CALGARY, Alberta, March 12, 2018 (GLOBE NEWSWIRE) — NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three months and year ended December 31, 2017 and provide an update on our future business plans.
For NuVista, 2017 was a very active and successful year with significantly increased adjusted funds flow, record production, and material reserves per share growth. These milestones were reached while advancing significantly on our 60,000 Boe/d five year 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. The Company’s balance sheet is strong and the strategic diversification of our gas markets outside of Alberta continued to be advanced materially to protect future cash flows.
NuVista has a material position in the Wapiti Montney play, which with prudent management has delivered solid financial returns to shareholders over the past several years and remains resilient to low natural gas prices. Our Wapiti position continues to improve with advanced drilling and completion technology. Our strategy is to maintain a strong balance sheet to allow the flexibility to accelerate spending when returns are strong. When there is near term commodity price volatility, we can choose to moderate our pace to spend the minimum required while adhering to our long term growth objectives. We also ensure strong alignment of every employee with our shareholders through our compensation structure which is linked to key financial metrics and shareholder returns.
Strong Fourth Quarter and Full Year 2017 Results
During the quarter and year ended 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 and 51% greater than the respective quarter in 2016. Full year 2017 production was approximately 29,800 Boe/d versus full year guidance of 28,000 – 31,000 Boe/d. This represents production which was 21% greater than the prior year figure;
- Achieved condensate & oil weighting which was higher than historical levels due to favorable well results, averaging 35% for the fourth quarter and 33% for the full year of 2017;
- Achieved adjusted funds flow of $75.9 million for the quarter ($0.44/share, basic) 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 versus the fourth quarter of 2016. Full year 2017 adjusted funds flow was $200 million ($1.15/share, basic) versus the originally guided range of $160 – $180 million, an increase of 45% versus the prior year adjusted funds flow;
- Achieved adjusted funds flow netbacks of $18.40/Boe and $22.06/Boe for the full year and fourth quarter of 2017, respectively. This represents an increase of 20% and 23% respectively, versus the corresponding periods of 2016;
- Executed a successful capital expenditure program for the fourth quarter of $40 million, spending significantly less than adjusted funds flow. Full year 2017 capital expenditures were $315 million including facilities expenditures and the drilling of 30 (30 net) wells in our condensate rich Wapiti Montney play. This capital was slightly higher than guidance of up to $310 million primarily due to earlier phasing of the 2018 winter drilling program which commenced in December of 2017;
- 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 well 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 length). 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;
- Realized total annual operating costs of $10.25/Boe, a reduction of 3% versus 2016 operating costs, and;
- Achieved annual net G&A costs of $1.60/Boe, continuing our long term trend of improvement with a reduction of 13% compared to 2016 G&A costs.
Significant Reserves Highlights for 2017
As previously announced, we have had 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”) which was effective December 31, 2017. 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 adjusted funds flow netback were 1.9x and 3.2x, respectively. Based on full year 2017 adjusted funds flow 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 adjusted funds flow 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. The detailed summary of our year end 2017 reserves disclosure was included in our press release dated February 12, 2018 and can be accessed on SEDAR.
Credit Facility, Senior Notes, and Hedging
- Exited 2017 with 41% drawn on the Company’s $310 million credit facility. Net debt, including senior unsecured notes and working capital deficiency, was $196 million and net debt to annualized fourth quarter adjusted funds flow was 0.6 times;
- Subsequent to 2017, NuVista issued $220 million aggregate principal amount of 6.5% five year senior unsecured notes due March 2, 2023. The net proceeds were used to redeem the Company’s pre-existing 9.875% senior unsecured notes in the aggregate principal amount of $70 million, and the excess proceeds were used for a non-permanent repayment of indebtedness under NuVista’s existing credit facility. The credit facility will then be redrawn as needed for general corporate purposes, primarily the ongoing development of our Wapiti Montney condensate rich assets. This private placement is commensurate with the significant increase in value of NuVista’s reserves and production, and;
- Continued to prudently and selectively add to our hedge positions for 2018 and 2019. We currently possess hedges which in aggregate cover 64% of 2018 projected liquids production with a price floor of C$69.91/Bbl, and 66% of 2018 projected gas production at a price of C$2.70/Mcf. Both of these percentage figures relate to production net of royalty volumes. NuVista has also continued to add long term AECO-Nymex basis hedges for terms out to the end of 2024. Combined with our AECO-NYMEX basis hedges and pipeline export contracts, NuVista has essentially no exposure to AECO pricing through the full year of 2018 and a maximum AECO exposure range of approximately 15-25% throughout our 60,000 Boe/d growth plan at attractive pricing.
