Advantage Announces Record Third Quarter 2018 & Three Year Plan to Accelerate Glacier / Pipestone Area Condensate & Light Oil Growth
CALGARY, Nov. 1, 2018 /CNW/ - Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to announce strong third quarter 2018 results which included record production of 45,611 boe/d (273.7 mmcfe/d), up 29% from the second quarter of 2018 and up 20% from the same period in 2017. Liquids production increased 69% to a record 1,804 bbls/d compared to the second quarter of 2018, up 29% from the same period of 2017. Advantage exited the third quarter of 2018 with liquids production of 2,100 bbls/d which was comprised of approximately 67% condensate ("C5+").
Adjusted funds flow during the quarter was $32 million or $0.17/share supported by realized hedging and marketing diversification gains of $9.5 million and industry leading low total cash costs of $6.12/boe ($1.02/mcfe), down 12% from the first half of 2018. Net capital expenditures of $48.4 million were on-track for the quarter resulting in a total debt to trailing 12 month adjusted funds flow ratio of 1.8 which is estimated to be reduced to 1.6 at year-end 2018 due to surplus cash generated from Glacier operations during the fourth quarter (See Appendix - Third Quarter 2018).
Three Year Development Plan (2019 through 2021)
The Board of Directors of Advantage has approved a three year development plan (the "Plan") including the Corporation's 2019 capital and operating budget. This Plan is expected to be internally funded through redeploying surplus cash generated by our Glacier asset, growing liquids revenue and existing credit facilities. Advantage's Plan is based on current annual average 2019 through 2021 strip prices for natural gas of $1.78/mcf AECO and oil of WTI $65.50 U.S./bbl and the Corporation's hedging and market diversification positions (see summary Plan estimates and assumptions provided in this press release).
Advantage's Plan is strategically designed to:
- Continue strengthening our solid business foundation by increasing our premium C5+ / light oil production mix to further diversify and enhance the Corporation's revenue sources making Advantage even stronger through and beyond 2021
- Preserve balance sheet strength and develop additional operational and infrastructure optionality by optimizing infrastructure investment, leveraging efficiencies in our existing owned process capacity and utilization of third party processing capacity
- Strengthen netbacks while maintaining Advantage's industry leading low cash cost structure
- Increase flexibility to optimize capital allocation by development of Advantage's vast multi-zone liquids potential while retaining torque to its extensive and ultra-low cost natural gas resource
Key Anticipated/Estimated highlights of our Plan are:
- Increases annual liquids production 700% to an exit rate of over 14,000 bbls/d and an annual average of 11,370 bbls/d in 2021 representing over 22% of total production and approximately 60% of total revenue
- Increases premium C5+ / light oil content from currently 67% to 82% of total liquids
- Increases total annual average production by 25% or 8% compound annual growth rate ("CAGR") to 52,300 boe/d (314 mmcfe/d) in 2021 over estimated 2018 annual production
- Further diversifies Advantage's revenue exposure with natural gas accounting for approximately 14% AECO, 13% Dawn and 14% mid-west U.S. by 2021
- Increases adjusted funds flow by 15% to $0.99/share in 2019, 26% to $1.25/share in 2020 and 34% to $1.67/share in 2021 over each prior annual period
- Increases adjusted funds flow per boe by 58% to $16.56/boe ($2.76/mcfe)
- Preserves financial flexibility with year-end total debt to trailing adjusted funds flow ratios of 1.6, 1.2 and 0.6 for 2019, 2020 and 2021, respectively. Significant cash flow growth results in cumulative cash of $735 million as compared to a capital investment of $690 million over the three years
- Maintains Advantage's industry leading low total cash costs averaging $7.92/boe ($1.32/mcfe) over the three years
- Requires only 96 new Montney wells to achieve the objectives of our Plan while retaining a significant high quality inventory of over 1,200 future Montney locations for development beyond 2021
- Enhances operational and financial optionality through utilization of third party processing capacity for our initial Pipestone/Wembley development with options to expand. This efficiently manages infrastructure capital requirements, provides more processing flexibility and accommodates growth from Advantage's other assets and third party processing revenue at our 100% owned Glacier gas plant. The Corporation continues to work on and retains future optionality to construct a Wembley to Glacier pipeline
We look forward to reporting on our progress as we continue development of our world class Montney resource with financially disciplined and full-cycle returns based approach that focuses on per share value generation.
