Pengrowth Energy Corporation
TSX : PGF
NYSE : PGH

Pengrowth Energy Corporation

March 03, 2014 08:00 ET

Pengrowth Exceeds 2013 Production Guidance on Lower Capital Expenditures and Delivers Strong Reserves Growth

CALGARY, ALBERTA--(Marketwired - March 3, 2014) - Pengrowth Energy Corporation (TSX:PGF)(NYSE:PGH) is pleased to announce its financial and operating results for the fourth quarter and the full year 2013, as well as strong 2013 year-end reserve results.

Production for the fourth quarter and the full year 2013 was above guidance, averaging 77,371 barrels of oil equivalent per day (boe/d) and 84,527 boe/d, respectively. The Company entered 2014 with approximately $450 million of cash on hand and the financial capacity to complete construction of the first commercial phase of its Lindbergh thermal bitumen project, with expected first steam in the fourth quarter of 2014 and first oil in early 2015.

Improved capital efficiency in the non-thermal business, including an expanded and highly attractive Cardium drilling program in the Lochend and Garrington areas, allowed Pengrowth to achieve strong production and cash flow results in 2013. Pengrowth was able to exceed its 2013 production guidance on capital spending of $696 million, $74 million less than had originally been budgeted.

Before adjusting for the impacts of the 2013 asset divestitures, Pengrowth achieved strong reserves growth with: Proved reserves (1P) increasing by 18 percent to 353 million barrels of oil equivalent (MMboe) and Proved plus Probable reserves (2P) growth of seven percent to 547 MMboe.

Pengrowth's differentiated strategy focusing on thermal bitumen is expected to enhance the Company's sustainability by shifting its production mix towards oil, reducing production decline rates and decreasing capital reinvestment requirements, thereby generating increased free cash flow to support dividends and profitable growth projects.

"2013 was a landmark year for Pengrowth, a year in which we set aggressive goals and achieved them. We disposed of approximately $1 billion of non-core assets to fully fund the first commercial phase of the Lindbergh project, received regulatory approval and began construction of the first phase in August. We enhanced the capital efficiency of our non-thermal business and finished the year strongly, with production exceeding guidance, spending $74 million less than budgeted and with $450 million of cash in the bank," said Derek Evans, President and CEO of Pengrowth. "In 2014, our primary objectives will be to get Lindbergh on stream, on time and on budget, maintain our current dividend, while protecting our balance sheet and continuing to invest efficiently in our non-thermal oil properties."

Financial and Operating Highlights:

  • Pengrowth delivered on its commitments in 2013, including re-positioning its asset portfolio and balance sheet to set itself up for first production from Lindbergh in early 2015, while maintaining a prudent capital structure and dividend plan going forward.
  • Annual average production of 84,527 boe/d, exceeded guidance and was achieved with a non-thermal capital program that was $74 million less than originally budgeted.
  • Successfully divesting approximately $1 billion of assets at excellent metrics of approximately $72,000/boe/d allowed Pengrowth to enter 2014 with approximately $450 million cash on hand and an undrawn, committed $1 billion bank facility.
  • Full year 2013 Funds Flow from Operations of $561 million compared to $539 million in 2012. The four percent increase in funds flow compared to 2012 resulted from higher realized commodity prices.
  • Pengrowth replaced 211 percent of 2013 production with organic 2P reserve additions, including revisions, of 65 MMboe.
  • 2P reserve life index (RLI) increased to 17.4 years at year-end 2013, an 18 percent increase from the year-end 2012 RLI of 14.7 years, due primarily to increased reserves at Lindbergh.
  • 2013 Finding and Development (F&D) cost was $21.96 per boe including changes in Future Development Costs (FDC) for 2P reserves. The 2013 F&D costs, excluding changes to FDC were $10.61 per boe for 2P reserves.
  • Pengrowth's three year weighted average Finding Development and Acquisition (FD&A) and F&D costs for 2P reserves were $19.03 per boe and $19.07 per boe, respectively, including FDC ($9.76 per boe and $8.43 per boe, respectively, excluding FDC).
  • Crude oil and natural gas liquid (NGL) reserves increased to 65 percent of total 1P and 2P reserves, compared to 57 percent and 63 percent of 1P and 2P reserves, respectively, at year-end 2012, as a direct result of focusing capital on oil and liquids-rich projects, particularly the Lindbergh thermal project.
  • The Lindbergh pilot continues to perform exceptionally well, with production volumes from the two well pairs at February 1, 2014 at approximately 1,900 bbl/d, with an Instantaneous Steam Oil Ratio (ISOR) of approximately 2.0. Total cumulative production from the two pilot wells has now exceeded 1.1 million barrels.
  • Construction of Lindbergh's first commercial phase remains on schedule and on budget, with 65 percent of the capital committed or spent as at March 3rd, 2014.
  • Lindbergh reserves increased significantly, with 70 MMbbl and 49 MMbbl of 1P and 2P reserve additions, including revisions, respectively, due to regulatory approval of the first phase commercial development, further delineation drilling and positive pilot results. At year-end 2013, 1P reserves were 82 MMbbl while 2P reserves stood at 143 MMbbl. Over and above the reserve volumes, the best estimate contingent resources was an incremental 163 MMbbl.
Summary of Financial & Operating Results
Three months endedTwelve months ended
(monetary amounts in millions)Dec 31, 2013Dec 31, 2012% ChangeDec 31, 2013Dec 31, 2012% Change
PRODUCTION
Average daily production (boe/d) 77,371 94,039 (18) 84,527 85,748 (1)
FINANCIAL
Funds flow from operations (1)$105.9 $189.7 (44)$560.9 $538.8 4
Funds flow from operations per share$0.20 $0.37 (46)$1.08 $1.20 (10)
Oil and gas sales including realized commodity risk management (1)$328.0 $431.6 (24)$1,538.4 $1,480.3 4
Oil and gas sales including realized commodity risk management per boe$46.08 $49.88 (8)$49.86 $47.17 6
Operating expense (2)$109.2 $114.5 (5)$482.5 $435.1 11
Operating expense per boe$15.34 $13.23 16 $15.64 $13.87 13
Royalty expense$62.8 $69.5 (10)$275.1 $277.5 (1)
Royalty expense per boe$8.82 $8.03 10 $8.92 $8.84 1
Royalty expense as a percent of sales 18.3% 16.8% 17.3% 19.0%
Operating netback per boe (1) (2)$20.82 $27.87 (25)$24.35 $23.67 3
Cash G&A expense (1) (2)$21.7 $25.1 (14)$87.8 $90.1 (3)
Cash G&A expense per boe$3.05 $2.90 5 $2.85 $2.87 (1)
Capital expenditures$239.7 $93.9 155 $695.8 $467.4 49
Capital expenditures per share$0.46 $0.18 156 $1.34 $1.05 28
Net cash acquisitions (dispositions)(3)$(29.2)$56.2 (152)$(977.7)$86.6
Net cash acquisitions (dispositions) per share$(0.06)$0.11 (155)$(1.89)$0.19
Dividends paid$62.4 $61.0 2 $248.1 $289.1 (14)
Dividends paid per share$0.12 $0.12 - $0.48 $0.69 (30)
Number of shares outstanding at period end (000's) 522,031 511,804 2 522,031 511,804 2
Weighted average number of shares outstanding (000's) 520,910 509,960 2 517,365 447,232 16
STATEMENT OF INCOME (LOSS)
Adjusted net income (loss) (1)$(37.3)$24.1 (255)$(183.8)$(89.7)105
Net income (loss)(3)$(91.1)$(1.0) $(316.9)$12.7
Net income (loss) per share(3)$(0.17)$- $(0.61)$0.03
CASH AND CASH EQUIVALENTS(3) $ 448.5 $ 2.7 $448.5 $2.7
DEBT (4)
Long term debt $1,412.7 $1,530.6 (8)
Convertible debentures $236.0 $237.1 -
Total debt excluding working capital $1,648.7 $1,767.7 (7)
Total debt including working capital $1,469.4 $1,589.2 (8)
CONTRIBUTION BASED ON OPERATING NETBACKS (1) (2)
Light oil 51% 65% 61% 68%
Heavy oil 17% 10% 15% 12%
Natural gas liquids 20% 13% 13% 15%
Natural gas 12% 12% 11% 5%
PROVED PLUS PROBABLE RESERVES
Light oil (Mbbls) 103,473 153,229 (32)
Heavy oil (Mbbls) 172,761 127,454 36
Natural gas liquids (Mbbls) 35,091 39,681 (12)
Natural gas (Bcf) 996 1,150 (13)
Total oil equivalent (Mboe) 477,385 511,960 (7)
CAPITAL PERFORMANCE
Finding & Development Cost (F&D) per boe (5) $21.96 $16.85 30
Recycle ratio (6) 1.1 1.4 (21)
1. See disclosures at end of release for definitions of additional GAAP and Non-GAAP Measures.
2. Prior periods restated to conform to presentation in the current period.
3. Percentage changes in excess of 500 are excluded.
4. Debt includes the current and long term portions.
5. Includes changes in Future Development Costs (FDC) and based on proved plus probable reserves.
6. Recycle ratio is calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves.

Production

Pengrowth's fourth quarter average production of 77,371 boe/d came in above guidance of 75,000 to 77,000 boe/d. Compared to fourth quarter 2012 average production of 94,039 boe/d, fourth quarter 2013 production declined 18 percent, primarily as a result of the sale of properties in 2013.

Full year 2013 average production of 84,527 boe/d also came in above guidance of 82,000 to 84,000 boe/d despite a non-thermal capital investment that was $74 million lower than budgeted. Compared to 2012 full year average production of 85,748 boe/d, 2013 production declined by one percent. Successful drilling at Lochend and Garrington in the Cardium formation underscored the efficiency of Pengrowth's non-thermal investments.

Capital Expenditures

Fourth quarter capital expenditures were approximately $240 million, with 87 percent of expenditures being directed to drilling, completions and facilities, with the remaining 13 percent spent on maintenance, land, seismic and other capital. Pengrowth participated in the drilling of 14 (8.3 net) non-thermal wells and 10 (10 net) wells (7 horizontal producers and 3 delineation/core holes) at Lindbergh during the quarter.

Full year 2013 capital spending of $696 million was ten percent lower than the original budget of $770 million. Similar to the fourth quarter, approximately 87 percent of the full year capital expenditures were allocated to drilling, completions and facilities and the remaining 13 percent spent on maintenance, land, seismic, and other capital. Pengrowth participated in the drilling of 139 (79.4 net) non-thermal wells and 36 (36 net) wells (7 horizontal producers, 19 delineation/core holes, 9 observation and 1 water disposal) at Lindbergh.

