Pengrowth Energy (PGH) 40-F 2016 FY Annual report (Canada)

SUPPLEMENTAL UNAUDITED DISCLOSURES

ABOUT OIL AND GAS PRODUCING ACTIVITIES REQUIRED UNDER UNITED

STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

SUPPLEMENTAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES

(unaudited)

The following are supplementary oil and gas disclosures required as a result of Pengrowth Energy Corporation ("Pengrowth") being an SEC registrant. All amounts pertain to Pengrowth’s audited annual consolidated financial statements prepared in accordance with International Financial Reporting Standards ("IFRS"). All amounts are in millions of Canadian dollars unless otherwise noted.

OIL AND GAS RESERVES

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made, Pengrowth’s estimated future production volumes and SEC Modernization of Oil and Gas Reporting rules, using the average of the first-day-of-the-month prices for the prior 12 month period. This same 12 month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The unaudited supplemental information on oil and gas exploration and production activities for 2016 and 2015 has been presented in accordance with the SEC Modernization of Oil and Gas Reporting reserve estimation and disclosure rules. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Pengrowth's share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2016, no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

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COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

(millions of dollars)	2016		2015
Property acquisition costs
- Proved	$	1.3	$	0.9
- Unproved	—		—
Exploration costs	0.3		3.6
Development costs	20.2		114.4
Injectants costs	0.4		4.4
	$	22.2	$	123.3

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development and exploration costs include the costs for drilling and equipping development and exploratory wells, constructing facilities to extract, treat, gather and store oil and gas, and land rights purchases. These costs also include capitalized amounts associated with asset retirement obligations and capitalized interest.

Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated to be 24 months.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration and development activities.

Approximately $502.1 million (2015 – $500.5 million) of capitalized costs to acquire and evaluate unproven and development properties has been excluded from depletion.

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CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to Pengrowth’s oil and gas exploration, development and producing activities at December 31 consist of:

(millions of dollars)	2016		2015
Oil and natural gas assets	$	2,956.1	$	3,334.0
Add: Exploration and evaluation assets	496.3		494.8
	$	3,452.4	$	3,828.8
Unproved oil and gas properties
Unproven properties included in oil and natural gas assets	$	864.9	$	602.7
Exploration and evaluation assets	496.3		494.8
	$	1,361.2	$	1,097.5
Proven oil & gas properties	2,091.2		2,731.3
Total capitalized costs	$	3,452.4	$	3,828.8

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OIL AND GAS RESERVE INFORMATION

All of Pengrowth’s proved oil, natural gas liquids, and natural gas reserves are located in Canada, in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Pengrowth’s proved developed and undeveloped reserves after deductions of royalties are summarized below:

Net Proved Developed and Undeveloped Reserves After Royalties	Crude Oil			Bitumen			NGLs			Natural Gas
	MMbbls			MMbbls			MMbbls			Bcf
End of year 2014	69.5			82.1			17.8			525.3
Revisions of previous estimates (including infill drilling & improved recovery)	(14.6	)	a	16.9		b	(4.3	)	a	(113.2	)	a
Purchase of reserves in place	0.1			—			—			0.2
Sale of reserves in place	(9.4	)	c	—			(0.6	)		(45.7	)
Discoveries and extensions	0.9			—			0.4			23.5		d
Production	(6.8	)		(3.7	)		(2.6	)		(58.7	)
End of Year 2015	39.7			95.3			10.7			331.4
Revisions of previous estimates (including infill drilling & improved recovery)	(1.2	)		16.0		e	5.0		f	21.7		f
Purchase of reserves in place	—			—			—			—
Sale of reserves in place	(4.3	)		—			(0.1	)		(6.6	)
Discoveries and extensions	—			36.1		g	0.9			8.0
Production	(3.9	)		(5.5	)		(2.3	)		(42.7	)
End of Year 2016	30.3			141.9			14.2			311.8
Notes Re Significant Changes:
(a) Primarily due to the lower constant oil and gas prices used for the reserve evaluation at December 31, 2015.
(b) Primarily due to lower royalties for the Lindbergh oil sands development resulting from the lower constant bitumen price used in the reserve evaluation at December 31, 2015.
(c) Due to our non-core asset disposition program as described more fully under "Acquisitions and Divestitures" on page 23 of Exhibit 99.1, Pengrowth's Annual Information Form, to our Form 40-F dated February 24, 2016.
(d) Primarily due to activity in the Groundbirch area as described more fully under "Reserves Reconciliation" on pages 20 and 21 of Exhibit 99.1, Pengrowth's Annual Information Form, to our Form 40-F dated February 24, 2016.
(e) Primarily due to lower royalties for the Lindbergh oil sands development resulting from the lower constant bitumen price used in the reserve evaluation at December 31, 2016 and improved performance.
(f) Due to improved performance and infill drilling in various properties.
(g) Primarily due to reserves associated with regulatory approval of Lindbergh oil sands Phase 2 expansion.
Net Proved Developed and Undeveloped Reserves After Royalties	Crude Oil			Bitumen			NGLs			Natural Gas
	MMbbls			MMbbls			MMbbls			Bcf
Net Proved Developed Reserves After Royalty
End of year 2014	54.1			21.6			17.0			447.9
End of year 2015	33.4			16.5			10.3			242.4
End of year 2016	26.5			13.9			11.7			207.6
Net Proved Undeveloped Reserves After Royalty
End of year 2014	15.4			60.5			0.8			77.4
End of year 2015	6.3			78.8			0.4			89.0
End of year 2016	3.8			128.0			2.5			104.2

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Notes:

1. Net after royalty reserves are Pengrowth’s lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Crown royalties are subject to change by legislation or regulation and vary depending on production rates, selling prices and potential timing of initial production.