Three Year Development Plan Commentary (2019 through 2021)
Advantage's Plan is anticipated to position the Corporation to capitalize on emerging demand growth with a more diversified revenue base and added flexibility to capture value enhancing opportunities. We believe Canadian condensate market demand will continue to exceed domestic supply growth resulting in strong future pricing. We also believe that Canadian natural gas demand will continue to grow through new domestic power, petro-chemical and industrial gas projects along with increasing export demand in the next 3 to 5 years. Accordingly, the Corporation's Plan to accelerate development of its liquids-rich lands with a specific focus on premium C5+ / light oil while retaining optionality to accelerate development of its ultra-low cost gas resource will create additional capital allocation flexibility.
Advantage's Plan will focus development of its liquids-rich Montney resources at east Glacier, Valhalla, Pipestone/Wembley with additional delineation of the Corporation's land block at Progress. The Plan includes anticipated liquids growth from east Glacier and Valhalla (liquids yields of 50 bbls/mmcf to 100 bbls/mmcf) in 2019 with increasing contribution from our Pipestone/Wembley (>250 bbls/mmcf) land block beginning in the fourth quarter of 2019 and ramping up significantly thereafter.
Existing gas production is expected to modestly decrease over the three year Plan; however, our low cost and lower decline Glacier foundational asset is expected to provide approximately $175 million of free cash flow to re-invest in development of Advantage's liquids potential.
Drilling and Future Inventory
Advantage's total Montney land holdings comprise 200 net sections (128,000 net acres) of prolific gas and liquids-rich drilling opportunities in multiple layers. To date, only 5% of our liquids-rich future well inventory has been drilled. The estimated future drilling inventory within our multi-zone land holdings reinforces the extensive high quality resource development potential that exists today and beyond 2021.
# Estimated Future Drilling Locations(1) |
|
C3+ Shallow Cut Liquids Content |
# Locations |
(approximately 50% to 80% C5%+) |
|
<25 bbls/mmcf |
270 |
25 to 100 bbls/mmcf |
730 |
>100 bbls/mmcf |
200 to 400 |
Total |
1,200 to 1,400 |
Note: (1) Management estimates given consideration to number of Montney layers, well spacing, frac design, regulatory guidelines and production & delineation results. C3+ refers to propane plus butane & condensate. |
The Plan includes drilling 96 new Montney production wells comprised of 42 ultra-rich C5+/light oil wells at Pipestone/Wembley and 54 wells targeting the premium condensate Montney intervals at Valhalla, east Glacier and Progress. The development drilling program at Pipestone/Wembley will commence during the second half of 2019 to support liquids growth targets in 2020 in conjunction with third party processing capacity.
Well costs (drill, complete, equip and tie-in) are estimated to range from $4.9 million to $5.3 million per well dependent on the number of frac stages and length.
Facilities, Processing and Transportation
Processing capacity in the Pipestone Area is currently constrained with one new third party mid-stream facility expected to come on-stream in the second half of 2019. Subsequent new third party mid-stream facilities are expected to be completed by mid-2020 and mid-2021 with additional expansion plans progressing to provide sufficient capacity to match longer term area growth plans.
