NuVista Energy Ltd. Announced Significant Quarterly Funds From Operations and Year End 2017 Reserves Growth
OREANDA-NEWS. NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce certain unaudited financial and operating results for the three months and year ended December 31, 2017; in addition to our year end independent reserve evaluation. The fourth quarter of 2017 was very active and successful with significantly increased funds from operations, record production, and material reserves per share growth. These milestones were reached while advancing significantly along on our 60,000 Boe/d growth plan. In 2017 NuVista was able to make meaningful continued improvement in well results through the application of new technologies including higher intensity fracture stimulation (HiFi) and extended reach horizontal wells (ERH) while reducing the total capital cost per stage and per metre completed. Balance sheet strength was excellent and the strategic diversification of our gas markets outside of Alberta continued to be advanced materially.
Strong Fourth Quarter and Full Year 2017 Results
NuVista anticipates announcing fourth quarter and audited year end 2017 financial results on or near March 12, 2018. The following are the unaudited highlights and all numbers are approximate. During the quarter and year ending December 31, 2017, NuVista:
- Produced a record 37,400 Boe/d for the fourth quarter of 2017, near the top of the guidance range of 35,000 – 38,000 Boe/d. Full year 2017 production was approximately 29,800 Boe/d versus full year guidance of 28,000 – 31,000 Boe/d;
- Achieved condensate & oil weighting which was higher than historical levels due to favorable well results, averaging 35% for the fourth quarter;
- Achieved funds from operations level of $76 million for the quarter due to increased production, improved condensate & oil weighting, and improved realized product pricing. This represents an increase of 85% versus the prior quarter and also the fourth quarter of 2016. Full year 2017 funds from operations were $200 million versus the originally guided range of $160 - $180 million;
- Achieved corporate funds from operations netbacks of $18.40/Boe and $22.06/Boe for the full year and fourth quarter of 2017, respectively;
- Executed a robust capital expenditure program for the fourth quarter of $40 million, spending significantly less than funds from operations. Full year 2017 capital expenditures were $315 million. This was slightly higher than guidance of up to $310 million primarily due to phasing of the 2018 winter drilling program which commenced earlier in December of 2017, and
- Exited 2017 with net debt of $196 million, maintaining a strong balance sheet with net debt to annualized fourth quarter funds from operations ratio of 0.6 times.
Lower Montney IP30 Result
NuVista successfully drilled our first Lower Montney horizontal well at Bilbo in the fourth quarter with very encouraging results. The well has now been on production for over one month and the initial IP30 production averaged over 3.6 MMcf/d raw gas and 665 Bbls/d of condensate, while flowing at a restricted rate. This represents a condensate gas ratio of 182 Bbls/MMcf. The well was drilled to 2,950m horizontal length and completed at regular fracture intensity (1 tonne of proppant per meter of horizontal). This Lower Montney well result is a very positive step for the continued derisking of this emerging layer of the Montney formation in our area.
Significant Reserves Highlights for 2017
NuVista is pleased to announce another significant increase in our reserves value as a result of the 2017 year end independent evaluation of our reserves by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”). 2017 saw significant increases to both Proved Developed Producing (“PDP”) and Total Proved plus Probable (“TP+PA”) reserves. Although GLJ’s assumptions for future commodity prices are lower than year end 2016, the combination of our continued shift to a higher condensate proportion coupled with our access to alternative gas markets outside of Alberta has helped to maintain continued improvement in the reserves value per barrel, leading to material increases to the overall net present value of our reserves. In addition to the growth, a number of strategic accomplishments were delivered including a significant increase to Pipestone reserves, the first booking of undeveloped ERH locations at Gold Creek, and NuVista’s first ever bookings in the Lower Montney zone, at Bilbo. Significant highlights of the evaluation include:
- Increased PDP reserves 43% from 37.9 to 54.1 MMBoe. This represents the largest percentage increase in PDP reserves since we began the transition into the Montney. TP+PA reserves increased 35% from 257 to 347 MMBoe;
- Increased the respective net present values before tax discounted at 10% (“NPVBT10”) of our PDP and TP+PA reserves materially year over year from $388 million and $1,165 million to $530 million and $1,782 million. This represented increases of 36% and 53% for the PDP and TP+PA NPVBT10 values, respectively, despite a reduction in the GLJ forecast pricing assumptions as compared to the prior year, particularly for natural gas;
- Increased Pipestone undeveloped gross drilling location count from 8 to 36. This core area now represents approximately 15% and over 20% of the Company’s TP+PA reserves and NPVBT10, respectively;
- Booked one PDP and four gross undeveloped drilling locations in the Lower Montney for total TP+PA reserves of 4.2 MMBoe. This further strengthens our confidence in the future development potential of this emerging horizon and corroborates our belief that the zone is indeed condensate rich in nature;
- Achieved continued low PDP and TP+PA finding and development (“F&D”) costs in 2017 of $11.35/Boe and $6.95/Boe, respectively. The PDP and TP+PA recycle ratios based on fourth quarter 2017 funds from operations netback were 1.9x and 3.2x, respectively. Based on full year 2017 funds from operations netback the PDP and TP+PA recycle ratios were 1.6x and 2.6x, respectively;
- Increased TP+PA Future Development Capital (“FDC”) versus 2016, from $1.6 billion to $2.0 billion as a result of the undeveloped reserve adds at Pipestone, Gold Creek, and the Lower Montney. This is accompanied by a continued decrease in the ratio of FDC to funds from operations to 10.0x from 12.9x at year end 2015 and 11.8x at year end 2016;
- NuVista’s forecast future realized gas prices are impacted less than GLJ’s decrease in AECO gas forecast as NuVista’s firm gas sales market diversification agreements have been reflected in the GLJ Report, and;
- Achieved positive PDP and TP+PA technical revisions of 7% and 6%, respectively, primarily based on production performance.
