News
print   email   rss

Penn West Announces its Financial and Operational Results for the Year Ended December 31, 2016 and 2016 Reserves Results

Mar 15, 2017

CALGARY, March 15, 2017 /CNW/ - PENN WEST PETROLEUM LTD. (TSX – PWT; NYSE – PWE) ("Penn West", the "Company", "we", "us" or "our") is pleased to announce financial and operational results for the year ended December 31, 2016, along with year-end 2016 reserves results.

"2016 was a year of reshaping and rebuilding for Penn West as we examined every aspect of our business to ensure we are well structured to thrive in today's commodity price environment," commented David French, President and Chief Executive Officer.

"Throughout 2016 we focused our efforts on three things. First, we simplified our balance sheet by completing our disposition program resulting in $1.4 billion in asset-sales in 2016, with an additional $65 million closed to date in the first quarter and a final $10 million to be completed shortly. These sales allowed us to reduce our debt by 76% in 2016 and significantly lower environmental liabilities, putting us on track to bring our Alberta Liability Management Ratio ("LMR") to two times by the end of 2017.

Second, we refocused our attention on operational efficiencies in a small number of key development areas where we hold industry leading positions. These changes are already bearing fruit, exhibited by a 12% increase in our cash margins, inclusive of hedging, year over year. Our portfolio offers an attractive balance of shorter-cycle opportunities including industry leading well rates in the Alberta Viking and cold flow manufacturing in Peace River, complemented by our mid-cycle Cardium integrated waterflood development. Our production mix is liquids-weighted and can be toggled higher or lower as we see fit. We are working the right assets and delivering their promise.

And lastly, we reshaped our year-end reserves to reflect a simpler and cleaner Penn West.  We received our first foothold reserve bookings for early results in our Cardium waterflood program, saw proceeds from sales from our divestment program exceed the change in our net asset value, and realigned our reserves in Peace River to shift from thermal to cold flow development. Our year-end results and reserves reflect the substantial underlying value of our new portfolio and provide a platform well positioned for growth and cash flow generation for years to come.

As we close the chapter on 2016, 2017 offers investors and stakeholders a platform focused on long-term value creation. The foundation of our portfolio of assets is best defined as leading positions in key development areas that will offer double-digit organic and self-funded growth in production over the course of 2017."

Penn West Results for the Three and Twelve Months Ended December 31, 2016





Three months ended December 31

Twelve months ended December 31


2016

2015

% change

2016

2015

% change

Financial (millions, except per share amounts)









Funds flow from operations (1)

$

48

$

39

23

$

182

$

249

(27)


Basic per share (1)


0.10


0.08

25


0.36


0.50

(28)


Diluted per share (1)


0.10


0.08

25


0.36


0.50

(28)

Net loss


(232)


(1,606)

(86)


(696)


(2,646)

(74)


Basic per share


(0.46)


(3.20)

(86)


(1.39)


(5.27)

(74)


Diluted per share


(0.46)


(3.20)

(86)


(1.39)


(5.27)

(74)

Capital expenditures (2)

50


99

(49)


82


470

(83)

Long-term Debt

$

469

$

1,940

(76)

$

469

$

1,940

(76)












Operations











Daily production












Light oil and NGL (bbls/d)


15,803


41,378

(62)


26,059


47,279

(45)


Heavy oil (bbls/d)


5,493


11,962

(54)


8,750


11,984

(27)


Natural gas (mmcf/d)


103


144

(28)


121


163

(26)

Total production (boe/d) (3)


38,481


77,398

(50)


54,990


86,357

(36)

Average sales price












Light oil and NGL (per bbl)

$

52.34

$

47.00

11

$

43.74

$

50.05

(13)


Heavy oil (per bbl)


27.09


25.40

7


21.22


33.26

(36)


Natural gas (per mcf)

$

2.98

$

2.54

17

$

2.14

$

2.86

(25)

Netback per boe (3)












Sales price

$

33.33

$

33.80

(1)

$

28.83

$

37.40

(23)


Risk management gain


4.27


4.89

(13)


5.03


2.59

94


Net sales price


37.60


38.69

(3)


33.86


39.99

(15)


Royalties


(1.26)


(4.39)

(71)


(1.08)


(4.05)

(73)


Operating expenses (4)


(14.05)


(17.43)

(19)


(13.18)


(18.56)

(29)


Transportation


(1.62)


(1.55)

5


(1.72)


(1.46)

18


Netback (1)

$

20.67

$

15.32

35

$

17.88

$

15.92

12

(1)

The terms "funds flow from operations" and their applicable per share amounts, and "netback" are non-GAAP measures. Please refer to the "Non-GAAP Measures" advisory section below for further details.