Advantage has secured and is finalizing additional third party processing arrangements in the Pipestone/Wembley area to accommodate our Plan gas processing volume requirements with options to add additional processing capacity for future development. This allows Advantage to optimize infrastructure investment and accelerate the drilling of liquids-rich wells. This will also allow Advantage more flexibility to utilize the current spare raw gas processing capacity of approximately 120 mmcf/d at our 100% owned Glacier gas plant to accommodate growth from east Glacier and Valhalla and provide additional flexibility to consider third party processing arrangements at Glacier. Advantage will retain the optionality to extend its gathering pipelines from Glacier to Wembley by completing engineering design work and surveying in 2019 but will defer the decision on this investment until a later date.
Liquids growth from Pipestone/Wembley will be handled through a new 100% owned liquids separation/handling facility which will be constructed to an initial design capacity of 5,000 bbls/d with provisions for expansion.
Revenue Diversification and Hedging
During the three years of the Plan, Advantage's liquids production is anticipated to grow to approximately 22% of total production in 2021 (82% C5+) and is expected to provide almost 60% of the Corporation's revenue. At that time, Advantage's natural gas revenue as a percentage of total Corporate revenue is estimated to be comprised of approximately 14% from AECO, 13% Dawn and 14% from the U.S. mid-west markets.
Advantage's hedging positions include an average 75 mmcf/d hedged at an average AECO price of $2.26/mcf for 2019 and 23 mmcf/d hedged at an average Dawn price of U.S. $2.94/mcf for 2019. Included in our 2019 hedging position is 87 mmcf/d hedged at an average AECO price of $2.00/mcf for the summer of 2019 where maintenance restrictions on the NGTL system are expected to occur. The Corporation will continue to participate in hedging both natural gas and liquids prices to reduce cash flow volatility to support future development.
2019 Capital Budget
Advantage's 2019 Capital Budget will focus investment primarily to drilling and completing wells at east Glacier, Valhalla and Pipestone/Wembley to support 2019 production and to provide sufficient well productivity to meet 2020 liquids growth targets.
Capital expenditures in 2019 are targeted at $225 million of which $154 million (68%) will be invested in drilling and completion activity. Infrastructure investment is expected to be $58 million (26%) which includes major gathering system and liquids handling facilities for Pipestone/Wembley and the equipping and tie-in of new wells.
Development Plan Summary Table
Guidance and Estimates |
|||
2019 Guidance(3) |
2020 |
2021 |
|
Average production (Boe/day) |
43,500 to 46,500 |
47,850 |
52,300 |
Gas production (mmcf/d) |
244 to 260 |
245 |
246 |
Liquids production (bbls/d) |
2,900 to 3,200 |
7,000 |
11,370 |
% Liquids / % Condensate/light oil |
7% / 75% |
15% / 80% |
22% / 82% |
Royalty Rate (%) |
4% |
4% |
4.5% |
Royalties ($/boe) |
$0.65 |
$0.90 |
$1.15 |
Operating Cost ($/boe) |
$2.00 |
$2.45 |
$2.65 |
Transportation Cost ($/boe) |
$3.35 |
$3.45 |
$3.40 |
G&A/Finance Cost ($/boe) |
$1.35 |
$1.35 |
$1.25 |
Total Costs ($/boe) |
$7.35 |
$8.15 |
$8.45 |
Net Capital Expenditures (millions)(1) |
$210 to $240 |
225 |
240 |
Capital Efficiency ($/boe/d) |
$14,400 |
$13,700 |
$12,700 |
Adjusted funds flow ($/boe)(1) |
$11.28 |
$13.38 |
$16.56 |
Adjusted funds flow (millions) (1) |
$185 |
$235 |
$315 |
Per share(1) |
$0.99 |
$1.25 |
$1.67 |
Total YE debt / trailing cash flow ratio(1) |
1.6 |
1.2 |
0.6 |
WTI (US$/bbl) (2) |
$66.79 |
$66.37 |
$63.29 |
Advantage C5+/Light oil differential to WTI (CAD$/bbl) (3) |
$(7.00) |
$(6.00) |
$(6.00) |
CAD/USD exchange rate(2) |
$0.77 |
$0.77 |
$0.77 |
AECO (C$/GJ) (2) |
$1.68 |
$1.61 |
$1.78 |
Notes: |
|
1) |
Non-GAAP Measure which may not be comparable to similar non-GAAP measures used by other entities. Please see |
2) |
Based on strip pricing at October 23, 2018. |
3) |
Management estimate. |
4) |
Midpoint management estimate. |
2021 and Beyond
Advantage's land holdings and infrastructure ownership provides a strong foundation to support development of natural gas and liquids for many years beyond 2021. Management estimates the Corporation's high quality land holdings are capable of supporting total production in excess of 120,000 boe/d with liquids production exceeding 30% of total production assuming an approximate 12+ year flat production plateau. The estimated return on average capital employed (ROACE) over a 10 year period is between 10% to 15% based on a flat AECO Cdn $2.00/mcf price and a flat WTI oil price of $U.S. $65.00/bbl. Continued efficiency improvements driven by technology gains and economies of scale could further increase these estimates.