Pengrowth reduced capital investment in its non-thermal program and was still able deliver above the top end of its full year production guidance as a result of improving capital reinvestment efficiencies and strong drilling results in the Cardium. Pengrowth's non-thermal capital strategy involves selecting projects from its large prospect inventory that maximize near term cash flow, allow strong capital efficiencies and provide the quickest payout of capital dollars.

Lindbergh

Lindbergh is Pengrowth's 100 percent owned and operated thermal project, located in the Cold Lake area of eastern Alberta. The project offers Pengrowth the potential to develop production up to 50,000 bbl/d of bitumen over the next five years. Lindbergh's expected strong netbacks, low decline rates, long reserve life and low sustaining capital requirements are expected to be the foundation of Pengrowth's sustainable total return model, supporting future growth in cash flow per share and underpinning an attractive dividend.

Pengrowth's Lindbergh pilot delivered another strong year of results that demonstrated better than expected steam/oil and diluent blending ratios and stronger than expected production performance. Production from the two well pair pilot averaged 1,700 bbl/d during the fourth quarter, with cumulative production from the pilot surpassing one million barrels of bitumen by December 31, 2013. During the quarter, replacement of a pump on one of the producing wells temporarily reduced production, which has now returned to normal, with rates of approximately 1,900 bbl/d. The pilot wells are expected to begin their natural declines in 2014.

Pengrowth invested $136 million at Lindbergh in the fourth quarter, bringing the full year 2013 investment to $306 million, consistent with guidance. Civil and mechanical field construction, as well as shop fabrication of major and minor equipment components, continued for the first 12,500 bbl/d commercial phase. Tank construction and major equipment foundations are progressing as planned and shop fabricated modular equipment continues to be shipped to the site and set into place. Drilling from the first well-pad continued, with seven horizontal wells drilled in the fourth quarter and the pad completed in January 2014.

Capital spent or committed at Lindbergh is now approximately 65 percent of the budgeted total. The project remains on budget and on schedule, with first steam from the commercial project planned in the fourth quarter of 2014 and first oil in early 2015.

In December of 2013, Pengrowth filed its Environmental Impact Assessment (EIA) application for regulatory approval of an incremental 17,500 bbl/d expansion at Lindbergh. Approval of the EIA application is expected in early 2016.

Non-thermal Oil and Gas

Pengrowth's significant non-thermal oil and gas portfolio includes a large, contiguous land base in the Greater Olds/Garrington area, encompassing over 500 gross (250 net) sections of land, with opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. The extensive, existing gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large conventional oil and gas accumulations in the Swan Hills area, with low decline production, strong cash flow and future development opportunities.

During the fourth quarter, Pengrowth invested $104 million in its non-thermal assets, with 70 percent of the expenditures being directed to development activities. Pengrowth continued to achieve strong drilling and completion results with 14 (8.3 net) wells being drilled in the Cardium formation with 100 percent success. Based on initial test data and early production results, the Cardium wells appear to be meeting or exceeding type curve expectations.

For the full year 2013, Pengrowth invested approximately $390 million in its non-thermal assets, $74 million lower than budgeted. Approximately 77 percent of this investment was directed to development activities, primarily in the Greater Olds/Garrington area. Pengrowth participated in the drilling of 139 (79.4 net) non-thermal wells in 2013.

Operating Expenses

Fourth quarter 2013 operating expenses were $109 million ($15.34 per boe) compared to $115 million ($13.23 per boe) for the same period of 2012.

Full year operating expenses of approximately $483 million ($15.64 per boe) were 11 percent higher on an aggregate basis compared to 2012 expenses of $435 million ($13.87 per boe). Higher power costs, the inclusion of the Lindbergh thermal pilot expenses in 2013 results and higher processing and gathering fees were the primary contributors to the higher operating expenses in 2013. On a per boe basis, 2013 operating expenses increased $1.77/boe compared to 2012, due to the higher costs noted above and slightly lower production volumes as a result of the 2013 dispositions.

Funds Flow from Operations

Fourth quarter 2013 Funds Flow from Operations was $106 million ($0.20 per share) compared to $190 million ($0.37 per share) in the fourth quarter 2012. The 44 percent decrease in Funds Flow from Operations, when comparing the fourth quarter to the same period in 2012, was largely due to an 18 percent decrease in production volumes as a result of the 2013 dispositions and higher oil price differentials experienced in the quarter. The widening of light and heavy oil price differentials experienced in November and December reduced revenues and funds flow during the quarter by approximately $39 million compared to the fourth quarter of 2012.

Full year 2013 Funds Flow from Operations was $561 million ($1.08 per share) compared to $539 million ($1.20 per share) in 2012. The four percent increase in aggregate funds flow compared to 2012 resulted from higher commodity prices, partly offset by higher operating expenses year over year.

Adjusted Net Income (Loss)

Pengrowth recorded an adjusted net loss of $37 million in the fourth quarter and $184 million for the full year, largely as a result of one-time, non-cash losses on dispositions and realized commodity risk management losses. These compare to adjusted net income of $24 million in the fourth quarter of 2012 and adjusted net loss of $90 million for the full year 2012. See the Management's Discussion and Analysis accompanying Pengrowth's 2013 year-end financial statements for details. The Company continues to seek cash flow certainty by entering into commodity risk management contracts to ensure the financial flexibility to fund Lindbergh, pay its monthly dividend and continue to invest in its non-thermal oil assets.

