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Exhibit 99.12

Baytex Energy Corp.
Supplemental Disclosures about Extractive Activities — Oil and Gas (unaudited)
December 31, 2014

The following disclosures have been prepared by Baytex Energy Corp. ("Baytex" or the "Company") in accordance with Accounting Standards Codification 932 "Extractive Activities — Oil & Gas" ("ASC 932") issued by the Financial Accounting Standards Board.

Petroleum and Natural Gas Reserve Information

Proved petroleum and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids ("NGL") that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed petroleum and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, which may require future expenditures.

Proved undeveloped petroleum and natural gas reserves are reserves that are expected to be recovered from known accumulations where a future expenditure is required.

Reserves are estimated quantities of crude oil, NGL and natural gas anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and considered to be economic at average commodity prices based upon the prior 12-month period. Estimates of petroleum and natural gas reserves are subject to uncertainty and will change as additional information regarding the producing fields and technology becomes available and as future economic conditions change. Net reserves presented in this section represent the Company's working interest and overriding royalty share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.

The changes in Baytex's net proved crude oil and NGL and natural gas reserves under constant prices and costs for the two-year period ended December 31, 2014 were as follows:

	Canada									United States								Total

	Crude Oil & NGL (mbbl)			Bitumen (mbbl)			Natural Gas (mmcf)			Crude Oil & NGL (mbbl)			Bitumen (mbbl)		Natural Gas (mmcf)			Crude Oil & NGL (mbbl)			Bitumen (mbbl)			Natural Gas (mmcf)
Net proved reserves
December 31, 2012		74,328			17,067			48,711			15,951			—		8,597			90,279			17,067			57,308
Revisions of previous estimates		(342	)		1,142			7,314			8,263			—		23,512			7,921			1,142			30,826
Improved recovery		209			—			—			—			—		—			209			—			—
Purchases		—			—			—			—			—		—			—			—			—
Extensions and discoveries		10,566			—			2,825			659			—		751			11,225			—			3,576
Production		(12,632	)		(846	)		(13,020	)		(771	)		—		(80	)		(13,403	)		(846	)		(13,100	)
Sales of minerals in place		(1,086	)		—			—			—			—		—			(1,086	)		—			—

December 31, 2013		71,043			17,363			45,830			24,102			—		32,780			95,145			17,363			78,610

Revisions of previous estimates		646			(1,317	)		31,865			—			—		—			646			(1,317	)		31,865
Improved recovery		33			—			2			—			—		—			33			—			2
Purchases		3,282			—			—			99,848			—		179,376			103,130			—			179,376
Extensions and discoveries		6,795			—			11,428			—			—		—			6,795			—			11,428
Production		(12,442	)		(1,051	)		(12,993	)		(4,959	)		—		(5,972	)		(17,401	)		(1,051	)		(18,965	)
Sales of minerals in place		(3,648	)		—			(6,770	)		(24,122	)		—		(32,845	)		(27,770	)		—			(39,615	)

December 31, 2014		65,709			14,995			69,362			94,869			—		173,339			160,578			14,995			242,701

Net proved developed reserves
End of year 2012		43,394			4,623			35,875			4,021			—		1,951			47,415			4,623			37,826
End of year 2013		43,161			9,929			35,017			4,325			—		5,091			47,486			9,929			40,108
End of year 2014		40,931			8,157			48,321			32,227			—		50,768			73,158			8,157			99,089
Net proved undeveloped reserves
End of year 2012		30,934			12,444			12,836			11,930			—		6,646			42,864			12,444			19,482
End of year 2013		27,882			7,434			10,813			19,777			—		27,689			47,659			7,434			(9,282	)
End of year 2014		24,778			6,838			21,041			62,642			—		122,571			87,420			6,838			143,612

The most significant changes to proved reserves estimates (and related changes to standardized measure of future net cash flows described below) occurring between December 31, 2012 and December 31, 2013 related primarily to the addition to previous proved reserves estimates of reserves in the Bakken/Three Forks area in North Dakota. The most significant changes to proved reserves estimates (and related changes to standardized measure of future net cash flows described below) occurring between December 31, 2013 and December 31, 2014 related to the purchase of proved reserves in the Eagle Ford shale in South Texas attributable to the Company's acquisition of Aurora Oil & Gas Limited in June 2014 and the sale of proved reserves as a result of the Company's disposition of its Bakken/Three Forks properties in North Dakota in September 2014.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Petroleum and Natural Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC 932, as updated by Accounting Standards Update 2010-03 "Oil and Gas Reserve Estimation and Disclosures", and based on crude oil, NGL and natural gas reserve and production volumes estimated by Baytex's independent reserves evaluator, Sproule Associates Limited. The methodology used in calculating our price and cost assumptions for the standardized measure of discounted future net cash flows for reserve estimation is based upon the average first-day-of-the-month prices during the year.