Updated corporate presentation and Sustainability Report have been added to our website. The Corporation's unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2018 together with the notes thereto, and Management's Discussion and Analysis for the three and nine months ended September 30, 2018 have been filed on SEDAR and are available on the Corporation's website.
APPENDIX - Third Quarter 2018
Operations Update
During the third quarter of 2018, Advantage resumed normal operations at our 100% owned Glacier gas plant after successfully completing the construction and commissioning of our major plant expansion project in the second quarter of 2018. The expansion increased the raw gas processing capacity at the Glacier gas plant to 400 mmcf/d and increased shallow cut liquids extraction capacity to 6,800 bbls/d. Current throughput is approximately 285 mmcf/d of raw gas and liquids extraction of approximately 2,100 bbls/d, providing spare capacity to accommodate future growth and third party processing opportunities.
Production from six new liquids-rich Middle Montney wells located in west Glacier continue to outperform and are exceeding our expectations by an average of 100% after 120 days of production.
In east Glacier, seven wells of a 10 well Middle Montney pad have been rig released targeting liquid yields ranging from 50 to 80 bbls/mmcf.
In Valhalla, two liquids-rich well pads at Valhalla consisting of five wells and two wells will commence drilling in the first quarter of 2019 as part of our winter drilling program. These wells will be brought on-production in 2019. Construction has commenced on Advantage's new liquids handling facility which is expected to be completed by year-end 2018. This facility is designed to compress up to 40 mmcf/d of liquids-rich gas production to our Glacier gas plant and will allow the existing and new Valhalla wells to flow unrestricted.
At Wembley, Advantage's existing well at 12-25-72-8W6 has been tied-in to a third party producer under a best-efforts processing arrangement. Processing capacity is currently very limited in the Pipestone/Wembley area and production from the well may be restricted until 2019. Advantage's 2018 annual liquids production is expected to be 1,520 bbls/d, an increase of 25% as compared to 2017. Annual 2018 production guidance is 40,000 boe/d to 42,500 boe/d (240 mmcfe/d to 255 mmcfe/d).