(2)

Capital expenditures include costs related to Property, Plant and Equipment. Includes the effect of capital carried from its partner under the Peace River Oil Partnership.

(3)

Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".

(4)

Includes the effect of carried operating expenses from its partner under the Peace River Oil Partnership of $5 million or $1.30 per boe (2015 – $4 million or $0.47 per boe) for the three months ended and $15 million or $0.75 per boe (2015 – $13 million or $0.40 per boe) for the twelve months ended on a combined basis.

(5)

Certain comparative figures have been reclassified to correspond with current period presentation.

 

2016 Year-End Operational and Financial Highlights

Simplifying our Balance Sheet by Completing the Disposition Program

  • Last year, the Company closed asset dispositions for proceeds of $1.4 billion in a major restructuring and renovation effort. The Company is on track to complete its asset disposition program near the end of the first quarter, with $65 million in proceeds closed year-to-date and total proceeds expected to be $75 million. The marginal production impact of the first quarter dispositions is approximately 1,000 boe per day on an annualized basis

  • The Company reduced Senior Debt to $469 million at year-end 2016, down from $1.9 billion a year earlier, and finished 2016 with a Senior Debt to EBITDA of 2.0 times

  • The number of Company wellbores was 6,500 at year-end, down from 13,200 at the end of the previous year. The number of wellbores is expected to fall further to 4,900 at the end of the first quarter significantly reducing our environmental liabilities

  • Discounted Asset Retirement Obligations ("ARO"), excluding associated ARO from assets held for sale, fell to $182 million on December 31, 2016 from $397 million on December 31, 2015

Improving Efficiencies with a Focused Portfolio

  • 2016 Funds Flow from Operations of $182 million ($0.36 per share) reflected improving efficiencies throughout the portfolio. In 2016, the Company's per unit cash margins, inclusive of hedging, were up 12% from 2015 despite a 23% reduction in the blended commodity price. This was driven primarily through an improvement in operating costs to $13.18 per boe, down 29% from the previous year

  • After the renovation process, Penn West now holds a focused portfolio with industry leading positions in the Cardium, Peace River, and Alberta Viking areas, which produced a combined 28,655 boe per day in the fourth quarter. This portfolio is approximately two-thirds liquids and is underpinned by shallow corporate declines, creating a foundation for growth

2016 Year-End Reserves Highlights

Foothold Reserve Bookings for Cardium Waterfloods

  • The 2016 reserves book has started to recognize the success of our new Cardium waterflood development. On a proved developed producing ("PDP") basis, increased reservoir pressure from injection resulted in the recognition of increasing light crude oil and falling conventional gas volumes in our reserve book. We received an incremental 2.1 mmboe in probable undeveloped waterflood additions. Should these wells continue to see active natural gas suppression and increased production response as forecast, we believe there will be additional reserve recognition of our methodology at year-end 2017

Asset Dispositions Accretive to Net Asset Value

  • The largest changes to our reserves at the end of 2016, across all reserve categories, were driven by asset dispositions. In 2016, we closed asset transactions for total cash proceeds of approximately $1.4 billion, above both the associated PDP and proved ("1P") before-tax present values, discounted at 10 per cent, of $1.1 billion and $1.2 billion, respectively

Realigned Reserves in Peace River for Cold Flow Development

  • We realigned our reserve book in the Peace River to shift away from thermal to cold flow development to better align with our near-term development plans in the current price environment. The removed thermal undeveloped bookings of 27 mmboe would have contributed only $20 million in proved plus probable ("2P") before-tax present value, with associated future development capital of $389 million