Future production and development costs are based on forecast price assumptions and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the petroleum and natural gas properties based upon existing laws and regulations. A 10% discount factor was applied to the future net cash flows.

The information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the fair market value of Baytex's petroleum and natural gas properties. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The prescribed discount rate of 10% may not appropriately reflect interest rates.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was based on an unweighted arithmetic average of the first-day-of-the-month price for each month in 2014 and 2013.

	Commodity Pricing

	2014		2013
WTI crude (US$/bbl)	$	94.99	$	96.94
Edmonton par (Cdn$/bbl)	$	94.84	$	92.73
Heavy oil⁽¹⁾ (Cdn$/bbl)	$	82.96	$	74.22
AECO-C spot price (Cdn$/mmbtu)	$	4.60	$	3.16
Henry Hub (US$/mmbtu)	$	4.30	$	3.68
Exchange rate (US$/Cdn$)		0.9100		0.9717

(1): Heavy oil pricing refers to Western Canadian Select reference price.

The standardized measure of discounted future net cash flows relating to net proved oil, NGL and natural gas reserves are as follows:

	Canada						United States						Total

(thousands of Canadian dollars)	2014			2013			2014			2013			2014			2013
Future cash inflows	$	5,927,985		$	5,908,063		$	8,246,158		$	2,262,625		$	14,174,143		$	8,170,688
Future production costs		(2,013,766	)		(2,446,053	)		(2,082,635	)		(500,460	)		(4,096,401	)		(2,946,513	)
Future development costs		(659,398	)		(647,433	)		(1,678,370	)		(619,088	)		(2,337,768	)		(1,266,521	)
Future income taxes		(467,661	)		(372,089	)		(670,916	)		(444,121	)		(1,138,577	)		(816,210	)

Future net cash flows		2,787,160			2,442,488			3,814,237			698,956			6,601,397			3,141,444
Deduct:
10% annual discount factor		(869,342	)		(742,421	)		(1,618,886	)		(395,433	)		(2,488,228	)		(1,137,854	)

Standardized measure	$	1,917,818		$	1,700,067		$	2,195,351		$	303,523		$	4,113,169		$	2,003,590

Reconciliation of Changes in Standardized Measure of Future Net Cash Flows Discounted at 10% per Year Relating to Proved Petroleum and Natural Gas Reserves

As at December 31, 2014 (thousands of Canadian dollars)	Canada			United States			Total

Balance, beginning of year	$	1,700,067		$	303,523		$	2,003,590
Sales, net of production costs		(787,203	)		(331,794	)		(1,118,997	)
Net change in prices and production costs related to future production		(510,709	)		—			(510,709	)
Changes in previously estimated production costs incurred during the period		2,359			(899,225	)		(896,866	)
Development costs incurred during the period		388,406			384,465			772,871
Extensions, discoveries and improved recovery, net of related costs		175,968			—			175,968
Revisions of previous quantity estimates		788,598			—			788,598
Sales of reserves in place		(30,069	)		(537,424	)		(567,493	)
Purchases of reserves in place		78,732			3,362,185			3,440,917
Accretion of discount		152,375			47,274			199,649
Net change in income taxes		(40,707	)		(133,653	)		(174,360	)

Balance, end of year	$	1,917,817		$	2,195,351		$	4,113,168

As at December 31, 2013 (thousands of Canadian dollars)	Canada			United States			Total

