature of reserve reporting, natural production declines and the risks involved in capital investment, a level of judgment is required to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Should the costs to explore for, develop or acquire petroleum and natural gas assets increase significantly, it is possible that Baytex would be required to reduce or eliminate its dividends in order to fund capital expenditures. There can be no certainty that Baytex will be able to maintain current production levels in future periods. Cash dividends declared, net of DRIP participation, of $237.7 million for the year ended December 31, 2013 were funded by funds from operations of $604.4 million.

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The following table reconciles net income (a GAAP measure) to EBITDA (a non-GAAP measure):



	Years Ended
($ thousands)	December 31, 2013			December 31, 2012
Net income	$	164,845		$	258,631
Plus:
Financing costs	50,335			47,191
Current tax (recovery) expense	(6,821		)	10,162
Depletion and depreciation	328,953			297,797
Charge on redemption of long-term debt	—			9,261
EBITDA attributable to disposal of assets	—			(3,293		)
Non-cash items⁽¹⁾	102,972			(50,402		)
EBITDA	$	640,284		$	569,347

(1) Non-cash items include share-based compensation, unrealized foreign exchange loss (gain), exploration and evaluation expense, unrealized loss (gain) on financial derivatives, (gain) loss on divestiture of oil and gas properties and deferred income tax expense.

LIQUIDITY AND CAPITAL RESOURCES

We regularly review our liquidity sources as well as our exposure to counterparties and have concluded that our capital resources are sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds from operations, augmented by our hedging program and existing credit facilities, will provide sufficient liquidity to sustain our operations in the short, medium and long-term. Further, we believe that our counterparties currently have the financial capacities to honor outstanding obligations to us in the normal course of business. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection from a counterparty.



($ thousands)	December 31, 2013		December 31, 2012
Bank loan	$	223,371	$	116,394
Long-term debt⁽¹⁾	459,540		449,235
Working capital deficiency⁽²⁾	79,151		34,197
Total monetary debt	$	762,062	$	599,826


(1)	Principal amount of instruments.


(2)	Working capital is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives, assets held for sale, and liabilities related to assets held for sale).

At December 31, 2013 total monetary debt was $762.1 million, as compared to $599.8 million at December 31, 2012. Total credit facilities in place are $850.0 million.

The Company's wholly-owned subsidiary, Baytex Energy Ltd. ("Baytex Energy"), has established a $40.0 million extendible operating loan facility with a chartered bank and an $810.0 million extendible syndicated loan facility with a syndicate of chartered banks, each of which constitute a revolving credit facility that is extendible annually for a 1, 2, 3 or 4 year period (subject to a maximum four-year term at any time). On June 4, 2013, Baytex Energy reached agreement with its lending syndicate to amend the credit facilities to (i) increase the amount available under the extendible syndicated loan facility to $810.0 million (from $660.0 million), (ii) extend the maximum term of the revolving period for both the operating and syndicated loan facilities to four years (from three years) and, (iii) extend the maturity date of both the operating and syndicated loan facilities to June 14, 2017 (from June 14, 2015). The credit facilities do not require any mandatory principal payments prior to maturity. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offer Rates, plus applicable margins. The credit facilities are secured by a floating charge over all of Baytex Energy’s assets and are guaranteed by Baytex and certain of its material subsidiaries. The credit facilities do not include a term-out feature or a borrowing base restriction. A copy of the amended and restated credit agreement (and related amendments) which establishes the credit facilities is accessible on the SEDAR website at www.sedar.com (filed under the category "Material Document" on July 22, 2011, July 10, 2012, January 14, 2013 and August 9, 2013).

The amended and restated credit agreement and the senior unsecured debentures contain standard commercial covenants that Baytex Energy is required to comply with. Baytex Energy is in compliance with all such covenants. The following table lists the financial covenants contained in the amended and restated credit agreement, the senior unsecured debenture agreement and Baytex Energy’s compliance therewith as at December 31, 2013.



Covenant Description	Maximum Ratio	Position at December 31, 2013
Bank loan
Senior secured debt to capitalization^{(1) (2)}	0.55:1.00	0.11:1.00
Senior secured debt to EBITDA⁽¹⁾	3.00:1.00	0.35:1.00
Debt to EBITDA⁽³⁾	3.50:1.00	1.07:1.00
Long-term debt
Fixed charge coverage⁽⁴⁾	2:50:1.00	0.08:1.00


(1)	"Senior secured debt" is defined as our bank loan.


