CALGARY, Alberta, Nov. 12, 2018 (GLOBE NEWSWIRE) — NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three and nine months ended September 30, 2018 and provide an update on its future business plans. NuVista experienced another robust quarter with continued development drilling success. Production and adjusted funds flow increased significantly, reaching record levels due to strong well and facility performance, and additional acquired volumes, despite planned outages.
NuVista is continuing to deliver as planned on our 2018 drilling program. We have kept our Bilbo and Elmworth facilities essentially full during the third quarter, and we continue to push them further. We have been making impactful progress in Gold Creek development as we now begin to prepare pads for the spring startup of the Wapiti SemCAMS gas plant. We possess a material position in the condensate-rich Wapiti Montney play, and we have significantly augmented that position during the third quarter with the previously announced acquisition in the Pipestone area (the “Acquired Assets”). We aim to deliver strong financial returns to shareholders today and over the long term. As our production has continued to increase at a measured pace, every area of our business is demonstrating improving efficiencies as planned.
These past months have certainly been volatile, with significant commodity price and product differential fluctuations. We continue to derive stability from our ongoing hedging program and also our natural gas sales diversification efforts. With our prudent focus on balance sheet strength, we maintain flexibility to adjust capital spending and pace of growth commensurate with the business environment while adhering to our long term value creation and profitability objectives.
Significant Operating Highlights
- Achieved a record in the third quarter of 2018 with production of 40,080 Boe/d including 32% condensate, above the top of our third quarter guidance range of 37,500 to 39,000 Boe/d. This is 11% above second quarter 2018 production and 36% above the third quarter of 2017. This result is due to strong recent well and facility performance as well as the partial contribution in the quarter from the Acquired Assets of approximately 2,950 Boe/d. These increases were partially offset by planned and unplanned outages at midstream facilities resulting in a reduction of 2,225 Boe/d for the quarter;
- Achieved adjusted funds flow of $72.6 million ($0.39/share, basic) for the third quarter, as compared to $69.5 million ($0.40/share, basic) for the prior quarter due to improved production, offset slightly by hedging losses, one-time acquisition transaction costs of $2.6 million, and (for the per share metrics only) the issuance of common shares for the Acquired Assets. This third quarter adjusted funds flow result represents a 75% increase compared to the third quarter of 2017, and an increase of 63% in adjusted funds flow per share versus the same period;
- Successfully executed an active third quarter capital program of $65.8 million, with rig-release of 7.0 (6.9 net) wells in our Wapiti Montney condensate rich resource play;
- Achieved a number of new well production milestones with improving results, as detailed below;
- Achieved third quarter operating costs of $9.82/Boe. This result is down 5% from the prior quarter, and down 4% from the third quarter of 2017, as we continue on our multi-year trend of reducing operating costs in our Montney play;
- Delivered G&A costs in line with our expectations at $1.18/Boe, a reduction of 14% from the prior quarter, and down 22% compared to the third quarter of 2017 due to increased efficiency and higher production levels; and
- Exited the third quarter of 2018 with net debt of $493 million, including credit facility borrowings of $278 million versus our facility limit of $450 million. The credit facility was increased from $310 million during the quarter upon closing of the transaction for the Acquired Assets. NuVista concluded the third quarter with a ratio of net debt to annualized current quarter funds from operations of 1.7 times. This metric is 1.5 times if one takes into account a pro forma view if the Acquired Assets had been contributing for the entire third quarter.
Gold Creek
Production at Gold Creek averaged approximately 9,000 Boe/d with 30% condensate in Q3. These volumes will be directed to the new SemCAMS Wapiti gas plant upon startup. The latest two ERH wells have now passed the IP90 mark and are outperforming the previous average by two-fold, averaging 2,397 Boe/d per well at 32% condensate. Four additional wells have been drilled and are awaiting completion operations in Q1 2019 in advance of the Wapiti plant startup. Plant commissioning is still planned to commence during the first quarter of 2019, with incremental NuVista volumes from the four-well pad expected to contribute sometime in the second quarter depending on spring breakup conditions. The next four-well pad in Gold Creek is scheduled to spud early in the first quarter of 2019.