Balance, beginning of year	$	1,727,560		$	113,445		$	1,841,005
Sales, net of production costs		(716,841	)		(44,581	)		(761,422	)
Net change in prices and production costs related to future production		16,617			16,974			33,591
Changes in previously estimated production costs incurred during the period		80,168			(224,833	)		(144,665	)
Development costs incurred during the period		467,191			75,176			542,367
Extensions, discoveries and improved recovery, net of related costs		248,269			218,266			466,535
Revisions of previous quantity estimates		(284,204	)		244,884			(39,320	)
Sales of reserves in place		(7,498	)		—			(7,498	)
Purchases of reserves in place		—			—			—
Accretion of discount		160,493			18,380			178,873
Net change in income taxes		8,312			(114,188	)		(105,876	)

Balance, end of year	$	1,700,067		$	303,523		$	2,003,590

Capitalized Costs Relating to Petroleum and Natural Gas Producing Activities

As at December 31, 2014 (thousands of Canadian dollars)	Canada			United States			Total

Proved properties	$	3,392,578		$	3,039,182		$	6,431,760
Unproved properties		124,494			417,546			542,040

Total capital costs		3,517,072			3,456,728			6,973,800
Accumulated depletion and depreciation		(1,258,258	)		(189,586	)		(1,447,844	)

Net capitalized costs	$	2,258,814		$	3,267,142		$	5,525,956

As at December 31, 2013 (thousands of Canadian dollars)	Canada			United States			Total

Proved properties	$	3,047,557		$	290,761		$	3,338,318
Unproved properties		127,736			35,556			163,292

Total capital costs		3,175,293			326,317			3,501,610
Accumulated depletion and depreciation		(999,832	)		(38,207	)		(1,038,039	)

Net capitalized costs	$	2,175,461		$	288,110		$	2,463,571

Costs Incurred in Petroleum and Natural Gas Property Acquisition, Exploration and Development Activities

For year ended December 31, 2014 (thousands of Canadian dollars)	Canada			United States			Total

Property acquisition costs⁽¹⁾
Proved properties	$	1,005		$	2,524,018		$	2,525,023
Unproved properties		10,948			392,315			403,263
Property dispositions⁽²⁾		(45,816	)		(337,314	)		(383,130	)
Development costs⁽³⁾		388,405			370,543			758,948
Exploration costs⁽⁴⁾		5,823			1,299			7,122

Total	$	360,365		$	2,950,861		$	3,311,226

For year ended December 31, 2013 (thousands of Canadian dollars)	Canada			United States			Total

Property acquisition costs
Proved properties	$	3,604		$	90		$	3,694
Unproved properties		707			2,353			3,060
Property dispositions		(45,003	)		(833	)		(45,836	)
Development costs⁽³⁾		467,191			75,176			542,367
Exploration costs⁽⁴⁾		7,110			1,423			8,533

Total	$	433,609		$	78,209		$	511,818

(1): Property acquisition costs include the acquisition of Aurora Oil & Gas Limited.
(2): Property dispositions include the disposition of assets in North Dakota and in Canada.
(3): Development and facilities capital expenditures.
(4): Cost of geological and geophysical capital expenditures and drilling costs for exploratory wells.

Results of Operations for Producing Activities

For year ended December 31, 2014 (thousands of Canadian dollars except per boe amounts)	Canada		United States		Total

Petroleum and natural gas revenues, net of royalties	$	1,124,279	$	405,618	$	1,529,897
Less:
Operating costs, production and mineral taxes		272,515		81,334		353,849
Transportation expense		141,886		—		141,886
Depreciation and depletion		332,108		204,461		536,569

Operating income		377,770		119,823		497,593
Income taxes		195		53,680		53,875

Results of operations⁽¹⁾	$	377,575	$	66,143	$	443,718

Depletion rate per net boe		16.02		25.30		18.75

For year ended December 31, 2013 (thousands of Canadian dollars except per boe amounts)	Canada		United States			Total

Petroleum and natural gas revenues, net of royalties	$	1,049,268	$	66,142		$	1,115,410
Less:
Operating costs, production and mineral taxes		253,958		21,561			275,519
Transportation expense		158,841		—			158,841
Depreciation and depletion		307,845		21,108			328,953

Operating income		328,624		23,473			352,097
Income taxes		—		(6,821	)		(6,821	)

Results of operations⁽¹⁾	$	328,624	$	30,294		$	358,918

Depletion rate per net boe		15.63		17.88			15.76

(1): Excludes corporate overhead and interest costs.

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Exhibit 99.12