Operating and Financial Summary
Three months ended |
Nine months ended |
|||||||||||||
Financial and Operating Highlights |
September 30 |
September 30 |
||||||||||||
2018 |
2017 |
2018 |
2017 |
|||||||||||
Financial ($000, except as otherwise indicated) |
||||||||||||||
Sales including realized hedging (3) |
$ |
57,928 |
$ |
51,706 |
$ |
176,625 |
$ |
193,832 |
||||||
Net income (loss) and comprehensive income (loss) |
$ |
(8,852) |
$ |
13,026 |
$ |
(14,043) |
$ |
73,614 |
||||||
per basic share(2) |
$ |
(0.05) |
$ |
0.07 |
$ |
(0.08) |
$ |
0.40 |
||||||
Cash provided by operating activities |
$ |
30,786 |
$ |
56,661 |
$ |
115,372 |
$ |
156,553 |
||||||
per mcfe |
$ |
1.23 |
$ |
2.69 |
$ |
1.75 |
$ |
2.46 |
||||||
per basic share(2) |
$ |
0.17 |
$ |
0.30 |
$ |
0.62 |
$ |
0.84 |
||||||
Adjusted funds flow(1) |
$ |
32,035 |
$ |
36,722 |
$ |
104,077 |
$ |
139,319 |
||||||
per mcfe |
$ |
1.28 |
$ |
1.74 |
$ |
1.58 |
$ |
2.18 |
||||||
per basic share (2) |
$ |
0.17 |
$ |
0.20 |
$ |
0.56 |
$ |
0.75 |
||||||
Cash used in investing activities |
$ |
39,085 |
$ |
77,286 |
$ |
163,011 |
$ |
154,839 |
||||||
Net capital expenditures (1) |
$ |
48,437 |
$ |
89,799 |
$ |
151,834 |
$ |
175,052 |
||||||
Working capital deficit |
$ |
8,169 |
$ |
37,017 |
$ |
8,169 |
$ |
37,017 |
||||||
Bank indebtedness |
$ |
259,179 |
$ |
156,351 |
$ |
259,179 |
$ |
156,351 |
||||||
Basic weighted average shares (000) |
186,065 |
185,953 |
186,073 |
185,533 |
||||||||||
Operating |
||||||||||||||
Daily Production |
||||||||||||||
Natural gas (mcf/d) |
262,841 |
219,812 |
233,780 |
225,480 |
||||||||||
Liquids (bbls/d) |
1,804 |
1,395 |
1,328 |
1,215 |
||||||||||
Total mcfe/d |
273,665 |
228,182 |
241,748 |
232,770 |
||||||||||
Total boe/d |
45,611 |
38,030 |
40,291 |
38,795 |
||||||||||
Average prices (including realized hedging) |
||||||||||||||
Natural gas ($/mcf) (3) |
$ |
1.93 |
$ |
2.26 |
$ |
2.38 |
$ |
2.87 |
||||||
Liquids ($/bbl) |
$ |
67.90 |
$ |
46.95 |
$ |
68.59 |
$ |
52.18 |
||||||
Operating Netback ($/mcfe)(1) |
||||||||||||||
Sales of natural gas and liquids from production |
$ |
2.22 |
$ |
2.06 |
$ |
2.30 |
$ |
2.80 |
||||||
Net sales of natural gas purchased from third parties(1) |
- |
- |
0.02 |
- |
||||||||||
Realized gains on derivatives |
0.08 |
0.40 |
0.38 |
0.25 |
||||||||||
Royalty recovery (expense) |
(0.03) |
0.02 |
(0.01) |
(0.08) |
||||||||||
Operating expense |
(0.27) |
(0.25) |
(0.31) |
(0.25) |
||||||||||
Transportation expense |
(0.51) |
(0.35) |
(0.57) |
(0.36) |
||||||||||
Operating netback(1) |
$ |
1.49 |
$ |
1.88 |
$ |
1.81 |
$ |
2.36 |
||||||
(1) Non-GAAP Measure which may not be comparable to similar non-GAAP measures used by other entities. |
(2) Based on basic weighted average shares outstanding. |
(3) Excludes net sales of natural gas purchased from third parties. |
Advisory
The information in this press release contains certain forward-looking statements within the meaning of applicable securities laws relating to the Corporation's plans and other aspects of its anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. These statements relate to future events or our future intentions or performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "guidance", "demonstrate", "expect", "may", "can", "will", "project", "predict", "potential", "target", "intend", "could", "might", "should", "believe", "would" and similar expressions and include statements relating to, among other things, the estimated total debt to trailing 12 month adjusted funds flow ratio at year-end 2018 and the reasons therefor; the expected sources of funding for the Corporation's Plan, the Plan's development focus and the timing thereof; expected results and benefits to be derived from the Plan, including, but not limited to, increasing annual liquids production and annual liquids production average and the anticipated amount of annual liquids production and annual liquids average in 2021, diversifying the Corporation's revenue sources, developing additional operational and infrastructure optionality and how this will be achieved; annual production average in 2021, increasing C5+/light oil production mix and the expected amount of C5+/light oil production mix increase, the expected amount by which total annual average production will be increased by in 2021, the expected amount of total annual average production in 2021; the amount by which the Corporation's natural gas revenue will be diversified by 2021; the expected adjusted funds flow per share in each of 2019, 2020 and 2021 over each prior annual period; the expected amount of adjusted funds flow netbacks; expected year-end total debt to trailing