Recognizing the Efficiency Improvements and Potential in the Portfolio

  • We chose to use a conservative booking methodology for the undeveloped potential in our renovated portfolio. Our 2P reserves account for only approximately 1.5 years of development in the Peace River and in the Alberta Viking, and no development in the Mannville. We feel that with successful execution in these areas in our 2017 program, we can begin to formally recognize the significant running room we have in these plays

  • We received positive technical revisions, acknowledging both lower operating costs and improved performance across our portfolio, which offset the economic revisions due to lower commodity price assumptions. The PDP before-tax present value, discounted at 10 per cent, received a positive technical revision of $486 million versus a negative economic revision of $223 million. The proved plus probable before-tax present value, discounted at 10 per cent, received a positive technical revision of $476 million versus a negative economic revision of $296 million

  • The 2016 2P operated development cost of $5.86 per boe (or $11.26 per boe excluding the impact of our partner capital in Peace River) reflects the capital efficiency of converting liquids resources into reserves and undeveloped reserves into developed reserves in our key development areas. We calculate 2P operated development cost as the sum of reserves added from all operated wells spud in the year divided by the drill, complete, equip, and tie-in costs incurred to bring these wells on production

  • The 2016 Finding and Development ("F&D") Cost, inclusive of changes to future development capital, on a 2P basis, was $16.45 per boe. These costs reflect our limited spending in the first half of the year which focused on base and facility maintenance and had a limited reserve impact. The Company's 2016 recycle ratio was approximately 1.1 times

Hitting the Ground Running in 2017

  • Last year, the Company extended its commodity risk program out six quarters and increased its hedged volumes for 2017. Penn West currently has approximately 50% of its net oil volumes and 25% of its net gas volumes hedged for 2017. As a result, the Company expects its capital program to be entirely self-funded even with a drop in oil prices down to US$40 per barrel WTI

  • In 2017, the Company plans to self-fund a $180 million capital program that is poised to deliver double-digit production growth from the fourth quarter of 2016 to the fourth quarter of 2017 in our key development areas

Operational Discussion

As a result of the asset dispositions and portfolio renovation over the past year, Penn West now holds a focused portfolio with industry leading positions in the Cardium, Peace River, and Alberta Viking areas.

The table below outlines select metrics in our key development areas for the three months ended December 31, 2016 and excludes the impact of hedging:




Area


Select Metrics – Three Months Ended December 31, 2016


Production

Liquids
Weighting

Operating
Cost

Netback

Cardium


18,081 boe/d

62%

$14.79/boe

$22.40/boe

Alberta Viking


1,415 boe/d

48%

$19.59/boe

$10.82/boe

Peace River(1)


4,867 boe/d

99%

$1.00/boe

$22.58/boe

Legacy Areas


4,292 boe/d

21%

$26.54/boe

($4.65)/boe

Key Development Areas


28,655 boe/d

61%

$14.44/boe

$17.81/boe

(1)

Net of carried operating costs

 

In the fourth quarter of 2016, we completed our second half drilling program of 5 Cardium wells, 11 Alberta Viking wells, and 19 Peace River oil wells. The second half 2016 drilling program contributed over 3,000 boe per day of production on December 31, 2016.

The table below provides a summary of our operated activity during the fourth quarter:






Number of Wells



Drilled

Completed

On production



Gross

Net

Gross

Net

Gross

Net

Cardium


6

6

5

5

2

2


Producer


3

3

5

5

2

2


Injector


3

3

0

0

0

0

Alberta Viking


0

0

11

11

9

9

Peace River


15

8.3

13

7.2

13

7.2

Total


21

14.3

29

23.2

24

18.2

 

The table below outlines select reserve metrics in our key development areas, excluding assets sold or held for sale in 2017, for the year-ending December 31, 2016:






Area


PDP

1P

2P


Volumes

(MMBoe)

Net Asset
Value

($ million)

Volumes

(MMBoe)

Net Asset
Value

($ million)

Volumes

(MMBoe)

Net Asset
Value

($ million)

