CALGARY, Alberta, May 09, 2018 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or the
“Company”) is pleased to provide its 2018 first quarter results and an operations update.
The quarter marks continued operational success across both business units. Athabasca is uniquely positioned as
a low-decline, oil-weighted producer with assets in the best plays in Western Canada (Montney, Duvernay and oil sands). The
Company’s focus remains on margin growth and financial sustainability.
Recent Operations Highlights and Q1 Results
Light Oil – High Margin Liquids Rich Growth
- Q1 production of 10,495 boe/d (50% liquids), representing 207% growth year over year
- Top decile operating netbacks of $25.75/boe and $24.3 million operating income
- Placid Montney: multi-well pad on stream in March and additional 6 well pad rig released in May
- Kaybob Duvernay: strong well results with the latest five IP30s averaging ~1,000 boe/d (>70% liquids)
Thermal Oil – Low Decline Production
- Q1 production of 30,077 bbl/d, representing 29% growth year over year
- Operating income of ($6.7) million impacted by short term volatility of heavy oil differentials, product basis spreads and
seasonality in blend ratios
- Norlite diluent line expected on-stream in Q2 with anticipated annual savings of $20 million at Leismer
- Four infill wells ready for production in Q3 at Leismer
Consolidated – Strength in Execution and Financial Sustainability
- Consolidated production of 40,572 boe/d (87% liquids), representing 52% growth year over year
- Capital spend of $57 million with funding capacity of approximately $330 million
- Operating income of $16.9 million with adjusted funds flow of ($6.4) million or ($0.01) per share
2018 Outlook
Athabasca’s 2018 operational outlook is unchanged with a $140 million capital budget and production guidance of
38,500 – 41,000 boe/d (87% liquids). Annual funds flow guidance has been increased to $145 million (from $125 million) on stronger
underlying commodity prices which are closely aligned to strip prices (US$65 WTI and US$20 Western Canadian Select “WCS” heavy
differential).
Canadian producers were faced with unprecedented volatility in Canadian heavy oil differentials and basis
spreads in early 2018 due to pipeline capacity constraints which impacted short term profitability and financial results. WCS
differentials peaked in excess of US$30 in Q1 2018, averaging 67% (~US$10) higher than Q1 2017. Since Q1 2018, WCS pricing has
improved considerably, with strip prices tightening to approximately US$20 for the balance of the year. The global outlook for
crude oil also continues to strengthen, supporting Athabasca’s oil-weighted portfolio. Adjusting for this macro volatility the
Company estimates that it would have realized an incremental $38 million in Thermal Oil operating income in Q1 2018 assuming a
US$5/bbl improvement in WCS differentials and normalized basis spreads.
Athabasca’s outlook and financial sustainability are underpinned by high margin Light Oil growth, low break-even
costs at Leismer, strong capital discipline, and an active commodity hedging program targeting up to 50% of near term production.
Athabasca has secured long term egress to multiple end markets with capacity on the Kinder Morgan Trans Mountain Expansion Project
and TransCanada Keystone XL.
Athabasca provides investors excellent exposure to improving oil prices with low total leverage with estimated
unhedged funds flow sensitivity of ~$80 million for each incremental US$5/bbl increase in WTI. The Company is a net consumer of gas
and is a beneficiary of the current low Alberta gas pricing environment.
Midstream Process
Athabasca is exploring monetization options of its extensive Thermal Oil infrastructure. The Company believes
that current timing is favorable following the integration of Leismer and strong market precedent transactions. A process is
underway to explore a wide range of alternatives for this infrastructure which could include a sale, partnership or joint venture.
The infrastructure will remain a strategic asset for future growth initiatives at Leismer and Corner.
The Company maintains flexibility for use of potential proceeds which could include bolstering liquidity and/or
debt reduction, investing in projects across its asset base that will generate attractive returns for shareholders, and initiating
a share buyback program.