(2)	"Capitalization" is defined as the sum of our bank loan, principal amount of long-term debt and shareholders' equity.


(3)	"Debt" is defined as the sum of our bank loan and the principal amount of long-term debt.


(4)	Fixed charge coverage is computed as the ratio of financing cost to trailing twelve month EBITDA.

In the event that Baytex Energy enters into a material acquisition, certain of the financial covenants are relaxed for up to two quarter ends following the closing of such material acquisition, provided that in each quarter: (i) the senior secured debt to EBITDA ratio shall not exceed 3.50:1.00; (ii) the debt to EBITDA ratio shall not exceed 4.00:1.00; and (iii) the sole cause of such ratios exceeding the levels set forth above is due to the material acquisition.

In the event that Baytex Energy does not comply with the covenants under the syndicated loan facility agreement, Baytex Energy would be required to repay, refinance, or renegotiate the loan terms and conditions which may restrict Baytex’s ability to pay dividends to its shareholders.

The weighted average interest rate on the bank loan for the year ended December 31, 2013 was 4.61% (year ended December 31, 2012 - 3.95%).

On July 19, 2012, we issued $300 million principal amount of Series C senior unsecured debentures bearing interest at 6.625% payable semi-annually with principal repayable on July 19, 2022. Net proceeds of this issue were used to repay a portion of the amount drawn in Canadian currency on Baytex Energy’s credit facilities. These debentures are unsecured and are subordinate to Baytex Energy’s credit facilities.

On August 26, 2012, we redeemed our 9.15% Series A senior unsecured debentures due August 26, 2016 ($150 million principal amount) at 104.575% of the principal amount. The payment of the redemption price was funded by drawing upon Baytex Energy's credit facilities.

Pursuant to various agreements with our lenders, we are restricted from paying dividends to shareholders where the dividend would or could have a material adverse effect on us or our subsidiaries' ability to fulfill our respective obligations under our senior unsecured debentures and Baytex Energy’s credit facilities.

Baytex believes that funds from operations, together with the existing credit facilities, will be sufficient to finance current operations, dividends to the shareholders and planned capital expenditures for the ensuing year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments. The level of dividend is also discretionary, and the Company has the ability to modify dividend levels should funds from operations be negatively impacted by factors such as reductions in commodity prices or production volumes.

Capital Expenditures

Capital expenditures are summarized as follows:



	Years Ended December 31
($ thousands)	2013			2012
Land	$	8,026		$	10,022
Seismic	3,094			2,410
Drilling and completion	368,801			287,475
Equipment	170,949			118,649
Other	30			69
Total exploration and development	$	550,900		$	418,625
Total acquisitions, net of divestitures	(39,082		)	(170,936		)
Total oil and natural gas expenditures	511,818			247,689
Other plant and equipment, net	4,059			6,338
Total capital expenditures	$	515,877		$	254,027

During the year ended December 31, 2013, Baytex drilled 226.8 net wells, as compared to 162.6 net wells in the year ended December 31, 2012. In 2013, capital investment activity has progressed as planned in our key development areas. Our thermal development projects are proceeding on schedule with facility construction underway at both our 15-well cyclic steam stimulation module at Cliffdale and our Gemini steam-assisted gravity drainage pilot project.

Shareholders’ Capital

Baytex is authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. Baytex establishes the rights and terms of preferred shares upon issuance. As at March 10, 2014, the Company had 126,113,046 common shares and no preferred shares issued and outstanding.

Contractual Obligations

Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s funds from operations in an ongoing manner. A significant portion of these obligations will be funded by funds from operations. These obligations as of December 31, 2013, and the expected timing of funding of 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	$	213,091	$	213,091	$	—	$	—	$	—
Dividends payable to shareholders	27,586		27,586		—		—		—
Bank loan⁽¹⁾	223,371		—		—		223,371		—
Long-term debt⁽²⁾	459,540		—		—		—		459,540
Operating leases	41,747		6,496		13,155		13,142		8,954
Processing agreements	35,593		4,107		6,815		5,550		19,121
Transportation agreements	72,778		6,592		19,835		17,974		28,377
Total	$	1,073,706	$	257,872	$	39,805	$	260,037	$	515,992


(1)	The bank loan is a covenant-based revolving loan that is extendible annually for a one, two, three or four year period (subject to a maximum four-year term at any time). Unless extended, the revolving period will end on June 14, 2017, with all amounts to be re-paid on such date.