Cardium


56

$994

73

$1,070

102

$1,326

Alberta Viking


2

$35

3

$38

4

$51

Peace River


6

$121

8

$162

12

$216

Legacy Areas


7

$71

7

$73

10

$93

Key Development Areas


71

$1,221

91

$1,343

128

$1,686

 










Area




2P Reserve Life
Index


Discounted Future
Development Capital


Years of Development at
2017 Pace

Cardium




16.0 years


$497 million


5.1 years

Alberta Viking




6.4 years


$20 million


1.5 years

Peace River




6.1 years


$19 million


1.5 years

 

Our 2017 total capital budget remains unchanged at $180 million from our previous announcement. Our capital program is focused on (i) Building a Cardium Waterflood Platform, (ii) Manufacturing Cold Flow in Peace River, (iii) Leveraging our Infrastructure Advantage in the Alberta Viking, and (iv) Pursuing New Ventures.

Details on expected capital spending allocation are as follows:






Capital Category


Number of Wells


Net Capital

Cardium Waterflood Platform


10 Producers, 45 Injectors


$97 million

Manufacture Cold Flow


24 Producers


$8 million

Optimize Volumes with Viking


11 Producers


$15 million

Pursue New Ventures


7 Producers


$15 million

Total Development


52 Producers, 45 Injectors


$135 million

Base Capital




$25 million

Total E&D Capital Expenditures




$160 million






Decommissioning Expenditures




$20 million

 

For more information on our 2017 capital program, please see our January 5, 2017 press release, http://pennwest.mediaroom.com/index.php?s=27585&item=135287.

Building a Cardium Waterflood Platform

Our strategy in the Cardium is based on integrated waterflood development in Pembina and Willesden Green, combining new horizontal producers with simultaneous vertical injection drilling to support reserve development and arrest base decline.

Our main focus in Pembina in 2017 will be in PCU#9, where we will drill three vertical injection wells to support an existing producing well in the first quarter. After breakup, we plan to drill an additional 3 horizontal wells plus 15 injection wells. We are also working with our partners in PCU#11 on preparing for our second half development program.

In 2016, in the J-Lease area of Pembina, we fracture-stimulated the two horizontal wells drilled in late September using a cemented liner system, and brought the wells on production in November. This year, we plan to focus on waterflood optimization opportunities in J-Lease, including converting several producing wells to injection. We are already seeing waterflood response in several areas based on earlier horizontal injector conversions.

In 2016, in the Crimson area of Willesden Green, we drilled the second and third horizontal wells of our three well development program in early October and completed all three wells in November. The wells were brought on production in early January and are performing in line with expectations. This year, we expect to drill 15 vertical injection wells prior to breakup and six injection wells in the second half of the year.

We are currently optimizing and upgrading some of our water injection infrastructure projects in preparation for our development program in the second half of the year.

Manufacturing Cold Flow in Peace River

This year, we will increase the development pace in the Peace River area with a 24 well program. We are currently carried on 90% of our capital and operating commitments through our joint venture partner, and we forecast the carry to finish by the end of 2017.

In 2016, in the Peace River area, we drilled and rig released the remaining 15 wells of our 19 well second half program in the fourth quarter. Through simultaneous drilling and facility build operations, we were able to reduce per well costs to $2.4 million, approximately 15% below budget.

In the first quarter 2017 we drilled 3 wells and brought on production 4 additional wells. We are currently running two rigs in the area and plan to bring on production an additional 8 wells during the third quarter.

Leveraging our Infrastructure Advantage in the Alberta Viking

In 2016, in the Alberta Viking, we brought 9 wells on production in the fourth quarter and 2 wells on production in the first quarter of 2017. These wells continue to perform ahead of expectations with average per well production rates, including oil rates, approximately 25% ahead of the average industry type curve in the play. We believe the success of these wells can be attributed to the novel approach, including energized fracs, we are taking with our completions in the area.

In the second half of the year, we have budgeted to drill 7 wells in the area. We are currently working on a small debottlenecking project in the area, which will allow us to expand the gas plant capacity at two of our gas plants.