Athabasca’s Strategy
Athabasca is an intermediate producer with strong and competitive investment opportunities across its portfolio
in the current operating environment. The Company has tremendous leverage to oil prices and is focused on maximizing profitability
through measured activity in Light Oil and ongoing Thermal Oil optimization. The strategy is guided by:
- Light Oil (Montney and Duvernay): Defined and Material Margin Growth
- Thermal Oil: Low Decline, Long-Life, Free Cash Flow Generating Assets
- Financial Sustainability: Increasing Margins, Flexible Capital, Strong
Liquidity
The Company’s strategy is intended to ensure both its Light Oil and Thermal Oil businesses are financially
robust and competitive, with exceptional growth potential. The Company will continue its strategic emphasis on generating strong
oil-weighted margins and significant free cash flow to maximize shareholder returns and provide strategic optionality into the
future.
Financial and Operational Highlights
|
|
3 Months ended March
31 |
|
($ Thousands, unless otherwise noted) |
2018 |
|
2017 |
|
CONSOLIDATED |
|
|
|
|
Petroleum and Natural Gas Volumes (boe/d) |
|
40,572 |
|
|
26,737 |
|
Operating Income1,2 |
$ |
16,876 |
|
$ |
19,204 |
|
Operating Netback1,2 ($/boe) |
$ |
4.65 |
|
$ |
7.99 |
|
Capital Expenditures3 |
$ |
82,261 |
|
$ |
90,124 |
|
Capital Expenditures Net of
Capital-Carry1,3 |
$ |
56,661 |
|
$ |
79,444 |
|
|
|
|
|
|
LIGHT OIL DIVISION |
|
|
|
|
Oil, Condensate and NGLs (bbl/d) |
|
5,243 |
|
|
1,961 |
|
Gas (mcf/d) |
|
31,511 |
|
|
8,760 |
|
Petroleum and Natural Gas Volumes (boe/d) |
|
10,495 |
|
|
3,421 |
|
Operating Income1 |
$ |
24,292 |
|
$ |
6,863 |
|
Operating Netback1 ($/boe) |
$ |
25.72 |
|
$ |
22.28 |
|
Capital Expenditures3 |
$ |
66,630 |
|
$ |
77,646 |
|
Capital Expenditures Net of
Capital-Carry1,3 |
$ |
41,030 |
|
$ |
66,966 |
|
|
|
|
|
|
THERMAL OIL DIVISION |
|
|
|
|
Bitumen Production (bbl/d) |
|
30,077 |
|
|
23,316 |
|
Operating Income / (Loss)1 |
$ |
(6,744 |
) |
$ |
10,050 |
|
Operating Netback1 ($/bbl) |
$ |
(2.51 |
) |
$ |
4.80 |
|
Capital
Expenditures3 |
$ |
15,631 |
|
$ |
10,868 |
|
|
|
|
|
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
Cash Flow from Operating Activities |
$ |
(3,241 |
) |
$ |
(52,896 |
) |
per share (basic) |
$ |
(0.01 |
) |
$ |
(0.11 |
) |
Adjusted Funds Flow1 |
$ |
(6,360 |
) |
$ |
(1,649 |
) |
per share (basic) |
$ |
(0.01 |
) |
$ |
- |
|
|
|
|
|
|
NET LOSS AND COMPREHENSIVE LOSS |
|
|
|
|
Net Loss and Comprehensive Loss |
$ |
(93,330 |
) |
$ |
(29,162 |
) |
per share (basic and diluted) |
$ |
(0.18 |
) |
$ |
(0.06 |
) |
|
|
|
|
|
COMMON SHARES OUTSTANDING |
|
|
|
|
Weighted Average Shares Outstanding (basic and diluted) |
510,191,864 |
|
472,157,006 |
|
|
|
|
|
|
As at ($
Thousands) |
|
March 31,
2018 |
|
|
|
Dec. 31
2017 |
|
LIQUIDITY AND INDEBTEDNESS |
|
|
|
|
Cash and Cash Equivalents |
$ |
128,915 |
|
$ |
163,321 |
|
Restricted Cash |
$ |
111,778 |
|
$ |
113,406 |
|
Capital-Carry Receivable (current & LT portion
undiscounted) |
$ |
138,423 |
|
$ |
164,023 |
|
Face Value of Long-term
Debt4 |
$ |
580,545 |
|
$ |
563,310 |
|
1) Refer to "Advisories and Other Guidance" in the MD&A for additional information on Non-GAAP Financial
Measures.
