BOE Report

NuVista Energy Ltd. Announces First Quarter 2018 Financial and Operating Results

CALGARY, Alberta, May 08, 2018 (GLOBE NEWSWIRE) — NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three months ended March 31, 2018 and provide an update on our future business plans.

This has been another successful quarter for NuVista, with key operational advancements, the favorable placement of senior unsecured notes and the renewal of our credit facility.  It was also a quarter where despite industry headwinds, we have seen improvement in oil and condensate pricing, and relative steadiness in NYMEX natural gas pricing.  Due to our favorable price diversification and natural gas export position, NuVista has not been materially exposed to the downward pressure affecting AECO natural gas pricing.  As a result, NuVista adjusted funds flow netbacks have continued to strengthen and our balance sheet remains robust as we progress on our 60,000 Boe/d growth plan.

Key Financial and Operational Highlights

During the quarter ended March 31, 2018 NuVista:

  • Achieved production of 36,100 Boe/d, at the top of the guidance range of 34,500 – 36,000 Boe/d and 35% greater than the comparative quarter in 2017.  Condensate volume weighting remained similar to the prior year at 31% but decreased from the short term high of 35% for the fourth quarter of 2017, as expected;
  • Attained adjusted funds flow of $58.7 million for the quarter ($0.34/share, basic), compared to $43.3 million ($0.25/share, basic) for the first quarter of 2017.  Q1 2018 includes approximately $9 million in costs for the early redemption of our prior $70 million term note;
  • Achieved adjusted funds flow netbacks of $18.09/Boe as compared to $17.98/Boe for the first quarter of 2017;
  • Realized operating costs of $10.02/Boe as compared to $10.72 for the comparable quarter in 2017;
  • Continued our downward trend in net G&A expenses, reaching $1.41/Boe, as compared to $1.71 in the first quarter of 2017;
  • Executed a successful $115 million capital expenditure program for the first quarter running three to four rigs and drilling 8 gross (8 net) successful wells in our Wapiti asset; and
  • Successfully drilled, completed and brought on stream the longest horizontal lateral well ever drilled in Canada at almost 3,000 Boe/d, including over 1,000 BBls/d of condensate.

Credit Facility, Senior Notes, and Hedging

  • Exited the first quarter of 2018 with nil drawn on the Company’s $310 million credit facility. Net debt, including senior unsecured notes and working capital deficiency, was $259 million;
  • Achieved net debt to annualized current quarter adjusted funds flow of 1.1 times;
  • During the quarter, NuVista issued $220 million of 6.5% five year senior unsecured notes due March 2, 2023.  The net proceeds were used in part to redeem the Company’s pre-existing 9.875% senior unsecured notes in the amount of $70 million and the excess proceeds were used for a non-permanent repayment of indebtedness under NuVista’s existing credit facility;
  • Subsequent to the first quarter of 2018, NuVista successfully concluded the annual review of our borrowing base with our lenders with no change to the $310 million credit capacity, and;
  • Continued to prudently and selectively add to our hedge positions for 2018 and beyond.  We currently possess hedges which in aggregate cover approximately 70% of 2018 projected liquids production with a price floor of C$70.41/Bbl, and approximately 70% of 2018 projected gas production at a price of C$2.62/Mcf.  Both of these percentage figures relate to production net of royalty volumes.  Early in the second quarter, NuVista added approximately 40 MMcf/d of physical natural gas delivery to the US Pacific NW/Northern California markets with the completion of the NGTL Sundre Crossover Pipeline Project.  This was also our first full quarter utilizing the long term fixed priced (LTFP) contract volumes of 45 MMcf/d on the TCPL pipeline to the Dawn hub.  NuVista has also continued to add long term NYMEX basis hedges for terms out as far as 2024.  Combined with our natural gas pipeline export contracts and NYMEX natural gas basis hedges, NuVista has essentially no exposure to AECO natural gas pricing through the full year of 2018 and a maximum AECO natural gas volume exposure range of approximately 15-25% throughout our 60,000 Boe/d growth plan.