Summary of Reserves Results

Pengrowth's reserves and present values at year-end 2013 were based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ) effective December 31, 2013, using the GLJ January 1, 2014 price forecast and prepared in accordance with National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH).

  • Pengrowth's year-end 2013 2P reserves, after the impacts of the 2013 dispositions, were 477 MMboe compared to 512 MMboe at year-end 2012.
  • The 6.8 percent decrease in 2P reserves compared to December 31, 2012 resulted from net asset dispositions of 69 MMboe and production of 31 MMboe, offset by a combination of drilling activity and increased reserve bookings at Lindbergh, which added 65 MMboe.
  • Total proved reserves at 2013 year-end, increased 2.3 percent to 307 MMboe from 300 MMboe at year-end 2012.
  • On a 1P basis, Pengrowth replaced 122 percent of 2013 production, adding 38 MMboe of 1P reserves net of dispositions.
  • Pengrowth's total proved reserves of 307 MMboe account for 64 percent of total 2P reserves.
  • Proved producing reserves of 186 MMboe represent approximately 60 percent of the total proved reserves.
  • Using a 6:1 boe conversion rate for natural gas, approximately 22 percent of 2P reserves are light/medium crude oil, 36 percent are heavy oil and bitumen, seven percent are NGL and 35 percent are natural gas.
  • Proved producing reserves and total proved reserves account for 53 and 74 percent respectively, of the 2P reserves before tax present value of $5.1 billion.
Table 1. Company Interest Reserves Summary*
As at December 31, 2013
Light & Medium crude oil (Mbbl) Heavy oil (Mbbl) Bitumen (Mbbl) Natural Gas Liquids (Mbbl) Natural Gas (Bcf) Total oil equivalent (Mboe) Percent of 2P oil equivalent
Proved Producing 57,926 13,273 1,304 23,587 537.9 185,743 39%
Proved Developed Non-producing 596 83 - 449 18.7 4,238 1%
Proved Undeveloped 14,771 5,955 80,423 1,306 87.5 117,035 25%
Total Proved 73,293 19,311 81,727 25,342 644.1 307,016 64%
Total Probable 30,180 10,884 60,838 9,749 352.3 170,369 36%
Total Proved Plus Probable 103,473 30,196 142,565 35,091 996.4 477,385 100%
* Numbers in table may not add due to rounding

Reserves Reconciliation

Total 2P reserve additions of 65 MMboe, including revisions, resulted from drilling and improved recovery projects, replacing production by 211 percent. The most significant of these additions were reserves attributed to the Lindbergh thermal project, where 2P reserves increased by 49 MMboe in 2013 over year-end 2012 numbers.

Non-core asset dispositions resulted in a 2P reserve decrease of 70 MMboe in 2013, partially offset by minor acquisitions of 1 MMboe. As a result of the large disposition program, total 2P reserves at year-end 2013 decreased by 6.8 percent compared to year-end 2012.

On a 1P basis, year-end 2013 reserves increased by 2.3 percent compared to 2012. In total, 38 MMboe of 1P reserves were added, including revisions and net of dispositions, replacing 122 percent of 2013 production.

Table 2. Company Interest Reserves Reconciliation 2013*
Light & Medium crude oil (Mbbl) Heavy oil (Mbbl) Bitumen (Mbbl) Natural Gas Liquids (Mbbl) Natural Gas (Bcf) Total oil equivalent (Mboe)
Total Proved
December 31, 2012 107,841 21,687 12,789 28,425 776.0 300,078
Technical Revisions 302 833 324 1,362 12.7 4,943
Economic Factors (10) (23) 0 (40) (2.4) (473)
Drilling 5,379 634 69,287 978 15.5 78,860
Improved Recovery 30 0 0 14 0.2 83
Acquisitions 311 61 0 150 1.8 816
Dispositions (30,683) (1,504) 0 (1,724) (75.2) (46,439)
Production (9,877) (2,376) (674) (3,824) (84.6) (30,852)
December 31, 2013 73,293 19,311 81,727 25,342 644.1 307,016
Total Proved Plus Probable
December 31, 2012 153,229 32,662 94,792 39,681 1,149.6 511,960
Technical Revisions (2,168) (298) 272 977 8.4 181
Economic Factors (58) (37) 0 (94) (4.1) (870)
Drilling 6,557 2,282 48,176 1,255 45.1 65,783
Improved Recovery 69 0 0 23 0.5 174
Acquisitions 409 76 0 183 2.2 1,030
Dispositions (44,687) (2,115) 0 (3,109) (120.7) (70,020)
Production (9,877) (2,376) (674) (3,824) (84.6) (30,852)
December 31, 2013 103,473 30,196 142,565 35,091 996.4 477,385
* Numbers in table may not add due to rounding
Table 3. Select prices from GLJ's January 1, 2014 forecast prices and inflation rates
Year WTI Crude Oil ($US/bbl) Edm Light Crude Oil ($Cdn/bbl) WCS Crude Oil ($Cdn/bbl) Natural Gas
at AECO ($Cdn/MMBtu)
Inflation Rate (%/year)
2013 (actual) 97.88 93.33 74.91 3.24 -
2014 97.50 92.76 75.60 4.03 2.0
2015 97.50 97.37 79.36 4.26 2.0
2016 97.50 100.00 81.50 4.50 2.0
2017 97.50 100.00 81.50 4.74 2.0
2018 97.50 100.00 81.50 4.97 2.0
2019 97.50 100.00 81.50 5.21 2.0
2020 98.54 100.77 82.13 5.33 2.0
2021 100.51 102.78 83.76 5.44 2.0
2022 102.52 104.83 85.44 5.55 2.0
2023 104.57 106.93 87.14 5.66 2.0
Thereafter +2.0 %/yr +2.0 %/yr +2.0 %/yr +2.0 %/yr 2.0
Table 4. Before Income Tax Net Present Value Summary
As at December 31, 2013
Discounted at Percent of 2P
($ millions, except percentages) Undiscounted 5% 10% 15% 20% Discounted at 10%
Proved Producing 4,369 3,358 2,742 2,333 2,043 53%
Proved Developed Non-producing 80 52 38 30 24 1%
Proved Undeveloped 2,952 1,719 1,052 661 416 20%
Total Proved 7,401 5,129 3,832 3,024 2,483 74%
Total Probable 5,372 2,392 1,316 841 593 26%
Total Proved Plus Probable 12,774 7,521 5,148 3,865 3,076 100%