2) Includes realized gain (loss) on commodity risk management contracts.
3) Capital expenditures include capitalized G&A.
4) The face value of the US dollar denominated 2022 Notes is US$450 million. As at March 31, 2018, the 2022 Notes were translated
into Canadian dollars at the period end exchange rate of US$1.00=C$1.2901.
Operations Update
Light Oil
Q1 2018 production averaged 10,495 boe/d (50% liquids), representing 207% growth year over year. Light Oil
operating income was $24.3 million with a netback of $25.72/boe, supported by a high liquids weighting and low operating costs of
$8.88/boe. Athabasca’s Light Oil business unit has top decile netbacks when compared to Alberta’s other liquids-rich resource
producers. The Company spent $41 million in Montney and Duvernay programs (net of capital carry) during the quarter.
The Company forecasts 2018 Light Oil operating income of $125 million and free cash flow of $55 million (US$65
WTI and C$1.50 AECO). The $70 million capital program includes $40 million for Placid Montney and $387 million ($30 million net)
for Kaybob Duvernay. Second half activity levels in the Montney will be assessed mid-year.
Greater Placid Montney (Athabasca operated, 70% working interest)
Q1 2018 production from Placid averaged 8,213 boe/d (46% liquids). Volumes were impacted temporarily as a result
of shut-in production for offsetting completion activities.
In March, the Company placed the 7-30 pad on production (surface location 07-30-60-23W5 Pod 2). Initial
production from the pad has been temporarily restricted as facilities are at maximum liquids handing capacity. These restrictions
are expected to be resolved in the second half of 2018. Restricted IP30 rates for the pad have averaged 822 boe/d (61%
liquids). An additional Montney six well development pad (surface location 12-19-60-23W5 Pod 3) spud in December and was rig
released in early May. The Company maintains operational readiness for completions following spring breakup.
Placid Program |
|
IP301 |
IP901 |
IP1801 |
Pad Surface Location |
On-stream Date |
boe/d |
% liquids |
boe/d |
% liquids |
boe/d |
% liquids |
07-30-60-23W5 |
December 2016 |
813 |
70 |
% |
690 |
67 |
% |
657 |
61 |
% |
12-19-60-23W5 (Pod 2)2 |
April 2017 |
821 |
51 |
% |
670 |
61 |
% |
705 |
55 |
% |
16-30-60-23W52 |
April 2017 |
1,053 |
50 |
% |
798 |
58 |
% |
824 |
52 |
% |
03-04-61-23W5 |
September 2017 |
1,206 |
66 |
% |
1,067 |
57 |
% |
929 |
52 |
% |
07-33-60-20W5 (Pod 2) |
November 2017 |
1,010 |
57 |
% |
1,023 |
49 |
% |
916 |
44 |
% |
07-30-60-23W5 (Pod 2)3 |
March 2018 |
822 |
61 |
% |
- |
- |
|
- |
- |
|
1) IPs reflect sales gas, free condensate and estimated plant based NGL recovery.
2) Peak 30 day rates reported on Pad 12-19 & 16-30 as the initial rates were temporarily restricted by spring road bans and the
16-day Keyera unplanned outage in April 2017.
3) Restricted 30 day rates reported due to facilities being temporarily at maximum liquids handling capacity.
Greater Kaybob Duvernay (Murphy operated, 30% working interest)
A robust drilling program is underway in the Duvernay with two to three rigs expected to remain active for the
balance of 2018. Activity levels were accelerated during the quarter with a jointly approved annual budget of C$387 million (~$30
million net). Operations are focused on development drilling at Kaybob West and ongoing volatile oil delineation across the
extensive acreage positon. The budget includes releasing 26 wells, completion operations on 29 wells and placing 28 wells on
production. The Duvernay is expected to contribute strong production and cash flow growth into year-end.