Pursuing New Ventures

We have approximately 700 net sections of secondary rights in our portfolio. In the second half of the year, we have plans to expand our reach by testing the deeper hydrocarbon formations below our Cardium rights, primarily in the Mannville. We are encouraged by offsetting industry activity, showing the potential for high production rates and liquid yields in the 30-40 bbls/mmscf. We have budgeted to drill 3 Mannville wells, our first operated development into the multi-horizon potential across the Cardium area acreage, and are partnered on an additional 4 Mannville wells.

We are currently evaluating whether to reallocate some of the Mannville capital in the second half of the year elsewhere in the portfolio due to the recent fall in natural gas prices. We will continue to monitor our opportunities and commodity prices over spring breakup.

Hitting the Ground Running: Updated 2017 Guidance

Earlier this year, we re-evaluated a portion of our acreage in the outer Cardium and central Alberta that we originally planned to sell. These assets have meaningful deeper mineral rights in the Mannville that we intend to further evaluate in the near future. We decided to retain these assets and sell a portion of our freehold and gross overriding royalties for approximately equal proceeds. As a result, retained production in our key development areas in the fourth quarter of 2016 increased by approximately 3,500 boe per day to 28,655 boe per day.

We are increasing full year 2017 average production guidance to 30,500 – 31,500 boe per day, and remain confident in our ability to generate double-digit organic production growth from the fourth quarter of 2016 to the fourth quarter of 2017. We anticipate our 2017 capital program will be paid for fully with Funds Flow from Operations.

Updated Hedging Position

Our hedging program helps reduce the volatility of our Funds Flow from Operations, and thereby improves our ability to manage our ongoing capital programs. We target having hedges in place for approximately 25 percent to 50 percent of our crude oil exposure, net of royalties, and 20 percent to 50 percent of our gas exposure, net of royalties.

Our positions as of March 14, 2017 are as follows:











Q1 2017

Q2 2017

Q3 2017

Q4 2017

H1 2018

H2 2018

Oil Volume (bbl/d)


8,600

7,800

7,400

7,900

1,000

1,000

C$ WTI Price (C$/bbl)


$67.67

$66.42

$66.42

$66.70

$71.00

$71.00

US$ WTI Price (US$/bbl) (1)


US$50.40

US$50.22

US$50.21

US$50.42

US$52.88

US$52.88

Gas Volume (mcf/d)


20,900

19,000

17,100

15,200

5,700

3,800

AECO Price (C$/mcf)


$3.04

$2.81

$2.83

$3.03

$2.87

$2.89

(1)

US$ price implied using foreign exchange rates as at December 31, 2016

 

Senior Management Changes

We are pleased to announce that Mr. Andrew Sweerts, Penn West's Vice President of Business Development & Commercial, has assumed the position of Vice President of Production & Technical Services. Mr. Sweerts has 25 years of experience in leading asset & divestment and trading activities, directing projects and overseeing joint venture partnerships.

Replacing Mr. Sweerts as Vice President of Business Development and Commercial is Mr. Mark Hodgson. Mr. Hodgson brings over 16 years of experience in the industry most recently leading Bankers Petroleum Ltd. technical and commercial expansion efforts in Eastern Europe. Prior to New Ventures, Mr. Hodgson held positions managing service functions of Legal, Crude Marketing, Stakeholder Engagement, Supply Chain, Investor Relations, and Corporate Planning at various entities.

Conference Call Details

A conference call will be held to discuss the matters noted above at 6:30 am Mountain Time (8:30 am Eastern Time) on Wednesday, March 15, 2017.

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (toll-free). This call will be broadcast live on the Internet and may be accessed directly at the following URL:

http://event.on24.com/r.htm?e=1377599&s=1&k=4D74121AA7ACC2AF4E82852217FE413B

A digital recording will be available for replay two hours after the call's completion, and will remain available until March 29, 2017 21:59 Mountain Time (23:59 Eastern Time). To listen to the replay, please dial 416-849-0833 or 1-855-859-2056 (toll-free) and enter Conference ID 77593566, followed by the pound (#) key.

An updated corporate presentation, the year ended 2016 management's discussion and analysis and the audited consolidated financial statements are available on the Company's website at www.pennwest.com. Additionally, the year ended 2016 management's discussion and analysis and the audited consolidated financial statements will be posted on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.