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. Production for the first quarter of 2018 is anticipated to be in the range of 34,500 – 36,000 Boe/d. Full year adjusted funds flow is anticipated to be in the range of $200 – $230 million after adjusting for the non-recurring cost of refinancing the senior unsecured notes in the first quarter of 2018. This is based on our 2018 forecast production and assumed commodity prices of US$3.00/MMBtu NYMEX and US$55/Bbl WTI. The resulting 2018 net debt to adjusted funds flow ratio is expected to be approximately 1.3 times. In estimating the figures above we have assumed that our production and condensate ratio moderate slightly as compared to the fourth quarter of 2017, after flush production subsides somewhat from new wells brought onstream in that quarter.
NuVista has top quality assets and every team member is focused upon relentless improvement. We are excited to continue pursuing our growth plan to 60,000 Boe/d. We would like to thank our staff, contractors, and suppliers for their continued dedication and delivery, and we thank our board of directors and our shareholders for their continued guidance and support. Please note that our corporate presentation is being updated and will be available at www.nuvistaenergy.com on or before March 12, 2018. NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2017, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on Monday, March 12, 2018 and can also be accessed on NuVista’s website.
|Three months ended December 31||Year ended December 31|
|($ thousands, except per share and per $/Boe)||2017||2016||% Change||2017||2016||% Change|
|Petroleum and natural gas revenues||$||131,009||$||74,538||76||$||377,746||$||257,252||47|
|Adjusted funds flow (1)||75,932||40,697||87||200,030||137,841||45|
|Per share – basic||0.44||0.24||83||1.15||0.87||32|
|Per share – diluted||0.43||0.24||79||1.15||0.87||32|
|Net earnings (loss)||34,651||1,135||—||94,368||(1,653||)||—|
|Per share – basic||0.20||0.01||—||0.54||(0.01||)||—|
|Per share – diluted||0.20||0.01||—||0.54||(0.01||)||—|
|Proceeds on property dispositions||—||2,082||(100||)||2,241||75,983||(97||)|
|Adjusted working capital deficit (1)||2,784||15,536||(82||)|
|Long-term debt (credit facility)||125,725||—||—|
|Senior unsecured notes||67,680||67,156||1|
|Total net debt (1)||196,189||82,692||137|
|Long-term debt (credit facility) capacity||310,000||200,000||55|
|End of period common shares o/s – basic||174,004||172,746||1|
|Natural gas (MMcf/d)||131.7||96.3||37||108.2||97.0||12|
|Condensate & oil (Bbls/d)||13,087||7,258||80||9,860||6,892||43|
|NGLs (Bbls/d) (2)||2,397||1,402||71||1,893||1,575||20|
|Condensate, oil & NGLs weighting||41%||35%||39%||34%|
|Condensate & oil weighting||35%||29%||33%||28%|
|Average selling prices (3) (4)|
|Natural gas ($/Mcf)||3.44||3.74||(8||)||3.58||3.54||1|
|Condensate & oil ($/Bbl)||68.36||58.21||17||61.01||49.81||22|
|Petroleum and natural gas revenues||38.04||32.78||16||34.75||28.53||22|
|Realized gain on financial derivatives||0.16||1.02||(84||)||0.47||2.92||(84||)|
|Operating netback (1)||24.60||20.80||18||21.19||18.38||15|
|Adjusted funds flow netback (1)||22.06||17.90||23||18.40||15.28||20|
|SHARE TRADING STATISTICS|
|Average daily volume||475,615||693,415||(31||)||462,688||549,049||(16||)|
(1) See “Non-GAAP measurements”.