NuVista is pleased to note that our TP+PA reserve base has grown consistently over the past 5 years at a compounded annual growth rate of 64% to 347 MMBoe at year end 2017, illustrating the continued advancement of the inventory to underpin our growth strategy to 60,000 Boe/d and beyond. As the proportion of reserves attributed to the Montney has increased, so has the weighting to condensate which now forms 27% of the Company’s PDP reserves, up from 19% in 2015 and 25% last year.
No Change To 2018 Guidance
Guidance for 2018 remains as previously announced with capital spending anticipated in the range of $270 - $310 million and 2018 production expected in the range of 35,000 – 40,000 Boe/d. Full year funds from operations is anticipated to be in the range of $210 - $240 million, based on 2018 forecast production and assumed commodity prices of US$3.00/MMBtu NYMEX and US$55/Bbl WTI. The resulting 2018 net debt to funds from operations ratio is expected to be approximately 1.2 times.
The kickoff to our 2018 capital program has gone well. Production for the first quarter of 2018 is anticipated to be in the range of 34,500 – 36,000 Boe/d, with production in the third and fourth quarters of 2018 anticipated to be in the upper portion of the annual guidance range as wells drilled during the active winter drilling season are fracture stimulated and brought on production through the summer months.
Detailed Summary of Corporate Reserves Data
The following table provides summary reserve information based upon the GLJ Report using the published GLJ January 1, 2018 price forecast:
|Natural Gas(2)||Natural Gas
|Reserves category(1)||Company Gross||Company Gross||Company Gross||Company Gross|
|Total proved plus probable||1,375,188||117,454||34||346,685|
(1) Numbers may not add due to rounding.
(2) Includes conventional natural gas and shale gas and coal bed methane.
(3) Includes light, medium crude oil.
The following table is a summary reconciliation of the 2017 year end working interest reserves with the working interest reserves reported in the 2016 year end reserves report:
|Balance, December 31, 2016||547,046||42,587||65||133,826|
|Exploration and development(2)||161,428||16,480||0||43,385|
|Balance, December 31, 2017||679,193||57,458||25||170,682|
|Total proved plus probable
Total proved plus probable
|Balance, December 31, 2016||1,050,121||82,255||86||257,361|
|Exploration and development(2)||332,845||35,058||0||90,532|
|Balance, December 31, 2017||1,375,188||117,454||34||346,685|
(1) Numbers may not add due to rounding.
(2) Reserve additions for drilling extensions, infill drilling and improved recovery.
(3) Includes conventional natural gas, shale gas and coal bed methane.
(4) Includes light, medium crude oil.
The following table summarizes the future development capital included in the GLJ Report:
|($ thousands, undiscounted)||Proved||Proved plus
The following table outlines NuVista's corporate finding and development costs in more detail:
|3 Year-Average (1)||2017 (1)||2016 (1)|
|Proved plus||Proved plus||Proved plus|
|After reserve revisions and including changes in future development capital|
|Finding and development costs ($/Boe)||$9.56||$6.40||$9.70||$6.95||$10.13||$8.39|
(1) F&D costs are used as a measure of capital efficiency. The calculation for F&D costs includes all exploration and development capital for that period as outlined in the Company’s year end financial statements and unaudited estimated amount for 2017 plus the change in future development capital for that period. This total capital including the change in the future development capital is then divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year.
