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Altura Energy Inc. Announces Fourth Quarter and Year End 2017 Financial and Operating Results and Provides an Operational Update

CALGARY, Alberta, March 22, 2018 (GLOBE NEWSWIRE) -- Altura Energy Inc. ("Altura", or the "Corporation") (TSXV:ATU) is pleased to announce its financial and operating results for the fourth quarter and year ended December 31, 2017, and an operational update. The audited consolidated financial statements, and related management’s discussion and analysis ("MD&A") will be available at www.sedar.com and www.alturaenergy.ca.

OPERATION AND FINANCIAL SUMMARY

Three months endedYear ended
December 31,
2017
September 30,
2017
December 31,
2016
December 31,
2017
December 31,
2016
OPERATING
Average daily production
Medium oil (bbls/d)414 624 627 557 423
Heavy oil (bbls/d)544 274 195 369 59
Natural gas ­(mcf/d)1,286 1,045 890 1,085 501
NGLs (bbls/d)30 16 17 22 8
Total (boe/d)1,202 1,088 988 1,128 574
Total boe/d per million shares – basic 11.0 10.0 9.1 10.4 5.3
Average realized prices
Medium oil ($/bbl)55.73 47.61 51.37 51.41 44.37
Heavy oil ($/bbl)48.54 46.50 44.54 46.75 42.42
Natural gas ($/mcf)1.81 1.71 3.34 2.33 2.65
NGLs ($/bbl)45.46 49.54 44.75 42.79 39.60
Total ($/boe)44.22 41.38 45.20 43.72 39.95
NETBACK ($/boe)
Petroleum and natural gas sales44.22 41.38 45.20 43.72 39.95
Royalties(3.24)(3.70)(3.67)(3.88)(2.90)
Operating (9.72)(10.01)(8.99)(10.06)(9.09)
Transportation(1.86)(2.65)(2.52)(2.29)(2.67)
Operating netback(1)29.40 25.02 30.02 27.49 25.29
General and administrative(6.20)(3.78)(6.03)(4.31)(8.16)
Exploration expense- - - - (0.32)
Interest and financing expense(0.38)(0.06)(0.05)(0.20)(0.17)
Interest income- - 0.25 0.04 0.76
Corporate netback(1)22.82 21.18 24.19 23.02 17.40
FINANCIAL ($000, except per share amounts)
Petroleum and natural gas sales 4,892 4,143 4,106 18,001 8,390
Adjusted funds flow(1)2,526 2,119 2,197 9,478 3,656
Per share – basic and diluted(1)0.02 0.02 0.02 0.09 0.03
Cash flow from operating activities1,940 2,545 1,683 9,548 2,337
Per share – basic and diluted0.02 0.02 0.02 0.09 0.02
Income (loss)(1,032)322 264 (103)(1,249)
Per share – basic and diluted(0.01)- - - (0.01)
Capital expenditures, acquisitions and dispositions2,728 6,439 6,945 21,197 17,492
Net debt (working capital surplus) (1)3,729 2,881 (8,455)3,729 (8,455)
Common shares outstanding (000)
End of period – basic108,921 108,921 108,921 108,921 108,921
Weighted average for the period – basic108,921 108,921 108,921 108,921 108,921
Weighted average for the period – diluted108,921 108,922 108,921 108,921 108,921

(1) Adjusted funds flow, adjusted funds flow per share, net debt, corporate netback, and operating netback do not have standardized meanings prescribed by generally accepted accounting principles and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. Refer to the Non-GAAP Measures paragraph in the Advisories section of the MD&A.

2017 HIGHLIGHTS

  • Production volumes averaged 1,128 boe per day (84% oil and NGLs), a per share increase of 96% from 2016.
  • Adjusted funds flow was $9.5 million, up 159% from 2016 due to increased production volumes and higher crude oil prices.
  • Operating netback averaged $27.49 per boe, up 9% from 2016.
  • Total cash costs (royalties, operating, transportation, G&A, exploration, and interest and financing expenses) were $20.70 per boe, 8% lower than 2016, driving a corporate netback of $23.02 per boe for the year.
  • Capital expenditures totaled $21.2 million, including $14.7 million on drilling, completions and equipping, plus $3.8 million on facilities and pipelines.
  • Proved developed producing ("PDP") reserves increased by 45% from 1,099 mboe to 1,595 mboe. Total proved ("1P") reserves increased by 71% from 1,821 mboe to 3,107 mboe. Total proved plus probable ("2P") reserves increased by 68% from 3,195 mboe to 5,370 mboe.
  • All-in finding, development and acquisition ("FD&A") costs1 were $23.36 per boe for PDP, $21.97 per boe for 1P and $17.21 per boe for 2P reserves, including the changes in future development costs ("FDC"). This includes $5.6 million of non-reserve adding capital (27% of capital expenditures) to acquire undeveloped land and construct pipelines and facilities.
  • Recycle ratio1 of 1.2 times for PDP, 1.3 times for 1P, and 1.6 times for 2P reserves based on the all-in 2017 FD&A costs and Altura’s 2017 operating netback of $27.49 per boe.
  • The credit facility was increased to $10.0 million in October 2017 from $4.0 million in 2016 as a result of growth in Altura’s producing reserves and value. Net debt at December 31, 2017 was $3.7 million or 0.4 times annualized fourth quarter adjusted funds flow.

