CALGARY, March 15, 2017 /PRNewswire/ - 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