Bilbo, Elmworth, and Gold Creek Update

Drilling at Bilbo during the quarter continued as planned with one to two rigs operating and wells being brought on stream to maintain production at or near 18,000 Boe/d.  Pad sizes for new wells currently range from two to five wells per pad.  Four new wells were brought onstream during the quarter, with average IP30’s of 1,972 Boe/d including 46% condensate, or 124 Bbls condensate per MMcf of raw gas. NuVista’s first Lower Montney well which started up at the end of 2017 continues to perform favorably.  This quarter the well reached an IP90 condensate rate of 540 Bbls/d, an excellent outcome as compared to the average of all prior NuVista Middle Montney Bilbo wells at 550 Bbls/day condensate.  The Bilbo compressor station is performing well, with indications of peak-day production capability as high as 20,000 Boe/d as compared to original nameplate capacity of 18,000 Boe/d.

One rig was deployed at Elmworth during the quarter, currently drilling a four-well pad.  Production averaged 14,200 Boe/d for the quarter and is now being restricted to make room for the new Gold Creek wells which have come on stream.

At Gold Creek, volumes have now reached over 5,000 Boe/d.  One to two rigs were active, drilling a delineation/expiry well in the North and a record length two-well pad in the South.  Building upon the operational success from the last extended reach horizontal (ERH) pad at Gold Creek, the horizontal lengths achieved on these wells were 4,500 and 5,000 metres respectively.  The 5,000 metre well is the longest horizontal lateral well ever drilled in Canada. The wells were completed with high intensity fractures (HIFI), placing approximately 2 tonnes of sand per metre of horizontal length, a total of 88 fracture intervals in each well. The average drill and complete cost for each of these two wells was $14.5MM, or $164,000 per stage which is lower than our budgeted average for 2018.

Production from Elmworth is being restricted in order to make room for these new wells which have been brought onstream for initial cleanup flow. We are very pleased to note that the first well has averaged 2,962 Boe/d including 1,056 Bbls/d condensate (condensate gas ratio of 87 Bbls/MMcf) over the first 24 days. The test is particularly encouraging in that gas rates and flowing pressures have been stable to increasing as the high rate of frac water flowback subsides. The upcoming IP90 and IP180 results for these wells will be better indicators of how the first-year capital efficiencies for these ERH wells compare with the historic average.

The Elmworth compressor stations are performing well, handling the production from both Elmworth and Gold Creek wells at the present time.  Drilling continues in Elmworth to keep area production pushing up to and beyond nameplate levels, with 18,000+ Boe/d already achieved versus nameplate capacity of 19,000 Boe/d.  Drilling in Gold Creek will resume later this year in advance of the startup of the new SemCAMS Wapiti gas plant in early-mid 2019.  When the SemCams gas plant starts up, Gold Creek new and existing volumes will be directed there which will provide significant space for continued growth in both Elmworth and Gold Creek.

Year End 2017 Contingent Resource Study Completed

NuVista is pleased to announce that an updated contingent resources report for 2017 year end has been completed by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”), our independent qualified reserves evaluator.  Estimated total gross drilling locations on NuVista’s land base now total 947, including 107 developed locations, 272  proved undeveloped (“PUD”) plus probable undeveloped (“PAUD”) locations and 568 Best Estimate Contingent locations.  Highlights for 2017 are the inclusion of the Lower Montney zone where 150 locations are now booked (1 developed location,  4 PUD+PAUD locations, and  145 Best Estimate Contingent locations) and delineation into Pipestone where 57 Middle Montney zone wells are booked (1 developed location,  36 PUD+PAUD locations, 20 Contingent locations).  Across the three layers of NuVista’s 122,900 acres of land, an average of only 60% of our land has been assigned Reserves or Contingent Resources.  Also of note is that just 30% of our 122,900 gross acres have been assigned Reserves or Contingent Resources in the Lower Montney so far.  New wells are now on average approximately 30% longer than in recent years, therefore the wellcount required for equivalent resource coverage is reduced commensurately.  With 947 gross wells in our Reserves and Contingent Resource, and a drilling pace of 25 to 30 wells per year at our current rate of growth, we have the benefit of long line of sight and ample choice of location to optimize economics as the price of condensate and natural gas varies in future years.

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.  Production for the second quarter of 2018 is anticipated to be in the range of 34,000 – 36,000 Boe/d which includes downtime of approximately 2,000 – 3,000 Boe/d during the quarter for planned outages for routine maintenance at midstreamer facilities and also our NuVista Elmworth compressor station.

Full year 2018 adjusted funds flow is anticipated to be in the range of $210 – $240 million after taking into account 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 strip commodity prices of US$2.78/MMBtu NYMEX natural gas and US$64.00/Bbl WTI oil for the remainder of 2018.  The resulting 2018 net debt to adjusted funds flow ratio is expected to be approximately 1.0 to 1.3 times.