2. Reserves are the estimated quantities of crude oil, natural gas and related substances 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 the average of the commodity prices on the first day of each month for the years ended December 31, 2016 and 2015.

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

4. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

The following information is based on crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of Pengrowth. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Pengrowth or its performance. Further, 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 current value of Pengrowth’s reserves.

The future cash flows presented below are based on cost rates, and statutory income tax rates in existence as of the date of the projections and the average of commodity prices in effect on the first day of each month for the year ended December 31, 2016 and December 31, 2015. It is expected that revisions to some estimates of crude oil and natural gas reserves may occur in the future, due to development and production of the reserves that may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

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 computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2016 was based on the following average of the first-day-of-the-month benchmark prices for the twelve month period before the end of the year: Edmonton par crude oil price of $52.12/bbl (2015 - $58.88/bbl) and AECO natural gas price of $2.18/MMBtu (2015 - $2.68/MMBtu).

STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

The following table sets forth the standardized measure of discounted future net cash flows at 10% from projected production of Pengrowth’s crude oil and natural gas reserves at December 31, for the years presented.

(millions of dollars)	2016			2015
Future cash inflows	$	6,801		$	7,226
Future costs
- Future production costs	(4,227		)	(4,945		)
- Future developments costs	(1,464		)	(1,254		)
- Future income taxes	—			—
Future net cash flows	$	1,110		$	1,027
Deduct: 10% annual discount factor	(569		)	(314		)
Standardized measure of discounted future net cash flows	$	541		$	713

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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

At December 31, for the years presented, the following table sets forth the changes in the standardized measure of discounted future net cash flows at 10%.

(millions of dollars)	2016			2015
Future discounted net cash flow at beginning of year	$	713		$	3,717
Sales & transfer, net of production costs	(599		)	(644		)
Net change in sales & transfer prices	(474		)	(2,274		)
Development costs incurred during the period	63			181
Change in future development costs	(92		)	64
Change due to extensions and discoveries	87			18
Change due to revisions (including infill drilling & improved recovery)	53			18
Accretion of discount	71			397
Sales of reserves in place	(20		)	(271		)
Net change in income taxes	—			248
Changes in timing of future net cash flow and other	739			(741		)
Future discounted net cash flow at end of year	$	541		$	713

Note:

1. The schedules above are calculated using year-end costs, statutory tax rates and proved oil and gas reserves and the average of the commodity prices on the first day of each month for the years ended December 31, 2016 and 2015. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

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OTHER OIL AND GAS INFORMATION

Exploration and Development Activities

The following table summarizes the number of wells drilled during the financial year ended December 31, 2016.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	1	0.2	—	—	1	0.2
Crude Oil	—	—	—	—	—	—
Bitumen	—	—	—	—	—	—
Service	—	—	—	—	—	—
Stratigraphic Test	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	1	0.2	—	—	1	0.2

The following table summarizes the number of wells drilled during the financial year ended December 31, 2015.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	2	1.4	—	—	2	1.4
Crude Oil	7	5.4	1	0.3	8	5.7
Bitumen	—	—	—	—	—	—
Service	—	—	—	—	—	—
Stratigraphic Test	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	9	6.8	1	0.3	10	7.1

The following table summarizes the number of wells drilled during the financial year ended December 31, 2014.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	8	5.2	—	—	8	5.2
Crude Oil	92	56.8	2	0.5	94	57.3
Bitumen	13	13.0	—	—	13	13.0
Service	30	29.8	—	—	30	29.8
Stratigraphic Test	39	39.0	—	—	39	39.0
Dry	1	0.8	—	—	1	0.8
Total	183	144.6	2	0.5	185	145.1

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Oil and Gas Wells

As at December 31, 2016, we had an interest in 4,406 gross (2,464 net) producing oil and natural gas wells and 2,464 gross (1,375 net) non-producing wells. All wells are onshore except for wells in Nova Scotia which are all offshore.

	Producing		Non-Producing		Total
	Gross	Net	Gross	Net	Gross	Net
Crude Oil Wells
Alberta	1,707	917	983	467	2,690	1,384
British Columbia	75	43	197	130	272	173
Saskatchewan	60	2	15	5	75	7
Bitumen Wells
Alberta	22	22	—	—	22	22
Natural Gas Wells
Alberta	2,393	1,399	703	423	3,096	1,822
British Columbia	137	79	187	107	324	186
Saskatchewan	1	1	9	3	10	4
Nova Scotia	11	1	10	1	21	2
Other
Alberta	—	—	271	178	271	178
British Columbia	—	—	87	59	87	59
Saskatchewan	—	—	2	2	2	2
Total	4,406	2,464	2,464	1,375	6,870	3,839

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