Net Asset Value

The following table provides a calculation of Pengrowth's estimated net asset value (NAV) based on the estimated future net revenues associated with Pengrowth's proved plus probable reserves.

Table 5. Net Asset Value - Before Income Tax
As at December 31, 2013
($ millions, except percentages and share numbers) 5% Discount 10% Discount
Value of Total Proved plus Probable reserves(1)
7,521

5,148
Undeveloped Land(2) 184 184
Long-term debt, including convertible debentures and working capital(3) (1,452) (1,452)
Reclamation Funds(4) 55 55
Other Liabilities (Asset Retirement Obligations, commodity contracts, private investment)(5) (148) (10)
Net Asset Value 6,160 3,925
Shares outstanding (millions) 522 522
NAV per share ($/share) 11.80 7.52
1. Discounted value of GLJ total proved plus probable reserves.
2. Internal undeveloped land value estimate.
3. See 2013 Audited Financial Statements and Notes.
4. Pre-paid reclamation costs for Sable Offshore Energy Project, Nova Scotia and Judy Creek, Alberta.
5. Estimated value of commodity contracts, ownership in a private company and other liabilities.

As of December 31, 2013, Pengrowth's estimated NAV is $7.52/share. The 13 percent decrease from the 2012 year-end estimated NAV of $8.61/share is primarily due to a lower reserve value resulting from significant asset dispositions in 2013 and higher forecasted FDC.

Finding, Development and Acquisition Costs

During 2013, Pengrowth spent $692 million, excluding information technology and office expenditures, on development and optimization activities, which added 83 MMboe of 1P and 65 MMboe of 2P reserves including revisions, resulting in a 2P F&D cost of $21.96 (including FDC). The largest 2P additions were at Lindbergh, where 2P reserves increased by 49 MMboe due to further delineation drilling and continued superior pilot performance.

Pengrowth's 2013 F&D and FD&A costs are summarized below. These are determined separately for exploration and development activities, acquisition and disposition transactions, and with and without the change in FDC. FDC reflects the amount of estimated capital that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. Pengrowth includes FD&A costs because it believes that acquisitions and dispositions can have a significant impact on its ongoing reserve replacement costs.

Table 6. 2013 F&D and FD&A Costs



2013


2012

2011 - 2013
Weighted Average

Proved
Proved plus
Probable

Proved
Proved plus
Probable

Proved
Proved plus
Probable
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM 692.4 692.4 461.0 461.0 1,756.8 1,756.8
Exploration and Development Reserve Additions including Revisions - MMboe 83.4 65.3 21.0 103.8 145.5 208.4
Finding and Development Cost - $/boe 8.30 10.61 21.93 4.44 12.08 8.43
F&D Recycle Ratio, $/$ 2.9 2.3 1.1 5.3 2.1 3.0
Net Acquisition (Disposition) Capital - $MM (977.8) (977.8) 1,654.2 1,654.2 668.1 668.1
Net Acquisition (Disposition) Reserve Additions - MMboe (45.6) (69.0) 75.9 109.4 30.1 40.1
Net Acquisition Cost - $/boe 21.43 14.17 21.81 15.12 22.21 16.64
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM (285.3) (285.3) 2,115.2 2,115.2 2,424.9 2,424.9
Reserve Additions including Net Acquisitions (Dispositions) - MMboe 37.8 (3.7) 96.9 213.2 175.6 248.5
Finding Development and Acquisition Cost - $/boe1 (7.55) 76.66 21.83 9.92 13.81 9.76
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM 692.4 692.4 461.0 461.0 1,756.8 1,756.8
Exploration and Development Change in FDC - $MM 1,031.7 741.2 104.6 1,288.0 1,393.3 2,217.1
Exploration and Development Capital including Change in FDC - $MM 1,724.1 1,433.6 565.6 1,748.9 3,150.1 3,973.9
Exploration and Development Reserve Additions including Revisions - MMboe 83.4 65.3 21.0 103.8 145.5 208.4
Finding and Development Cost - $/boe 20.67 21.96 26.91 16.85 21.65 19.07
F&D Recycle Ratio, $/$ 1.2 1.1 0.9 1.4 1.2 1.3
Net Acquisition (Disposition) Capital - $MM (977.8) (977.8) 1,654.2 1,654.2 668.1 668.1
Net Acquisition (Disposition) FDC - $MM (224.7) (381.2) 229.8 467.2 5.1 86.0
Net Acquisition (Disposition) Capital including Change in FDC - $MM (1,202.5) (1,359.0) 1,884.0 2,121.4 673.3 754.2
Net Acquisition (Disposition) Reserve Additions - MMboe (45.6) (69.0) 75.9 109.4 30.1 40.1
Net Acquisition Cost - $/boe 26.36 19.70 24.83 19.39 22.38 18.79
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM (285.3) (285.3) 2,115.2 2,115.2 2,424.9 2,424.9
Total Change in FDC - $MM 807.0 360.0 334.4 1,755.2 1,398.4 2,303.2
Total Capital including Change in FDC - $MM 521.7 74.6 2,449.6 3,870.4 3,823.3 4,728.1
Reserve Additions including Net Acquisitions (Dispositions) - MMboe 37.8 (3.7) 96.9 213.2 175.6 248.5
Finding Development and Acquisition Cost including FDC - $/boe2 13.80 (20.05) 25.29 18.16 21.78 19.03