Duvernay Program |
|
|
IP301 |
Area |
UWI or Pad Surface Location |
On-stream Date / Status |
boe/d |
% liquids |
Kaybob West Volatile Oil |
100/05-09-065-20W52 |
November 2017 |
IP30 468
IP150 450 |
100 |
% |
|
4 well pad (06-33-64-20W5) |
Rig Released |
- |
- |
|
|
3 well pad (16-18-065-20W5) |
Rig Released |
- |
- |
|
Simonette Volatile Oil |
02/10-29-63-24W5 |
February 2018 |
745 |
72 |
% |
|
02/06-29-63-24W5 |
February 2018 |
913 |
71 |
% |
Kaybob East Volatile Oil |
14-36-64-19W5 |
March 2018 |
1,178 |
82 |
% |
|
15-36-64-19W5 |
March 2018 |
979 |
81 |
% |
|
2 well pad (16-06-65-18W5) |
Rig Released |
- |
- |
|
Saxon Wet Gas |
02/14-09-62-23W53 |
April 2018 |
IP25 1,525 |
53 |
% |
|
00/14-09-62-23W53 |
April 2018 |
- |
- |
|
|
00/03-16-62-23W53 |
April 2018 |
- |
- |
|
Kaybob West Gas |
5 well pad (11-14-62-20W5) |
Completions Underway |
- |
- |
|
1) IPs reflect sales gas, free condensate and estimated plant based NGL recovery.
2) Facility constrained. 5-9 on production through temporary facilities with gas flared and oil trucked.
3) Restricted IP25 reported. 3 well pad currently being tied into permanent production facilities.
Thermal Oil
Q1 2018 production averaged 30,077 bbl/d, representing 29% growth year over year. Growth was driven by the
Leismer acquisition effective January 31, 2017 and the continued ramp-up at Hangingstone. Q1 2018 capital expenditures were $15.6
million.
Thermal Oil generated a Q1 operating income of ($6.7) million ($4.9 million operating income for Leismer and
($11.6) million for Hangingstone).
Financial results were adversely impacted by significant volatility in the macro environment and business
seasonality.
WCS differentials averaged at US$24.32 during Q1 2018 and peaked in excess of US$30. Product basis spreads which
reflect quality differentials and apportionment were also volatile. Athabasca’s dilbit sales received a C$6.62 discount to the WCS
benchmark, compared to C$3.88 in the Q4 2017. Since Q1, Athabasca has seen marked improvement on both fronts with WCS pricing
tightening to approximately US$20/bbl for the balance of the year.
Adjusting for the macro volatility the Company estimates that it would have realized an incremental $38 million
in Thermal Oil operating income in Q1 for a US$5/bbl improvement in WCS differentials and normalized basis spreads.
Thermal operations have seasonality with respect to condensate blending. Blend ratios in winter months increase
up to approximately 47% and in the summer months decline to approximately 40% (example: 1 barrel of bitumen + 0.40 barrel of
condensate). Athabasca will complete the Norlite diluent tie-in at the end of May, which is expected to lower annual fixed costs by
approximately $20 million, further enhancing Leismer’s low cost operating structure.
With the strength in oil prices and improved differential outlook the Company now forecasts 2018 Thermal Oil
operating income of $130 million (up from $100 million) with free cash flow of $60 million (US$65 WTI and US$20 WCS
differential).
Leismer
Leismer production averaged 21,021 bbl/d in Q1 2018. Athabasca remains focused on reservoir management to
maximize profitability while managing production between 20,000 – 22,000 bbl/d. The Company intends to tie-in four pre-drilled
infill wells on Pad L5 in the second half of 2018 to maintain production. A scheduled turnaround commenced in late April and is
expected to be completed in May. The Company estimates that the turnaround will impact annual average volumes by approximately
1,000 bbl/d. The Norlite diluent tie-in will be operational at the end of May.
Hangingstone
Hangingstone production averaged 9,056 bbl/d in Q1 2018 with facility maintenance impacting volumes for the
quarter. 2018 operations are focused on cost optimization and the start-up of a standing pre-drilled well pair. Hangingstone
production is expected to continue to increase with steam chamber growth and minimal capital is forecasted over the next several
years.
2018 Guidance
Athabasca’s 2018 operations outlook is unchanged with a $140 million capital budget and production guidance of
38,500 – 41,000 boe/d (87% liquids). Annual funds flow guidance has been increased to $145 million (from $125 million) on stronger
underlying commodity prices which are aligned to strip prices.