(2)	Principal amount of instruments.

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

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Baytex is exposed to a number of financial risks, including market risk, liquidity risk and credit risk. 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 by Baytex through a series of derivative contracts intended to reduce some of the volatility of its operating cash flow. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its 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. Baytex manages credit risk by entering into sales contracts with creditworthy entities and reviewing its exposure to individual entities on a regular basis.

A summary of the risk management contracts in place as at December 31, 2013 and the accounting treatment of the Company’s financial instruments are disclosed in note 20 to the consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

A summary of Baytex's significant accounting policies can be found in notes 2 and 3 to the consolidated financial statements. The preparation of the consolidated financial statements in accordance with GAAP requires management to make judgments and estimates that affect the financial results of the Company. The financial and operating results of Baytex incorporate certain estimates including:


•	estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;


•	estimated capital expenditures on projects that are in progress;


•	estimated depletion and depreciation that are based on estimates of petroleum and natural gas reserves and future costs to develop those reserves that Baytex expects to recover in the future;

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2013 MD&A Page 12


•	estimated fair values of financial derivative contracts that are subject to fluctuation depending upon the underlying commodity prices, interest rates and foreign exchange rates;


•	estimated value of share-based compensation related to our Share Award Incentive Plan and Share Rights Plan and their related performance conditions and forfeiture rates;


•	estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and


•	estimated future recoverable value of petroleum and natural gas properties and goodwill.

Baytex employs individuals skilled in making such estimates and ensures 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.

CHANGES IN ACCOUNTING POLICIES

Current Accounting Pronouncements

Presentation of Financial Statements

Certain standards and amendments were issued effective for accounting periods beginning on or after January 1, 2013. Many of these updates are not applicable or consequential to the Company and have been excluded from the discussion below. As of January 1, 2013, the Company adopted the following IFRS standards and amendments in accordance with the transitional provisions of each standard.

Consolidation, Joint Ventures and Disclosures

Consolidated Financial Statements

IFRS 10 "Consolidated Financial Statements" replaces the consolidation guidance in IAS 27 "Consolidation and Separate Financial Statements" and Standing Interpretations Committee ("SIC") 12 "Consolidation - Special Purpose Entities" by introducing a single consolidation model for all entities based on control, irrespective of the nature of the investee. Under IFRS 10, control is based on whether an investor has: 1) power over the investee; 2) exposure, or rights, to variable returns from its involvement with the investee; and 3) the ability to use its power over the investee to affect the amount of the returns. The retrospective adoption of this standard did not have any impact on the Company's consolidated financial statements.

Joint Arrangement

IFRS 11 "Joint Arrangements" replaces the guidance in IAS 31 "Interests in Joint Ventures" and SIC 13 "Jointly Controlled Entities - Non-Monetary Contributions by Ventures", and divides joint arrangements into two types, joint operations and joint ventures, each with their own accounting model. The new standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted. Baytex accounts for its joint arrangements as joint operations. The retrospective adoption of this standard did not have any impact on the Company's consolidated financial statements.

Disclosure of Interests in Other Entities

IFRS 12 "Disclosure of Interests in Other Entities" requires enhanced disclosures about both consolidated entities and unconsolidated entities in which an entity has involvement. The objective of IFRS 12 is to require information so that financial statement users may evaluate the basis of control, any restrictions on consolidated assets and liabilities, risk exposures arising from involvements with unconsolidated structured entities and non-controlling interest holders' involvement in the activities of consolidated entities. The retrospective adoption of the annual disclosure requirements of this standard did not have a material impact on the Company's consolidated financial statements.

Separate Financial Statements

IAS 27 "Separate Financial Statements" has been amended as a result of changes to IFRS 10. The retrospective adoption of these amendments did not have any impact on the Company's consolidated financial statements.