FOURTH QUARTER 2017 HIGHLIGHTS

  • Production volumes averaged 1,202 boe per day, a per share increase of 10% from the third quarter of 2017 and 22% from the fourth quarter of 2016.
  • Adjusted funds flow was $2.5 million, up 19% from the third quarter of 2017 and up 15% from the fourth quarter of 2016 due primarily to increased production volumes and higher crude oil prices.
  • At Leduc-Woodbend, two 1.5-mile extended reach horizontal ("ERH") wells (102/13-14-049-26W4 or "13-14") and 100/03-02-049-26W4 "03-02") were brought on production on October 27th. The two wells together produced 559 boe per day (95% oil & NGLs) from October 27th to December 31st or 401 boe per day in the fourth quarter.
  • Operating netback averaged $29.40 per boe, up 18% from the third quarter of 2017 and consistent with the fourth quarter of 2016.
  • Total cash costs (royalties, operating, transportation, G&A, exploration, and interest and financing expenses) were $21.40 per boe, driving a corporate netback of $22.82 per boe for the quarter.
  • Leduc-Woodbend operating and transportation costs averaged $9.51 per boe, down from $18.10 per boe in the third quarter of 2017 and $14.70 per boe in the fourth quarter of 2016.
  • Net capital expenditures totaled $2.7 million. The main projects included $1.7 million for completion and equipping activities related to the two new ERH wells and $0.7 million for the emulsion gathering pipeline at Leduc-Woodbend.

______________________________________
1
"Finding, development & acquisition costs" or "FD&A costs", and "Recycle ratio" do not have standardized meanings. See "Oil and Gas Metrics" contained in this news release.


OPERATIONAL UPDATE

Leduc-Woodbend

Since acquiring its initial land position in 2015 and drilling its first horizontal well in August 2016, Altura has accumulated 66 sections of 100% working interest land in this Upper Mannville Rex oil pool. Altura believes this pool to be one of the largest conventional oil pools discovered in the Western Canada Sedimentary Basin within the last 20 years. The Corporation is in the very early stages of drilling its large oil-weighted well inventory, with only five horizontal wells drilled to date.

Leduc-Woodbend 2P reserves increased 900% to 2,140 mboe in 2017 from 235 mboe in 2016 and now represent 40% of Altura's total 2P reserves. Production volumes for the area increased to 516 boe per day in the fourth quarter of 2017 compared to 167 boe per day in the third quarter of 2017 and 81 boe per day in the fourth quarter of 2016.

Operating and transportation costs for this core area decreased to $9.51 per boe in the fourth quarter of 2017 compared to $18.10 per boe in the third quarter of 2017 and $14.70 per boe in the fourth quarter of 2016. The decreased operating and transportation costs are attributed to increased production volumes coupled with decreased well servicing costs and markedly reduced water handling and water disposal costs due to the 2017 infrastructure expenditures in the area.

Altura drilled and completed a 1.5-mile ERH well (100/02-02-049-26W4 or "02-02") in the first quarter of 2018, its third ERH well in the area. The well was drilled to a vertical depth of 1,300 meters with a horizontal length of approximately 2,000 meters with 46 frac stages. Drilling and completion costs for 02-02 including access roads and pad construction are estimated at $2.5 million.

The 02-02 well was placed on production on February 24th and produced a total of 6,925 bbls of 17° API oil over the first 26 calendar days ending March 21st. The well initially produced at restricted rates due to solution gas processing constraints and the recovery of completion load fluid. The well has now fully recovered the completion load fluid and the average production rates over the last seven days ended March 21st is shown below:

WellOIL
bbls/d
NGLs
bbls/d
GAS
mcf/d
TOTAL
boe/d
WATER
bbls/d
100/02-02-049-26W4 2939192334294

Current production rates from all three ERH wells (13-14, 03-02, and 02-02) are exceeding management's expectations. With limited production history to date, Altura is modeling each well to average approximately 160 boe per day over the first 12 months of production and exit the 12-month period at 105 boe per day. For more detailed information, please refer to Altura’s corporate presentation on the Corporation’s website at www.alturaenergy.ca.