Summary of Reserves

In 2016, we engaged Sproule Associates Limited ("Sproule"), an independent, qualified engineering firm, to evaluate one hundred percent of our proved and proved plus probable reserves.  Sproule conducted an independent reserves evaluation of Penn West's reserves effective December 31, 2016.  This evaluation was prepared in accordance with definitions, standards, and procedures set out in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101").  The Sproule reserves evaluation was based on Sproule's December 31, 2016 product price forecast.

Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserves estimate. The reserves estimates set forth below are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The Summary of Reserves tables below are based on Sproule's evaluation at December 31, 2016 using Sproule's December 31, 2016 product price forecast. All reserve volumes are company gross unless otherwise noted.

Total Company Gross (WI) Reserves

As at December 31, 2016







Reserve


Light &
Medium
Crude Oil

Heavy
Crude Oil
& Bitumen

Natural
Gas
Liquids

Conventional
Natural Gas

Barrel of Oil
Equivalent

Estimates Category (1)(2)


(mmbbl)

(mmbbl)

(mmbbl)

(bcf)

(mmboe)

Proved







Developed producing


41

8

6

236

94

Developed non-producing


2

0

1

19

6

Undeveloped


10

2

1

23

17

Total Proved


54

10

7

278

117

Probable


21

5

3

97

44

Total Proved plus Probable


75

14

10

374

161

(1)

Company gross (WI) reserves are before royalty burdens and exclude royalty interests.

(2)

Columns and rows may not add due to rounding.

 

Total Company Net after Royalty Interest Reserves

As at December 31, 2016







Reserve


Light &
Medium
Crude Oil

Heavy
Crude Oil
& Bitumen

Natural
Gas
Liquids

Conventional
Natural Gas

Barrel of Oil
Equivalent

Estimates Category (1)(2)


(mmbbl)

(mmbbl)

(mmbbl)

(bcf)

(mmboe)

Proved







Developed producing


38

7

5

209

84

Developed non-producing


2

0

1

16

5

Undeveloped


9

2

1

21

15

Total Proved


49

9

6

246

105

Probable


19

4

2

87

39

Total Proved plus Probable


68

12

8

333

144

(1)

Net after royalty reserves are working interest reserves including royalty interests and deducting royalty burdens.

(2)

Columns and rows may not add due to rounding.

 

Additional reserve disclosures, as required under NI 51-101, will be contained in our Annual Information Form that will be filed on SEDAR at www.sedar.com.

Reconciliation of Company Gross (WI) Reserve



Light &
Medium
Crude Oil

Heavy
Crude Oil
& Bitumen

Natural Gas
Liquids

Conventional
Natural Gas

Barrel of Oil
Equivalent

Reconciliation Category (1)


(mmbbl)

(mmbbl)

(mmbbl)

(bcf)

(mmboe)

Total Proved







December 31, 2015


104

33

12

353

208

Extensions


0

0

0

0

0

Infill Drilling


0

2

0

1

2

Improved Recovery


0

0

(0)

(1)

(0)

Technical Revisions


1

1

0

34

7

Acquisitions


0

0

0

23

4

Dispositions


(42)

(23)

(3)

(77)

(81)

Economic Factors


(2)

(0)

(0)

(11)

(5)

Production


(8)

(3)

(1)

(44)

(20)

December 31, 2016


54

10

7

278

117

(1)

Columns and rows may not add due to rounding.

 



Light &
Medium
Crude Oil

Heavy
Crude Oil
& Bitumen

Natural Gas
Liquids

Conventional
Natural Gas

Barrel of Oil
Equivalent

Reconciliation Category (1)


(mmbbl)

(mmbbl)

(mmbbl)

(bcf)

(mmboe)

Proved Plus Probable







December 31, 2015


141

70

16

473

306

Extensions


0

1

0

0

1

Infill Drilling


0

3

0

1

3

Improved Recovery


2

0

0

1

2

Technical Revisions


(2)

(28)

0

29

(25)

Acquisitions


0

0

0

31

5

Dispositions


(57)

(28)

(5)

(103)

(107)

Economic Factors


(2)

(0)

(0)

(14)

(5)

Production


(8)

(3)

(1)

(44)

(20)

December 31, 2016


75

14

10

374

161

(1)

Columns and rows may not add due to rounding.