Investments in Associates and Joint Ventures

IAS 28 "Investments in Associates and Joint Ventures" has been amended as a result of changes to IFRS 10 and IFRS 11. The retrospective adoption of these amendments did not have any impact on the Company's consolidated financial statements.

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Fair Value Measurement

IFRS 13 "Fair Value Measurement" defines fair value, establishes a framework for measuring fair value, and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The adoption of this standard requires the revaluation of certain derivative financial liabilities on the Company's consolidated balance sheets to reflect an appropriate amount of risk of non-performance by the Company. The prospective adoption of this standard did not have a material impact on the Company's consolidated financial statements.

Financial Instruments: Disclosures

IFRS 7 "Financial Instruments: Disclosures" has been amended to provide disclosure requirements about rights of offset and related agreements for financial statements under an enforceable master netting or similar agreement. The retrospective adoption of this amendment did not have any impact on the Company's consolidated financial statements.

Future Accounting Pronouncements

Levies

IFRS Interpretations Committee ("IFRIC") 21 "Levies" is effective January 1, 2014, and clarifies the recognition requirements concerning a liability to pay a levy imposed by a government, other than an income tax. The interpretation clarifies that the obligating event which gives rise to a liability is the activity that triggers the payment of the levy in accordance with the relevant legislation. The Company is assessing the impact of this interpretation on its consolidated financial statements.

Financial Instruments

IFRS 9, “Financial Instruments” replaces IAS 39 “Financial Instruments: Recognition and Measurement”, which 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. In November 2013, the IASB amended IFRS 9 to include the new general hedge accounting model which remains optional, allows more opportunities to apply hedge accounting, and defers the effective date of this standard indefinitely. The full impact from adoption will not be known until completion of the standard and may have an impact on the Company's accounting for financial assets and liabilities.

Financial Instruments: Presentation

IAS 32 "Financial Instruments: Presentation" has been amended to clarify certain requirements for offsetting financial assets and liabilities. IAS 32 relates to presentation and disclosure and is not expected to have a material impact on the Company's consolidated financial statements.

SELECTED ANNUAL INFORMATION



($ thousands, except per common share amounts)	2013		2012
Petroleum and natural gas revenues	$	1,115,410	$	1,215,606
Net income	$	164,845	$	258,631
Per common share - basic	$	1.33	$	2.16
Per common share - diluted	$	1.32	$	2.12
Total assets	$	2,698,334	$	2,538,077
Total bank loan and long-term debt	$	675,401	$	557,589
Cash dividends or distributions declared per common share	$	2.64	$	2.64
Average wellhead prices, net of blending costs per boe	$	61.74	$	55.48
Total production (boe/d)	57,196		53,986

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FOURTH QUARTER OF 2013

For a discussion and analysis of our operating and financial results for the three months ended December 31, 2013, please see our Management's Discussion and Analysis for the three months and year ended December 31, 2013 and 2012 dated March 12, 2014, which is incorporated by reference into this MD&A and is accessible on SEDAR at www.sedar.com.

2014 GUIDANCE & HIGHLIGHTS

The following guidance does not reflect the integration of Aurora.

We have set a 2014 exploration and development capital budget of $485 million for exploration and development activities. This capital budget is designed to generate an average production rate of 60,000 to 62,000 boe/d which reflects a production growth rate of 6% for oil equivalent volumes.

Our 2014 capital program includes the drilling of 201 net wells, of which 156 will target crude oil, three will target natural gas and 42 will be stratigraphic and service wells. Our 2014 stratigraphic and service well program will support multi-lateral drilling programs in future years and further delineate our lands for thermal development. Approximately 70% of our 2014 capital budget will be invested in our heavy oil operations at Peace River and Lloydminster. The balance of our capital program will be directed primarily towards light oil development, with the single largest project being the Bakken/Three Forks in North Dakota. Our 2014 development plan in North Dakota represents approximately 17% of our 2014 capital budget, and will include the drilling of approximately 15 gross (9.6 net) wells. Our 2014 production mix is forecast to be approximately 89% liquids (75% heavy oil and 14% light oil and natural gas liquids) and 11% natural gas, based on a 6:1 natural gas-to-oil equivalency.

Baytex expects to finance its 2014 capital budget and dividends with funds from operations and its existing credit capacity. Baytex is well positioned with a strong balance sheet and significant available credit capacity. At the end of the fourth quarter of 2013, Baytex had $627 million in undrawn credit facilities and no long-term debt maturities until 2021.