The Corporation continues to invest in critical infrastructure in the area. In March, Altura constructed a key natural gas gathering pipeline that connects Altura's northern area production to a second third party gas plant in the southern half of the field. This pipeline connection is expected to come on stream at the beginning of April and will increase Altura’s natural gas gathering and processing capacity, reduce processing fees, and enable Altura to avoid periodic production curtailments related to third party gas gathering systems.

Altura remains committed to expanding the multi-well battery at 12-14-049-26W4 ("12-14") to a processing capacity of 3,000 to 3,500 barrels of oil per day. To date, Altura has invested approximately $0.9 million on the initial phase of the battery which includes procurement of major equipment, full scale engineering, and the installation of water disposal equipment. Water disposal commenced mid-March from the 12-14 battery into Altura's northern area disposal well which will result in further operating cost reductions by eliminating water hauling to Altura’s water disposal well in the southern area of the field. The final construction and commission phases of the multi-well battery to meet designed oil processing rates are planned for 2019.

Macklin

Altura drilled and completed a 1.0-mile horizontal well at Macklin (09-33-039-28W3 or "09-33") in the first quarter of 2018 following up on the success of its initial horizontal well drilled in this Sparky oil pool in March 2017 (13-32-039-28W3). The 09-33 well was drilled to a vertical depth of 725 meters with a horizontal length of 1,485 meters with 36 frac stages and was placed on production on February 1, 2018. Drilling and completion costs including access roads and pad construction are estimated at $1.3 million.

The 09-33 well produced a total of 2,236 bbls of 19° API oil over the first 49 calendar days ending March 21st while recovering 7,724 bbls of completion load fluid. The well has fully recovered the completion load fluid and is continuing to improve with a decreasing water cut. A summary of the average well production rates over the last seven days ended March 21st is shown below:

Well OIL
bbls/d
NGLs
bbls/d
GAS
mcf/d
TOTAL
boe/d
WATER
bbls/d
101/09-33-039-28W3 6204269185

Altura is modeling the 09-33 well to average approximately 64 boe per day over the first 12 months of production and exit the 12-month period at 44 boe per day.

In February, the Corporation commissioned a new produced water disposal pipeline at Macklin which is connected to third party water disposal facilities. This has eliminated water hauling and will reduce area operating costs.

OUTLOOK

For the remainder of 2018, Altura plans to drill two additional ERH wells at Leduc-Woodbend. Guidance remains as previously announced with capital expenditures of approximately $15 million for 2018. The capital development program is split approximately 60% to drilling, completion, equipping and tie-in ("DCET") capital and 40% to infrastructure and other capital. The significant weighting to infrastructure investment positions Altura to continue to reduce operating costs and grow production profitably as it develops its Leduc-Woodbend oil pool.

The capital program is forecasted to grow 2018 annual average production by 12% to 1,260 boe per day. Based on $9.5 million of well-related capital, the current program is forecasted to deliver a capital efficiency on an annual basis of approximately $17,000/boe per day.

On behalf of our management team and board of directors, we thank our shareholders for their ongoing support and commitment to Altura.

ANNUAL GENERAL MEETING

The Annual General Meeting of shareholders will be held at 9:30 a.m. on Thursday, May 17, 2018 in the Devonian Room at the Calgary Petroleum Club, 319 – 5th Avenue SW, Calgary, Alberta.

ABOUT ALTURA ENERGY INC.

Altura is a junior oil and gas exploration, development and production company with operations in central and east central Alberta. Altura predominantly produces from the Sparky and Rex members in the Upper Mannville group and is focused on delivering per share growth and attractive shareholder returns through a combination of organic growth and key strategic acquisitions.

An updated corporate presentation is available on Altura's website at www.alturaenergy.ca.

READER ADVISORIES

Forwardlooking Information and Statements

This press release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "budget", "forecast", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this press release contains forward-looking information and statements pertaining to plans concerning the construction of a future multi-well battery at Leduc-Woodbend, the ability to reduce operating costs and grow production profitably with planned Leduc-Woodbend infrastructure investments, on-stream date for the new gas gathering pipeline at Leduc-Woodbend, ability to reduce processing fees and reduce production curtailments with the new natural gas gathering pipeline, 2018 budget guidance, forecasted 2018 production growth, and forecasted 2018 capital efficiency. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve 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.