 

Summary of Before Tax Net Present Values

As at December 31, 2016








Net Present Value








$ millions (1)



Undiscounted

5%

10%

15%

20%

Proved








Developed producing


$

2,629

1,811

1,396

1,148

983

Developed non-producing



105

82

67

55

47

Undeveloped



410

181

74

18

(14)

Total Proved



3,143

2,075

1,537

1,221

1,015

Probable



1,462

680

385

245

167

Total Proved plus Probable


$

4,605

2,755

1,922

1,466

1,182

(1)

Columns and rows may not add due to rounding.

 

Net present values take into account wellbore abandonment and reclamation liabilities on reserve wells and are based on the price assumptions that are contained in the following table. It should not be assumed that the estimated future net revenues represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.

Summary of Pricing and Inflation Rate Assumptions




Canadian







WTI

Light Sweet

Natural Gas





Cushing,

Crude

AECO-C

Exchange

As at December 31 (1)


Oklahoma

40° API

Spot

Rate

Sproule Forecast


($US/bbl)

($Cdn/bbl)

($Cdn/MMbtu)

($US/$Cdn)











Year


2016

2015

2016

2015

2016

2015

2016

2015

Historical










2012


94.19

94.19

86.57

86.57

2.43

2.43

1.00

1.00

2013


97.98

97.98

93.27

93.27

3.13

3.13

0.97

0.97

2014


93.00

93.00

93.99

93.99

4.50

4.50

0.91

0.91

2015


48.80

48.80

57.45

57.45

2.70

2.70

0.78

0.78

2016(2)


43.32

45.00

52.80

55.20

2.18

2.25

0.76

0.75











Forecast










2017


55.00

60.00

65.58

69.00

3.44

2.95

0.78

0.80

2018


65.00

70.00

74.51

78.43

3.27

3.42

0.82

0.83

2019


70.00

80.00

78.24

89.41

3.22

3.91

0.85

0.85

2020


71.40

81.20

80.64

91.71

3.91

4.20

0.85

0.85

2021


72.83

82.42

82.25

93.08

4.00

4.28

0.85

0.85

2022


74.28

83.65

83.90

94.48

4.10

4.35

0.85

0.85

2023


75.77

84.91

85.58

95.90

4.19

4.43

0.85

0.85

2024


77.29

86.18

87.29

97.34

4.29

4.51

0.85

0.85

2025


78.83

87.48

89.03

98.80

4.40

4.59

0.85

0.85

2026


80.41

88.79

90.81

100.28

4.50

4.67

0.85

0.85

2027


82.02

n.a.

92.63

n.a.

4.61

n.a.

0.85

n.a.

(1)

Costs & Prices escalated at 2.0% after 2027.

(2)

2016 Pricing was forecast at the time of the December 31, 2015 reserves report based on Sproule pricing.

 

Future Development Capital

As at December 31, 2016






Future Development Capital






$ millions (1)



Total Proved


Total Proved plus
Probable

2017


$

43


86

2018



136


154

2019



113


160

2020



87


202

2021



32


79

2022 and subsequent



5


7

Total, Undiscounted


$

417


689

Total, Discounted @ 10%


$

336


544

(1)  Rows may not add due to rounding












As at December 31, 2015






Future Development Capital






$ millions (1)



Total Proved


Total Proved plus
Probable

Total, Undiscounted


$

692


1,528

Total, Discounted @ 10%


$

526


1,099

 

Additional Reader Advisories

Oil and Gas Information Advisory
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value. 