2013


2012 (Restated)

2011 - 2013
Weighted Average
Operating Netback ($/boe)3 24.35 23.67 25.52
1. The negative 2013 FD&A Cost excluding FDC for Proved Reserves is due to the proceeds from dispositions exceeding capital expenditures plus acquisition costs.
2. The negative 2013 FD&A Cost including FDC for P+P Reserves is due to the reserve decrease from dispositions exceeding the reserve additions, including revisions, from development activity and acquisitions.
3. The operating netbacks are equal to sales revenue plus other income less royalties, operating expenses and transportation costs. Please see Pengrowth's 2013 year-end Management Discussion and Analysis (MD&A) and Annual Information Form (AIF) dated February 28, 2014 for further information.
4. The aggregate of the exploration and development costs incurred in the most recent financial year and the changes during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Table 7. Total Future Net Revenue (Undiscounted)
($ millions) Revenue Royalties Operating Costs Development Costs Abandonment Costs1 Revenue Before Income Tax Income Tax2 Revenue After
Income Tax
Proved Producing 11,911 2,130 4,917 187 308 4,369 28 4,341
Proved Developed Non-producing 213 34 78 17 4 80 19 61
Proved Undeveloped 8,794 1,624 2,376 1,797 45 2,952 821 2,131
Total Proved 20,918 3,788 7,371 2,001 357 7,401 868 6,533
Total Probable 13,668 2,975 3,883 1,380 58 5,372 1,509 3,863
Total Proved Plus Probable 34,587 6,763 11,254 3,382 415 12,774 2,378 10,396
1. Includes GLJ's estimate of well abandonment costs and abandonment costs for Sable Island facilities and subsea pipelines, but does not include abandonment costs for other facilities or any surface reclamation costs. Please see our AIF for further information.
2. Income tax values were calculated by Pengrowth using GLJ's before tax cash flow, current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. Please see our AIF for further information.

Reserve Life Index

Pengrowth's proved RLI increased to 11.8 years from 9.2 years in 2012. The RLI for proved plus probable reserves increased to 17.4 years at year-end 2013, an 18 percent increase from the year-end 2012 RLI of 14.7 years, due primarily to increased reserves at Lindbergh.

Table 8. Historical Reserve Life Index
Reserve Line Index (Years) 2013 2012 2011 2010
Proved Producing 7.4 7.6 7.6 7.2
Total Proved 11.8 9.2 9.0 8.2
Total Proved Plus Probable 17.4 14.7 12.0 11.1

RLI refers to the number of years determined by dividing Company Interest reserves of a property by the next year's forecast Company Interest production for the corresponding reserve category from such property. The reserves and next year's forecast production for such property come from the GLJ Report.

Reserves and Contingent Resources Classification

The following table summarizes GLJ's estimates of reserves and contingent resources, as of year-end 2013, for the Lindbergh thermal property and Groundbirch natural gas property.

Table 9. Summary of Reserves and Contingent Resources
Reserves (MMboe) Contingent Resources (MMboe)
Field Proved Proved + Probable Proved + Probable + Possible Low Estimate Best Estimate High Estimate
Lindbergh 82 143 196 124 163 276
Groundbirch 10 32 39 36 57 100

The contingencies which prevent the contingent resources from being classified as reserves at Lindbergh include: the need for additional evaluation well drilling within the area, firm development plans, high quality project design and cost estimates and commitment by Pengrowth for future development phases and regulatory approval for expanding the current development area. It is expected that GLJ will do a full reserve and resource update for Lindbergh in the third quarter of 2014, which will incorporate the results of first half delineation drilling, pilot performance and impact of the EIA application filed in December 2013 to expand the Lindbergh development area.

The primary contingency which prevents the contingent resources at Groundbirch to be classified as reserves is the early evaluation and delineation stage of the tight gas resource. Additional drilling, completion and testing data, in conjunction with higher gas prices is required before Pengrowth can commit to further development.