Total Proved F&D was $9.70/Boe in 2017, down from $10.13/Boe in 2016 and in-line with our three year average of $9.56/Boe. Total Proved plus Probable F&D was $6.95/Boe in 2017, down from $8.39/Boe in 2016 and marginally above the three year average of $6.40/Boe. The three year average Total Proved plus Probable F&D is marginally below 2017 due to the anomalously low numbers achieved in 2015 due to a large one-time reduction in FDC due to cost efficiency gains.
Summary of Corporate Net Present Value Data
The estimated net present values of future net revenue before income taxes associated with NuVista’s reserves effective December 31, 2017 and based on published GLJ future price forecast as at January 1, 2018 as set forth below are summarized in the following table:
The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
|Before Income Taxes|
|Discount Factor (%/year)|
|Reserves category (1) ($ thousands)||0%||5%||10%||15%||20%|
|Total proved plus probable||4,854,104||2,762,377||1,782,109||1,254,503||938,826|
(1) Numbers may not add due to rounding.
The following table is a summary of pricing and inflation rate assumptions based on published GLJ forecast prices and costs as at January 1, 2018:
(1) Costs are inflated at 2% per annum.
(2) Exchange rate used to generate the benchmark reference prices in this table.
(3) NuVista’s future realized gas prices are forecasted based on a combination of various benchmark prices in addition to the AECO benchmark in order to reflect the favorable price diversification to other markets which NuVista has undertaken. Pricing at these markets has been accounted for in the GLJ Report. Additional information on NuVista’s gas marketing diversification will be available in our Q4 2017 MD&A as well as in our corporate presentation.
ADVISORIES REGARDING OIL AND GAS INFORMATION
This news release contains the term barrels of oil equivalent (“Boe”). Natural gas is converted to a Boe using six thousand cubic feet of gas to one barrel of oil. Boes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As well, given than the value ratio based on the current price of crude oil to natural gas is significantly different from the 6:1 energy equivalency ratio, using a conversion ratio on a 6:1 basis may be misleading as an indication of value.
This news release contains a number of additional oil and gas metrics prepared by management, including F&D costs and recycle ratios, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate NuVista's performance on a comparable basis with prior periods; however, such measures are not reliable indicators of the future performance of NuVista and future performance may not compare to the performance in previous periods. Details of how F&D costs have been calculated are included in the body of this press release. Recycle ratio has been calculated by dividing fourth quarter 2016 funds from operations netback and full year funds from operations netback (refer to Non-GAAP Measurements) by F&D costs per Boe for the year.
“IP30” is defined as the estimated average producing day rate over the initial first 30 days of production. Any references in this news release to such 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. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.
Within this new release, references are made to terms commonly used in the oil and natural gas industry. Management uses “funds from operations”, "funds from operations netback", "net debt", "net debt to annualized fourth quarter funds from operations", "operating netback", and “annual cash costs” to analyze operating performance and leverage. These terms do not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. These terms are used by management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of NuVista.
Funds from operations are based on cash flow from operating activities as per the statement of cash flows before changes in non-cash working capital, asset retirement expenditures, environmental remediation expense and note receivable impairment (recovery). Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, per the statement of cash flows, net earnings (loss) or other measures of financial performance calculated in accordance with GAAP.
Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net loss per share. Operating netback equals the total of revenues including realized financial derivative gains/losses less royalties, transportation and operating expenses calculated on a Boe basis. Funds from operations netback is operating netback less general and administrative, restricted stock units, deferred share units and interest expenses calculated on a Boe basis. Net debt is calculated as long-term debt plus senior unsecured notes plus adjusted working capital. Adjusted working capital is current assets less current liabilities and excludes the current portions of the financial derivative assets or liabilities and asset retirement obligations. Net debt to annualized fourth quarter funds from operations is net debt divided by annualized fourth quarter funds from operations. Annual cash costs equals the total of royalties, transportation, operating expenses, general and administrative costs and interest costs calculated on a Boe basis.
This news release contains preliminary estimates of fourth quarter and 2017 annual funds from operations and funds from operations netback as well as 2017 net debt and net debt to annualized fourth quarter funds from operations. Readers are cautioned that these are estimates based on preliminary financial results, which have not yet been finalized or, in the case of annual results, audited and, as such, these estimates could change and a reconciliation to their mostly directly comparable GAAP measure is not available.
The reserves estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and are effective as of December 31, 2017. All reserves information has been presented on a gross basis, which is the Company's working interest share before deduction of royalties and without including any royalty interests of the Company. The reserves have been categorized accordance with the reserves definitions as set out in the COGE Handbook.
The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
This news release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the GLJ Report 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 36 gross Pipestone drilling locations included in this news release, 9 are proved locations and 27 are probable locations. Of the 4 gross Lower Montney drilling locations included in this news release, 2 are proved locations and 2 are probable 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 we 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 derisked 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 or production.