Non-GAAP Measures

Certain financial measures including Funds Flow from Operations, Funds Flow from Operations per share-basic, Funds Flow from Operations per share-diluted, netback, EBITDA and gross revenues included in this press release do not have a standardized meaning prescribed by IFRS and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. Funds Flow from Operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and office lease settlements which also excludes the effects of financing related transactions from foreign exchange contracts and debt repayments/ pre-payments and is representative of cash related to continuing operations. Funds Flow from Operations is used to assess the Company's ability to fund its planned capital programs. See "Calculation of Funds Flow from Operations" below for a reconciliation of Funds Flow from Operations to its nearest measure prescribed by IFRS. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. See "Results of Operations – Netbacks" above for a calculation of the Company's netbacks. EBITDA is cash flow from operations excluding the impact of changes in non-cash working capital, decommissioning expenditures, financing expenses, realized gains and losses on foreign exchange hedges on prepayments, realized foreign exchange gains and losses on debt prepayments and restructuring expenses. EBITDA as defined by Penn West's debt agreements excludes the EBITDA contribution from assets sold in the prior 12 months and is used within Penn West's covenant calculations related to its syndicated bank facility and senior notes. Gross revenue is total revenues including realized risk management gains and losses on commodity contracts and is used to assess the cash realizations on commodity sales

Calculation of Funds Flow from Operations



Year ended December 31

(millions, except per share amounts) (1)



2016



2015

Cash flow from operating activities


$

(137)


$

175

Change in non-cash working capital



97



(31)

Decommissioning expenditures



11



36

Office lease settlements



4



-

Monetization of foreign exchange contracts



(32)



(95)

Settlements of normal course foreign exchange contracts



(3)



(40)

Monetization of transportation commitment



(20)



-

Realized foreign exchange loss – debt prepayments



191



123

Realized foreign exchange loss – debt maturities



37



36

Carried operating expenses (2)



15



12

Restructuring charges



19



33

Funds flow from operations


$

182


$

249








Per share – funds flow from operations








Basic per share


$

0.36


$

0.50


Diluted per share                                        


$

0.36


$

0.50

(1)

Certain comparative figures have been reclassified to correspond with current period presentation.

(2)

The effect of carried operating expenses from the Company's partner under the Peace River Oil Partnership.

 

Forward-Looking Statements
Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "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 be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our capital spending plans in 2017 and the associated funding of that spending, when we expect the carry from our joint venture partner in Peace River to expire, our updated expected full year production range, our expected production growth rate, our expected approach to development including the area-specific asset development plans described herein, the timing of development activities, the timing of pending and anticipated asset dispositions and the associated proceeds, our expectations for the ARO and the number of wellbores and associated environment liabilities going forward, our expectations for the LMR by the end of 2017, the changes expected in our reserves once certain things are recognized, that we are working on a project in the Alberta Viking to allow us to expand the gas plant capacity at our two gas plants, that we are evaluating whether or not to reallocate some of the capital spend based on continuing to monitor our opportunities and commodity prices over spring break-up, and our targeted hedging program. 

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: 2017 prices of US$54.07 per barrel of West Texas Intermediate light sweet oil and C$3.32 per mcf AECO gas, and a C$/US$ foreign exchange rate of $1.32; the terms and timing of asset sales to be completed; that we do not dispose of any material producing properties; our ability to execute our long-term plan as described herein and in our other disclosure documents and the impact that the successful execution of such plan will have on our Company and our shareholders; that the current commodity price and foreign exchange environment will continue or improve; future capital expenditure levels; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future crude oil, natural gas liquids and natural gas production levels; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior unsecured notes on maturity; and our ability to add production and reserves through our development and exploitation activities.

Although we believe that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the possibility that we will not be able to continue to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to our Company and our securityholders as a result of the successful execution of such plans do not materialize; the possibility that we are unable to execute some or all of our ongoing asset disposition program on favourable terms or at all; the possibility that we breach one or more of the financial covenants pursuant to our amending agreements with the syndicated banks and the holders of our senior, unsecured notes; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); and the other factors described under "Risk Factors" in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

SOURCE Penn West

For further information: PENN WEST: Penn West Plaza, Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3, Phone: 403-777-2500, Fax: 403-777-2699, Toll Free: 1-866-693-2707, Website: www.pennwest.com; Investor Relations: Toll Free: 1-888-770-2633, E-mail: investor_relations@pennwest.com

 
loading