cash flow ratios in each of 2019, 2020 and 2021; the expected cumulative cash flow and capital investment over the Plan's three years; the number of new wells required to achieve the objectives of the Corporation's Plan and the number of Montney locations for development beyond 2021; expectations that the owned Glacier gas plant has capacity to accommodate future growth and provide third party processing opportunities; Q1 2019 drilling plans in east Glacier and the timing of wells being brought on production; the timing for the construction to be completed on the Corporation's new liquids handling facility in Valhalla and the benefits derived from such new facility; duration of production restrictions at Wembley and the impact on the Corporation's annual 2018 liquids production estimates; the expectation that production restrictions at Wembley will not impact the Corporation's expected annual 2018 production guidance; management's beliefs on the Canadian condensate market and the Canadian natural gas demand; expectations that the Plan will enhance shareholder value; expectations with respect to lean gas and natural gas production over the course of the Plan; the Corporation's future drilling inventory, the estimated well costs and the C3+ liquids content; resource development potential beyond 2021; the timing of the drilling program at Pipestone/Wembley; the timing for the construction to be completed on third party mid-stream facilities; the benefits derived from third party processing arrangements the Corporation entered into with two midstream firms; whether the Corporation will extend its gathering pipelines from Glacier to Wembley and the timing to complete engineering design work and surveying; the impact of the Plan on the Corporation's revenue in 2021 and the expected allocation of natural gas revenue; the Corporation's current and future hedging program; the focus on the Corporation's 2019 capital budget; the Corporation's expected capital expenditures for 2019, including the expected allocation of such expenditures; and other matters. Advantage's actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them.
These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage's control, including, but not limited to: changes in general economic, market and business conditions; industry conditions; impact of significant declines in market prices for oil and natural gas; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; failure to achieve production targets on timelines anticipated or at all; unexpected drilling results; changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; individual well productivity; lack of available capacity on pipelines; delays in anticipated timing of drilling and completion of wells; delays in completion of infrastructure; lack of available capacity on pipelines; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; our ability to comply with current and future environmental or other laws; stock market volatility and market valuations; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Corporation's Annual Information Form dated March 5, 2018 which is available at www.Sedar.com and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.
With respect to forward-looking statements contained in this press release, Advantage has made assumptions regarding, but not limited to: timing of regulatory approvals, conditions in general economic and financial markets; effects of regulation by governmental agencies; current and future commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs, cash costs and liquids transportation costs; frac stages per well; lateral lengths per well; well costs; expected annual production growth rate; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation's conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation's properties in the manner currently contemplated; available pipeline capacity; that the Corporation will be able to complete its infrastructure projects; that Advantage's production will increase; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and that the estimates of the Corporation's production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects. Production estimates contained herein are expressed as anticipated average production over the calendar year. In determining anticipated production for the years ended December 31, 2018, 2019, 2020 and 2021 Advantage considered historical drilling, completion and production results for prior years and took into account the estimated impact on production of the Corporation's 2018, 2019, 2020 and 2021 expected drilling and completion activities.