(2) Natural gas liquids (“NGLs”) include butane, propane and ethane.
(3) Product prices exclude realized gains/losses on financial derivatives.
(4) The average NGLs selling price is net of tariffs and fractionation fees.
Basis of presentation
Unless otherwise noted, the financial data presented in this news release has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) also known as International Financial Reporting Standards (“IFRS”). The reporting and measurement currency is the Canadian dollar.
Advisories Regarding Oil And Gas Information
In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes and net present value of reserves in this news release (and all information derived therefrom) are based on “company gross reserves” using forecast prices and costs.
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.
Oil and Gas Metrics
This news release contains a number of 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 our performance on a comparable basis with prior periods; however, such measures are not reliable indicators of our future performance and our future performance may not compare to the performance in previous periods. For details of how our finding and development costs and recycle ratios are calculated see our news release dated February 12, 2018 which can be accessed on SEDAR.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbbl 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.
“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 us.
Advisory regarding forward-looking information and statements
This news release contains forward-looking statements and forward-looking information (collectively, “forward-looking statements”) within the meaning of applicable securities laws. The use of any of the words “will”, “may”, “expects”, “believe”, “plans”, “potential”, “continue”, “guidance”, and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this news release contains forward looking statements, including management’s assessment of: NuVista’s future focus, strategy, plans, opportunities and operations; the use of proceeds from the recently issued 6.5% five year senior unsecured notes; financial and commodity risk management strategy; NuVista’s planned capital expenditures; the timing, allocation and efficiency of NuVista’s capital program and the results therefrom; the anticipated potential and growth opportunities associated with NuVista’s asset base; future drilling results; IP30 rates and well performance; anticipated adjusted funds flow; net debt to adjusted funds flow and production guidance; drilling inventory; and our future exposure to AECO. By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista’s control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and adjusted funds flow, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, access to infrastructure and markets, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; and including, without limitation, those risks considered under “Risk Factors” in our Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the forward-looking statements in this news release in order to provide readers with a more complete perspective on NuVista’s future operations and such information may not be appropriate for other purposes. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Future Oriented Financial Information
This news release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about NuVista’s prospective results of operations and adjusted funds flow, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI and forward-looking statements. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and FOFI, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the forward-looking statements and FOFI in order to provide readers with a more complete perspective on NuVista’s future operations and such information may not be appropriate for other purposes. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Within the news release, references are made to terms commonly used in the oil and natural gas industry. Management uses “adjusted funds flow”, “adjusted funds flow per share”, “adjusted funds flow netback”, “net debt”, “total net debt”, “net debt to annualized fourth quarter adjusted funds flow”, “operating netback” and “adjusted working capital deficit”. 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. For more details on non-GAAP measures, including a reconciliation to GAAP measures refer to our Management’s Discussion and Analysis.
Adjusted funds flow 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, note receivable allowance (recovery) and environmental remediation expenses (recovery). Adjusted funds flow 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 or other measures of financial performance calculated in accordance with GAAP.
Adjusted funds flow per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings per share. Total revenue equals oil and natural gas revenues including realized financial derivative gains/losses. Operating netback equals the total of revenues including realized financial derivative gains/losses less royalties, transportation and operating expenses calculated on a Boe basis. Adjusted funds flow netback is operating netback less general and administrative, 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, asset retirement obligations and deferred premium on flow through shares. Net debt to annualized fourth quarter adjusted funds flow is net debt divided by annualized fourth quarter adjusted funds flow.
FOR FURTHER INFORMATION CONTACT:
Jonathan A. Wright Ross L. Andreachuk Mike J. Lawford
President and CEO VP, Finance and CFO Chief Operating Officer
(403) 538-8501 (403) 538-8539 (403) 538-1936