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 May 9, 2018.  NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the first quarter of 2018, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on or before May 9, 2018 and can also be accessed on NuVista’s website.

Corporate Highlights
Three months ended March 31
($ thousands, except per share and per $/Boe) 2018 2017 % Change
FINANCIAL
Petroleum and natural gas revenues 124,756 84,236 48
Adjusted funds flow (1) 58,732 43,254 36
Per share – basic 0.34 0.25 36
Per share – diluted 0.34 0.25 36
Net earnings 22,371 38,317 (42 )
Per share – basic 0.13 0.22 (41 )
Per share – diluted 0.13 0.22 (41 )
Total assets 1,281,475 1,054,272 22
Capital expenditures 115,220 107,412 7
CAPITAL STRUCTURE
Adjusted working capital deficit (1) 43,410 28,116 54
Long-term debt (credit facility) — 60,979 (100 )
Senior unsecured notes 215,207 67,257 220
Total net debt (1) 258,617 156,352 65
Long-term debt (credit facility) capacity 310,000 200,000 55
End of period common shares o/s – basic 174,184 172,774 1
OPERATING
Daily Production
Natural gas (MMcf/d) 132.7 99.7 33
Condensate (Bbls/d) 11,313 8,354 35
NGLs (Bbls/d) (2) 2,667 1,758 52
Total (Boe/d) 36,099 26,731 35
Condensate & NGLs weighting 39 % 38 %
Condensate weighting 31 % 31 %
Average selling prices (3) (4)
Natural gas ($/Mcf) 3.50 3.74 (6 )
Condensate ($/Bbl) 73.69 63.46 16
NGLs ($/Bbl) 33.31 18.82 77
Netbacks ($/Boe)
Petroleum and natural gas revenues 38.40 35.02 10
Realized gain (loss) on financial derivatives (1.63 ) 0.01 —
Royalties (0.56 ) (1.13 ) (50 )
Transportation expenses (2.91 ) (2.51 ) 16
Operating expenses (10.02 ) (10.72 ) (7 )
Operating netback (1) 23.28 20.67 13
Adjusted funds flow netback (1) 18.09 17.98 1
SHARE TRADING STATISTICS
High 9.16 6.39 43
Low 6.78 5.33 27
Close 7.06 6.15 15
Average daily volume 516,466 399,827 29
(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 condensate and NGLs selling price is net of pipeline tariffs and fractionation fees.
Advisories & Contact

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

Drilling Locations
This press release discloses NuVista’s drilling locations in three categories: (i) developed drilling locations; (ii) PUD plus PAUD drilling locations; and (iii) contingent resource drilling locations. Both developed and PUD plus PAUD drilling locations are derived from a report prepared by GLJ, NuVista’s independent qualified reserves evaluator, evaluating NuVista’s reserves as of December 31, 2017, and account for developed and undeveloped drilling locations that have associated proved and/or probable reserves, as applicable. Continent resource drilling locations are derived from the GLJ Report, and account for drilling locations that have associated best estimate contingent resources. There is no certainty that we will drill all drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas 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. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. In the case of the contingent resources estimated in the GLJ Contingent Resource Report, contingencies include: (i) further delineation of interest lands; (ii) corporate commitment, and; (iii) final development plan. To further delineate interest lands additional wells must be drilled and tested to demonstrate commercial rates on the resource lands. Reserves are only assigned in close proximity to demonstrated productivity. As continued delineation drilling occurs, a portion of the contingent resources are expected to be reclassified as reserves. Confirmation of corporate intent to proceed with remaining capital expenditures within a reasonable timeframe is a requirement for the assessment of reserves. Finalization of a development plan including timing, infrastructure spending and the commitment of capital. Determination of productivity levels is generally required before the company can prepare firm development plans and commit required capital for the development of the contingent resources. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources.

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; NuVista’s 60,000 Boe/d growth plan; Bilbo production capability; drilling plans at Gold Creek; the timing of the startup of the new SemCAMS Wapiti Gas Plant and expected capacity of the plant; 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; initial production 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 resources and the imprecision of reserve and resource 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. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the 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 FOFI statements, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP measurements
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 current 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 provided by 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 expense 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 quarterly annualized adjusted funds flow is net debt divided by annualized first quarter adjusted funds flow.