Management has included the above summary of assumptions and risks related to forward-looking information in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this press release and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Barrels of oil equivalent (boe) and thousand cubic feet of natural gas equivalent (mcfe) may be misleading, particularly if used in isolation. Boe and mcfe conversion ratios have been calculated using a conversion rate of six thousand cubic feet of natural gas equivalent to one barrel of oil. A boe and mcfe conversion ratio of 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. 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 of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
This press release discloses drilling inventory in the Glacier, Valhalla, Progress and Pipestone/Wembley areas in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from Sproule Associates Limited reserves evaluation effective December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 1,200 to 1,400 total drilling locations identified herein, 303 are proved locations, 34 are additional probable locations and 863 to 1,063 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Corporation 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 we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
The Corporation discloses several financial and performance measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS" or "GAAP"). These financial and performance measures include "net capital expenditures" and "adjusted funds flow", which should not be considered as alternatives to, or more meaningful than "net income", "comprehensive income", "cash provided by operating activities", or "cash used in investing activities" as determined in accordance with GAAP. Management believes that these measures provide an indication of the results generated by the Corporation's principal business activities and provide useful supplemental information for analysis of the Corporation's operating performance and liquidity. Advantage's method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Net capital expenditures include total capital expenditures related to property, plant and equipment and exploration and evaluation assets incurred during the period. Management considers this measure reflective of actual capital activity for the period as it excludes changes in working capital related to other periods. The Corporation considers adjusted funds flow to be a useful measure of Advantage's ability to generate cash from the production of natural gas and liquids, which may be used to settle outstanding debt and obligations, and to support future capital expenditures plans. Changes in non-cash working capital are excluded from adjusted funds flow as they may vary significantly between periods and are not considered to be indicative of the Corporation's operating performance as they are a function of the timeliness of collecting receivables or paying payables. Expenditures on decommissioning liabilities are excluded from the calculation of adjusted funds flow as the amount and timing of these expenditures are unrelated to current production, highly variable and discretionary. Please see the Corporation's most recent Management's Discussion and Analysis, which is available at www.sedar.com and www.advantageog.com for additional information about these financial measures, including a reconciliation to the nearest GAAP measures.
This press release and, in particular the information in respect of the Corporation's expected 2019, 2020 and 2021 cash flow per share, 2021 cash flow netbacks, year-end total debt to trailing cash flow ratios for 2019, 2020 and 2021, average cash costs over 2019, 2020 and 2021 and 2019 capital expenditures, may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Corporation's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions, including the assumptions discussed above, and assumptions with respect to the costs and expenditures to be incurred by the Corporation, capital equipment and operating costs, foreign exchange rates, taxation rates for the Corporation, general and administrative expenses and the prices to be paid for the Corporation's production. Management does not have firm commitments for all the costs, expenditures, prices or other financial assumptions used to prepare the FOFI 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 Corporation and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Corporation and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. FOFI contained in this press release was made as of the date of this press release and the Corporation disclaims any intention or obligations to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.
The following abbreviations used in this press release have the meanings set forth below.
bbl |
barrel |
bbl/d |
barrel per day |
bbls/d |
barrels per day |
bbls/mmcf |
Barrels per million cubic feet |
boe |
barrels of oil equivalent of natural gas, on the basis of one barrel of oil or natural gas liquids for six thousand cubic feet of natural gas |
boe/d |
barrels of oil equivalent per day |
GJ |
gigajoule |
mcf |
thousand cubic feet |
mcfe |
thousand cubic feet equivalent on the basis of six thousand cubic feet of natural gas for one barrel of oil or natural gas liquids |
mmcf/d |
million cubic feet per day |
mmcfe/d |
million cubic feet equivalent per day |
SOURCE Advantage Oil & Gas Ltd.
Craig Blackwood, Vice President, Finance and Chief Financial Officer, (403) 718-8005 OR Investor Relations, Toll free: 1-866-393-0393; ADVANTAGE OIL & GAS LTD., 300, 440 - 2nd Avenue SW, Calgary, Alberta T2P 5E9, Phone: (403) 718-8000, Fax: (403) 718-8332, Web Site: www.advantageog.com, E-mail: [email protected]
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