The Company maintains a strong financial position with funding capacity of approximately $330 million, including
cash, available credit facilities and the Duvernay capital carry balance.
2018
Guidance |
Full Year |
CORPORATE (net) |
|
Production (boe/d) |
38,500 – 41,000 |
Liquids Weighting (%) |
~87% |
Adjusted Funds Flow ($MM) |
$145 |
Operating Income ($MM) |
$255 |
|
|
LIGHT OIL (net) |
|
Production (boe/d) |
10,500 – 11,500 |
Operating Income ($MM) |
$125 |
Capital Expenditures ($MM) |
$70 |
|
|
THERMAL OIL |
|
Bitumen Production (bbl/d) |
28,000 – 29,500 |
Operating Income ($MM) |
$130 |
Capital Expenditures ($MM) |
$70 |
|
|
|
|
COMMODITY ASSUMPTIONS |
|
WTI (US$/bbl) |
$65.00 |
WCS Differential (US$/bbl) |
$20.00 |
AECO Gas (C$/mcf) |
$1.50 |
FX (US$/C$) |
|
0.77 |
Board Renewal Update
Athabasca is pleased to announce the appointment of Mr. Tom Ebbern as an independent director to the Board. Tom
has a diverse background in Canadian energy and capital markets.
Tom is currently the Chief Financial Officer of Northwest Refining, a private Alberta based Company that is a
50% partner with Canadian Natural Resources in the Sturgeon Refinery which is in the process of commissioning. Prior thereto Tom
was Managing Director of Energy Investment Banking for Macquarie Capital Markets Canada and previously was a senior partner in
Tristone Capital. Tom’s oil and gas experience also includes prior roles in upstream exploration, business development, gas
marketing and energy infrastructure development.
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and
light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of
extensive, high quality resources. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit
www.atha.com.
For more information, please contact:
Matthew Taylor
Vice President, Capital Markets and
Communications
1-403-817-9104
mtaylor@atha.com
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other
factors. All information other than statements of historical fact is forward-looking information. The use of any of the words
“anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “believe”, “view”, ”contemplate”, “target”,
“potential” and similar expressions are intended to identify forward-looking information. The forward-looking information is not
historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and
projections about the Company’s industry, business and future operating and financial results. This information involves known and
unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated
in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such
forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the
date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to,
the following: the Company’s 2018 guidance and five year outlook; type well economic metrics; estimated recovery factors and
reserve life index; and other matters.
Information relating to "reserves" is also deemed to be forward-looking information, as it involves the implied
assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated
and that the reserves can be profitably produced in the future. With respect to forward-looking information contained in this News
Release, assumptions have been made regarding, among other things: commodity outlook; the regulatory framework in the jurisdictions
in which the Company conducts business; the Company’s financial and operational flexibility; the Company’s, capital expenditure
outlook, financial sustainability and ability to access sources of funding; geological and engineering estimates in respect of
Athabasca’s reserves and resources; and other matters.
Actual results could differ materially from those anticipated in this forward-looking information as a result of
the risk factors set forth in the Company’s Annual Information Form (“AIF”) dated March 7, 2018 available on SEDAR at
www.sedar.com, including, but not limited to: fluctuations in commodity prices, foreign exchange and interest rates; political and
general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty regimes,
environmental risks and hazards; the potential for management estimates and assumptions to be inaccurate; the dependence on Murphy
as the operator of the Company’s Duvernay assets; the capital requirements of Athabasca’s projects and the ability to obtain
financing; operational and business interruption risks; failure by counterparties to make payments or perform their operational or
other obligations to Athabasca in compliance with the terms of contractual arrangements; aboriginal claims; failure to obtain
regulatory approvals or maintain compliance with regulatory requirements; uncertainties inherent in estimating quantities of
reserves and resources; litigation risk; environmental risks and hazards; reliance on third party infrastructure; hedging risks;
insurance risks; claims made in respect of Athabasca’s operations, properties or assets; risks related to Athabasca’s amended
credit facilities and senior secured notes; and risks related to Athabasca’s common shares.