Reserves and contingent resources included herein are stated on a Company interest basis unless noted otherwise. All reserves information has been prepared in accordance with NI 51-101 Standards of Disclosure for Oil and Gas Activities and COGEH. In addition to the information disclosed in this news release, more detailed information is included in Pengrowth's Annual Information Form (AIF) dated February 28, 2014, which is available on SEDAR at www.SEDAR.com.

Financial Flexibility

Pengrowth remains committed to ensuring its financial health and flexibility during its transition to becoming a low decline, sustainable, dividend paying, higher cash flowing thermal energy producer. The Company has taken several measures intended to safeguard its dividend, maintain its financial and balance sheet strength and provide additional flexibility to ensure that it has the financial means and discipline to develop its Lindbergh thermal project. These measures include:

  • Selling approximately $1 billion of non-core properties in 2013.
  • Reducing indebtedness
  • Expanding commodity hedging
  • Managing interest costs through terming out debt at fixed rates

Following the closing of the non-core dispositions, Pengrowth had approximately $450 million of cash on hand as at December 31, 2013. These proceeds will be used to provide the capital for the completion of the first 12,500 bbl/d commercial phase of Lindbergh, as well as provide Pengrowth with a balanced cash flow profile through 2014, whereby cash outflows are expected to equal cash inflows plus cash on hand.

Pengrowth continues to mitigate commodity price risk and provide a measure of stability and predictability to cash flows through the utilization of hedging. At March 3rd, 2014, Pengrowth has 76 percent of its expected 2014 oil production hedged at Cdn$94.51 per barrel and 62 percent of 2015 expected oil production hedged at Cdn$93.91 per barrel. Natural gas hedges account for 64 percent of expected 2014 gas production at Cdn$3.81 per Mcf and 49 percent of 2015 expected production hedged at Cdn$3.85 per Mcf. Pengrowth also hedges portions of its power consumption in order to mitigate volatility in operating expenses. Pengrowth has hedged 78 percent of expected 2014 power consumption at $55.69/MWh and 61 percent of expected 2015 power consumption at $49.50/MWh.

Additional details of Pengrowth's risk management contracts in place for 2014, 2015 and 2016 are outlined in the Management's Discussion and Analysis and accompanying Notes to the December 31, 2013 Audited Financial Statements.

Pengrowth's total long-term debt was approximately $1.6 billion as at December 31, 2013, comprising $1.4 billion of fixed rate term notes and $0.2 billion of convertible debentures. At December 31, 2013, Pengrowth's $1.0 billion bank facility continued to be undrawn and the company had approximately $450 million of cash on hand.

2014 Capital Expenditures

The 2014 capital program will once again target the development of light oil and liquids-rich natural gas production, while continuing to invest in the commercial development of the Lindbergh project. Pengrowth has budgeted $350 million for non-thermal activities, mainly in the Greater Olds/Garrington area and on heavy oil assets in the Jenner and Bodo areas. The 2014 non-thermal budget will focus on projects with the highest rates of return, shortest payouts and maximum funds flow.

At Lindbergh, $365 million has been budgeted for 2014, which includes the completion of the central processing facility, drilling the remaining 16 well pairs for the first 12,500 bbl/d commercial phase and investment to facilitate incremental production in 2016.

A summary of Pengrowth's 2014 operating and financial guidance is provided below:

Average daily production volume (boe/d) 71,000 to 73,000
Total capital expenditures ($millions) 700 to 730
Royalties (% of sales) 16 to 18
Net operating costs ($ per boe)1 15.20 to 15.80
Cash G & A expense ($ per boe)1 2.70 to 2.90
Funds flow from operations ($ per share)2 0.95 to 1.05
1. Per boe estimates based on high and low ends of production guidance.
2. Based on mid-point of production guidance using WTI USD$95/bbl, 8% discount for light oil and 21% discount for heavy oil, $3.50/Mcf AECO and $0.95 USD/CAD FX rate and approximately 525 million shares outstanding.

Outlook

Pengrowth continues on its transition to becoming a sustainable, low decline, dividend paying, higher cash flowing thermal energy producer. In 2014, the primary objectives will be to maintain Pengrowth's dividend at the current level of four cents per share per month, while continuing to execute on the commercial development of the Lindbergh thermal project, ensuring Lindbergh is on time, on budget and en route to first steam in the fourth quarter of 2014, with meaningful oil production in early 2015. Pengrowth will invest in its best opportunities, maximizing funds flow from its non-thermal business, while continuing to be prudent in managing its balance sheet and maintaining financial flexibility.

Pengrowth's audited Financial Statements for the three and twelve months ended December 31, 2013 and related Management's Discussion and Analysis, as well as Pengrowth's AIF dated February 28, 2014, can be viewed on Pengrowth's website at www.pengrowth.com. They will also be available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml.

Conference call:

Pengrowth will host a conference call for investors at 6:30 A.M. Mountain Time on Monday, March 3, 2014. To participate, callers may dial in via telephone or participate online in listen only mode via the audio webcast. To ensure timely participation in the teleconference, callers are encouraged to dial in 10 minutes prior to commencement of the call to register.