The forward-looking information and statements contained in this press release reflect several material factors and expectations and assumptions of Altura including, without limitation:

  • the continued performance of Altura’s oil and gas properties in a manner consistent with its past experiences
  • that Altura will continue to conduct its operations in a manner consistent with past operations;
  • the general continuance of current industry conditions;
  • the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes;
  • the accuracy of the estimates of Altura’s reserves and resource volumes;
  • certain commodity price and other cost assumptions;
  • the continued availability of oilfield services; and
  • the continued availability of adequate debt and equity financing and cash flow from operations to fund its planned expenditures.

Altura believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. To the extent that any forward-looking information contained herein may be considered future oriented financial information or a financial outlook, such information has been included to provide readers with an understanding of management’s assumptions used for budgeted and developing future plans and readers are cautioned that the information may not be appropriate for other purposes.

The forward-looking information and statements included in this press release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve 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 or statements including, without limitation:

  • changes in commodity prices;
  • changes in the demand for or supply of Altura’s products;
  • unanticipated operating results or production declines;
  • changes in tax or environmental laws, royalty rates or other regulatory matters;
  • changes in development plans of Altura or by third party operators of Altura’s properties,
  • increased debt levels or debt service requirements;
  • inaccurate estimation of Altura’s oil and gas reserve and resource volumes;
  • limited, unfavorable or a lack of access to capital markets;
  • increased costs;
  • a lack of adequate insurance coverage;
  • the impact of competitors; and
  • certain other risks detailed from time to time in Altura’s public documents.

The forward-looking information and statements contained in this press release speak only as of the date of this press release, and Altura does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

NonGAAP Measures

This press release contains references to measures used in the oil and natural gas industry such as "adjusted funds flow", "net debt", "corporate netback", " adjusted funds flow per share", and "operating netback". These measures do not have standardized meanings prescribed by generally accepted accounting principles ("GAAP") and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used, they should be given careful consideration by the reader. These measures have been described and presented in the press release to provide shareholders and potential investors with additional information regarding the Corporation’s liquidity and its ability to generate funds to finance its operations.

Adjusted funds flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with GAAP, as an indicator of Altura's performance or liquidity. Adjusted funds flow is used by Altura to evaluate operating results and the Corporation's ability to generate cash flow to fund capital expenditures and repay indebtedness. Adjusted funds flow denotes cash flow from operating activities as it appears on the Corporation’s statement of cash flows before decommissioning expenditures, if any, transaction costs and changes in non‐cash operating working capital. Adjusted funds flow per share is calculated as adjusted funds flow divided by the weighted average number of basic and diluted common shares outstanding. Operating netback denotes total sales less royalty expenses, and operating and transportation costs calculated on a per boe basis. Corporate netback denotes operating netback less general and administrative, interest and financing expense, exploration expense plus interest income on a per boe basis. Altura uses net debt as a measure to assess its financial position. Net debt is equivalent to working capital deficit.

Reserves

All reserve references in this press release are "company share reserves". Company share reserves are the Corporation’s total working interest reserves before the deduction of any royalties and including any royalty interests of the Corporation.

It should not be assumed that the present value of estimated future net revenue presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Altura’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value.

Barrels of Oil Equivalent

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. Per boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 mcf) of natural gas to one barrel (1 bbl) of crude oil. The boe conversion ratio of 6 mcf to 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 equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by Altura as set out below. These metrics are "finding, development and acquisition costs", "recycle ratio", "reserve replacement", "reserve life index", "operating netbacks" and "net asset value". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Altura’s performance over time, however, such measures are not reliable indicators of Altura's future performance and future performance may not compare to the performance in previous periods.

  • "Finding, development and acquisition costs" or "FD&A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

    FD&A costs take into account reserves revisions and capital revisions during the year. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total FD&A costs related to reserves additions for that year. FD&A costs have been presented in this news release because acquisitions and dispositions can have a significant impact on Altura's ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Management uses FD&A as measures of its ability to execute its capital programs (and success in doing so) and of its asset quality.
  • "Recycle ratio" or is calculated by dividing the operating netback (in dollars per boe) by the FD&A costs (in dollars per boe) for the year. Altura uses recycle ratio as an indicator of profitability of its oil and gas activities.

Initial Production Rates

Any references in this press release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Oil and gas formations are inherently unpredictable, particularly in the early stage of their development. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Corporation.

For further information please contact:

Altura Energy Inc.
200, 640 – 5th Avenue SW
Calgary, Alberta T2P 3G4
Telephone (403) 984-5197
www.alturaenergy.ca


David BurghardtTavis Carlson
President and Chief Executive OfficerVice President, Finance and Chief Financial Officer
Direct (403) 984-5195Direct (403) 984-5196

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Source:Altura Energy Inc.