Also included in this press release are estimates of Athabasca's 2018 capital expenditures, adjusted funds flow,
operating netbacks and operating income levels, which are based on the various assumptions as to production levels, commodity
prices and currency exchange rates and other assumptions disclosed in this news release. To the extent any such estimate
constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca on May 9, 2018, and is
included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of
the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such
operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and
operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial
results may vary from the amounts set forth herein, and such variations may be material. The financial outlook contained in this
New Release was made as of the date of this press release and the Company disclaims any intention or obligations to update or
revise such financial outlook, whether as a result of new information, future events or otherwise, unless required pursuant to
applicable law.
Oil and Gas Information
“BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet
of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and
crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1,
utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Initial Production Rates
The initial production rates provided in this News Release should be considered to be preliminary. Initial
production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.
Drilling Locations
The 1,000 Duvernay drilling locations referenced in this news release include: 64 proved undeveloped or
non-producing locations and 35 probable undeveloped locations for a total of 99 undeveloped booked locations with the balance being
unbooked locations. The 200 Montney drilling locations referenced include: 84 proved undeveloped locations with the balance being
unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company's most
recent independent reserves evaluation as prepared by McDaniel as of December 31, 2017 and account for drilling locations that have
associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations
do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by
management as an estimation of Athabasca’s multi-year drilling activities expected to occur over the next two decades based on
evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the
Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in
additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells,
including the number and timing thereof is ultimately dependent upon the availability of funding, oil and natural gas prices,
provincial fiscal and royalty policies, costs, actual drilling results and additional reservoir information that is obtained and
other factors.
Non-GAAP Financial Measures
The "Adjusted Funds Flow”, "Light Oil Operating Income", “Light Oil Operating Netback”, “Light Oil Capital
Expenditures Net of Capital-Carry”, "Thermal Oil Operating Income (Loss)", "Thermal Oil Operating Netback", “Consolidated Operating
Income”, “Consolidated Operating Netback”, and “Consolidated Capital Expenditures Net of Capital-Carry” financial measures
contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be
non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be considered
in isolation with measures that are prepared in accordance with IFRS.
Adjusted Funds Flow is not intended to represent cash flow from operating activities, net earnings or other
measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow measure allows management and others
to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow
internally generated from ongoing operating related activities. Adjusted Funds Flow per share is calculated as Adjusted Funds Flow
divided by the applicable number of weighted average shares outstanding.
The Light Oil Operating Income and Light Oil Operating Netback measures in this News Release are calculated by
subtracting royalties and operating and transportation expenses from petroleum and natural gas sales. The Light Oil Operating
Netback measure is presented on a per boe basis. The Light Oil Operating Income and the Light Oil Operating Netback measures allow
management and others to evaluate the production results from the Company’s Light Oil assets.
The Operating Income (Loss) and Operating Netback measures in this News Release with respect to the Leismer
Project and Hangingstone Project are calculated by subtracting the cost of diluent blending, royalties, operating expenses and
transportation and marketing expenses from blended bitumen sales. The Thermal Oil Operating Netback measure is presented on a per
bbl basis. The Thermal Oil Operating Income (Loss) and the Thermal Oil Operating Netback measures allow management and others to
evaluate the production results from the Company’s Thermal Oil assets.
The Consolidated Operating Income and Consolidated Operating Netback measures in this News Release are
calculated by subtracting realized gains/losses on commodity risk management contracts, royalties, the cost of diluent blending,
operating expenses and transportation and marketing expenses from petroleum and natural gas sales. The Consolidated Operating
Netback measure is presented on a per boe basis. The Consolidated Operating Income and the Consolidated Operating Netback measures
allow management and others to evaluate the production results from the Company’s Light Oil and Thermal Oil assets combined
together including the impact of realized commodity risk management gains or losses.
The Consolidated Capital Expenditures Net of Capital-Carry and Light Oil Capital Expenditures Net of
Capital-Carry measures in this News Release are outlined in the Company’s Q1 2018 MD&A. These measures allow management and
others to evaluate the true net cash outflow related to Athabasca's capital expenditures.