Dial-in numbers:

Toll free: (866) 223-7781 or Toronto local (416) 340-2216

Live listen only audio webcast: http://www.gowebcasting.com/5262

About Pengrowth:

Pengrowth Energy Corporation is a dividend-paying, intermediate Canadian producer of oil and natural gas, headquartered in Calgary, Alberta. Pengrowth's assets include the Cardium light oil, Lindbergh thermal bitumen and Swan Hills light oil projects. Pengrowth's shares trade on both the Toronto Stock Exchange under the symbol "PGF" and on the New York Stock Exchange under the symbol "PGH".

PENGROWTH ENERGY CORPORATION

Derek Evans, President and Chief Executive Officer

For further information about Pengrowth, please visit our website www.pengrowth.com or contact: Investor Relations, E-mail: investorrelations@pengrowth.com

Currency:

All amounts are stated in Canadian dollars unless otherwise specified.

Advisory Regarding Reserves, Contingent Resources and Production Information

All reserves, reserve life index, and production information herein is based upon Pengrowth's company interest (Pengrowth's working interest share of reserves or production plus Pengrowth's royalty interest, being Pengrowth's interest in production and payment that is based on the gross production at the wellhead), before deduction of royalty obligations and using GLJ's January 1, 2014 forecast prices and costs as disclosed herein. Numbers presented may not add due to rounding.

The estimated value of reserves disclosed in this press release does not represent fair market value of the reserves. The estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregation.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political and regulatory matters or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates. Contingent Reserves do not constitute and should not be confused with reserves. There is no certainty that it will be commercially viable to produce any portion on the Contingent Resources. The estimates of Contingent Resources associated with Pengrowth's Lindbergh thermal oil property and Groundbirch gas property included herein have been evaluated by GLJ, Pengrowth's independent qualified reserves evaluator, in accordance with COGEH and NI 51-101. A best estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 50 percent confidence level. A low estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a 90 percent confidence level. A high estimate is the estimate of the quantity of resource that will be recovered from the accumulation, which under probabilistic methodology reflects a ten percent confidence level. The Contingent Resources as disclosed herein are considered economic based on forecast prices and costs as at December 31, 2013. Additional information relating to the Contingent Resources estimate for Pengrowth's Lindbergh thermal oil property and Groundbirch gas property, including specific contingencies and significant positive and negative factors associated with the estimate, can be found in Pengrowth's AIF dated February 28, 2014, which can be accessed immediately on Pengrowth's website at www.pengrowth.com and has been filed on SEDAR at www.sedar.com and on Form 40-F on EDGAR at www.sec.gov/edgar.shtml.

Caution Regarding Engineering Terms:

When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Caution Regarding Forward Looking Information:

In the interest of providing our shareholders and potential investors with information regarding us, including management's assessment of our future plans and operations, certain statements in this press release are forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of the Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to future dividends; 2014 anticipated capital expenditures and the allocation thereof; the Company's non-thermal capital strategy; Lindbergh development being on time and on budget; bringing Lindbergh on stream; ability of Lindbergh to generate cash flow; timing of Lindbergh development; Lindbergh production potential; future declines on Lindbergh pilot wells; expected average daily production; expected decline rates, reserve life and capital requirements of Lindbergh; expected first steam and production from the first commercial phase of Lindbergh; timing for approval of the Company's environmental impact assessment; anticipated timing for a reserves and resources update at Lindbergh; planned financial flexibility; benefit of commodity risk management program; improved capital efficiencies to be realized in 2014; number of wells to be drilled at Lindbergh in 2014; assumptions as to future commodity prices, discounts and exchange rates; future expansion of Lindbergh facility to accommodate additional commercial production; recycle ratios; number of rigs operating; future production declines and free cash flow; financing plans; adjusted payout ratio; net operating costs for 2014; anticipated G&A expenses; 2014 guidance including average daily production, total capital expenditures, royalties, net operating costs, cash flow, cash G&A and funds flow from operations per share; plans to manage interest costs by terming out debt at fixed rates. Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: changes in general economic, market and business conditions; the volatility of oil and gas prices; fluctuations in production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; geological, technical, drilling and processing problems and other difficulties in producing reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; fluctuations in interest rates; inadequate insurance coverage; compliance with environmental laws and regulations; actions by governmental or regulatory agencies, including changes in tax laws; Pengrowth's ability to access external sources of debt and equity capital; the impact of foreign and domestic government programs and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Further information regarding these factors may be found under the heading "Business Risks" in our most recent management's discussion and analysis and under "Risk Factors" in our Annual Information Form dated February 28, 2014.

The foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release, and Pengrowth 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 required by applicable laws.

The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.

Additional and Non-IFRS Measures

In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents additional and non-IFRS measures, Adjusted Net Income (Loss), operating netbacks, adjusted payout ratio and Funds Flow from Operations. These measures do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies. These measures are provided, in part, to assist readers in determining Pengrowth's ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth's ongoing business on an overall basis.

These measures should be considered in addition to, and not as a substitute for, net income (loss), cash provided by operations and other measures of financial performance and liquidity reported in accordance with IFRS. Further information with respect to these additional and non-IFRS measures can be found in Pengrowth's most recent management's discussion and analysis.

Note to US Readers

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

Current SEC reporting requirements permit, but do not require United States oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information.

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

Contact Information

  • Pengrowth
    Fred Kerr
    Vice President, Investor Relations
    Toll free 1-855-336-8814

    Pengrowth
    Wassem Khalil
    Manager, Investor Relations
    Toll free 1-855-336-8814
    www.pengrowth.com