ENVIRONMENTAL REGULATION AND RISK

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal 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 set 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 Baytex believes that it 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 the Baytex's business, financial condition, results of operations and prospects.

Climate Change Regulation

The Government of Canada is a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a participant to 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). On January 29, 2010, Canada inscribed in the Copenhagen Accord its 2020 economy-wide target of a 17% reduction of GHG emissions from 2005 levels. This target is aligned with the United States target. In a report dated October 2013, the Government stated that this target represents a significant challenge in light of strong economic growth (Canada's economy is projected to be approximately 31% larger in 2020 compared to 2005 levels).

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets, for application to regulated sectors on a facility-specific, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors. The federal government indicates that it is taking a sector-by-sector regulatory approach to reducing GHG emissions and is working on regulations for other sectors. Representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In June 2012, the second US-Canada Clean Energy Dialogue Action Plan was released. The plan renewed efforts to enhance bilateral collaboration on the development of clean energy technologies to reduce GHG emissions.

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In addition to federal commitments and legislation, province specific legislation also imposes GHG emission standards and regulations which may impact Baytex and its operations and financial condition. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. The implementation of strategies for reducing GHG, whether to meet the goals of the UNFCCC, the Copenhagen Accord, federal or provincial regulations, or otherwise, could have a material impact on the nature of oil and natural gas operations, including those of Baytex. The direct or indirect costs of compliance with these regulations may have a material adverse effect on Baytex's business, financial condition, results of operations and prospects. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on Baytex and its operations and financial condition.

Further information regarding environmental and climate change regulation is contained in our Annual Information Form for the year ended December 31, 2013 under the "Industry Conditions - Climate Change Regulation" section.

DISCLOSURE CONTROL AND PROCEDURES

As of December 31, 2013, an evaluation was conducted of the effectiveness of Baytex's “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 President and Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that Baytex's disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that Baytex files or submits 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 the Company's management, including the President and Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding the required disclosure.

It should be noted that while the President and Chief Executive Officer and the Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Baytex's 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.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting for Baytex. “Internal control over financial reporting” (as defined in the United States by Rules 13a-15(f) and 15d-15(f) under the Exchange Act and in Canada by NI 52-109) is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of Baytex's financial statements for external reporting purposes in accordance with Canadian GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Additionally, projections of any evaluations of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with Baytex's policies and procedures. Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2013. The effectiveness of Baytex's internal control over financial reporting as of December 31, 2013 has been audited by Deloitte LLP, as reflected in their report for 2013.

No changes were made to our internal control over financial reporting during the year ended December 31, 2013.

FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to: crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our business strategies, plans and objectives; the acquisition of Aurora, including timing of completion of the acquisition; our plans to establish new revolving credit facilities, a term loan and a borrowing base facility for Aurora’s U.S. subsidiary upon closing of the Arrangement; payment of the purchase price for the acquisition of Aurora, including the

Baytex Energy Corp.

2013 MD&A Page 16

use of proceeds from the Subscription Receipt financing and our plans to draw on the new revolving credit facilities and term loan; our ability to fund our capital expenditures and dividends on our common shares from funds from operations; 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; funding sources for our cash dividends and capital program; the timing of funding our financial obligations; and the existence, operation and strategy of our risk management program. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time.

These forward-looking statements are based on certain key assumptions regarding, among other things: the receipt of regulatory, court and shareholder approvals for the Arrangement; our ability to execute and realize on the anticipated benefits of the acquisition of Aurora; 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; 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; the amount of future cash dividends that we intend to pay; 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). The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period 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 acquisition of Aurora may not be completed on the terms contemplated or at all; failure to realize the anticipated benefits of the acquisition of Aurora; closing of the acquisition of Aurora could be delayed or not completed if we are unable to obtain the necessary regulatory, court and shareholder approvals for the Arrangement or any other approvals required for completion or, unless waived, some other condition to closing is not satisfied; failure to put in place a borrowing base facility for Aurora’s U.S. subsidiary following completion of the Arrangement; declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and 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 the control of Baytex. These 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, 2012, 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 information has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations (if the acquisition of Aurora is completed) and such information may not be appropriate for other purposes.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast 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.