Elmworth
Elmworth production averaged approximately 10,000 Boe/d with 23% condensate in the third quarter. Drilling will commence late in the fourth quarter on a three-well pad that will offset the volumes from Gold Creek which will move out of the Elmworth compressor station to the new Wapiti plant at the end of the first quarter of 2019. The first two high fracture intensity (HiFi) completions have reached the IP365 mark and averaged 1,440 Boe/d over their first year which is 90% greater than the previous average including over double the first year condensate rate at 361 Bbl/d. This result continues to underpin the progression to a shallowing base decline and improved capital efficiency for the area.
Combined production at Gold Creek and Elmworth was impacted by an unscheduled 7 day outage at the SemCAMS K3 plant which reduced third quarter volumes by approximately 825 Boe/d. In November, total combined production from the two areas continues at over 20,000 Boe/d.
Bilbo
Bilbo production averaged approximately 17,700 Boe/d with 40% condensate for the quarter. Operations included the successful completion of a three-well pad and the drilling of a five-well pad which is currently being completed. A four-well pad, including two Lower Montney wells, is currently drilling and will be completed and brought on stream in the first quarter of 2019 in order to maintain production at full capacity. In addition, a successful gas-lift pilot project has been implemented in order to maximize rates for heritage producing wells with high liquids content. The project has seen early success and we expect it to contribute to the continued reduction in the base decline of the asset.
Production at Bilbo was restricted for 7 days due to a scheduled outage at the Keyera Simonette Plant, impacting the quarter by 1,400 Boe/d total.
Pipestone
The third quarter marked a significant turning point for NuVista’s Pipestone area as we kicked off the Pipestone South development and also completed a major acquisition at Pipestone North with the purchase of the Acquired Assets.
At NuVista’s pre-existing land block, Pipestone South, we announced the commencement of construction of our new Pipestone South compressor station after receiving approval from the Alberta Energy Regulator. The facility design has been upsized from the original 10,000 Boe/d to 15,000 Boe/d. The upsize is a result of augmented drilling inventory after continued positive drilling results by NuVista and competitors in the area within several of the Montney layers. NuVista has commenced construction of our first pad site. The first will be an 8-well cube development where we are planning on drilling up to four Montney layers. The compressor station and this first pad have been targeted to come on stream in mid fourth quarter 2019.
The completion of the acquisition at Pipestone North has gone smoothly, and the integration of the new staff and assets is proceeding well. Production from the Acquired Assets has met or exceeded expectations, contributing approximately 2,950 Boe/d in the third quarter (or approximately 10,800 Boe/d for 25 days after closing of the transaction for the Acquired Assets). Production volumes in Pipestone North have been kept flat for the time being, as we offset natural declines by bringing on wells that were temporarily shut-in to make room for the most recent pad. As noted in our November 1 press release, the first egress solution for Pipestone North has been secured and development drilling may commence as early as the fourth quarter of 2019. NuVista has signed flexible agreements with Veresen Midstream Limited Partnership (“VMLP”) and Pembina Pipeline (“Pembina”) for raw gas and liquids processing from Pipestone North, including the transportation to market of all sales products including natural gas, condensate, and C3+. Also included was a fractionation agreement for the C3+ at Pembina’s Redwater facility. The capacity is to be provided with flexible take-or-pay terms in two tranches of 50 MMcf/d raw gas separated by one year, the first commencing in late 2020. Half of the second tranche may be deferred from 2021 to 2022 at NuVista’s option. To further bolster balance sheet flexibility, NuVista has the option to have VMLP fund the planned Pipestone North compressor station, which NuVista will construct and operate. And finally, NuVista has entered into an agreement with a third party to deliver the sales gas associated with the first tranche of 50 MMcf/d raw to Chicago via Alliance Pipeline, further diversifying our natural gas sales exposure.
We continue to focus on first year capital efficiency, condensate proportion, recycle ratio, and striving for half-cycle payouts below one year as primary measures of economic well performance. Together with our pre-existing capacity, the preceding has advanced our firmly contracted processing and egress capacity to 90,000 Boe/d, a significant milestone on our planned journey to 110,000 Boe/d.
Commodity Price Risk Management Continues to Benefit NuVista
NuVista continues to benefit from the discipline of our strong hedging program during this period of volatile commodity prices. This has been a challenging summer for AECO, with spot natural gas prices under pressure due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system. We are pleased to report that there was virtually no impact to NuVista pricing as a result of these restrictions and price reductions. We currently possess hedges which in aggregate cover 66% of remaining 2018 projected liquids production at a floor WTI price of C$ 72.62/Bbl, and 58% of remaining 2018 projected gas production at a price of C$ 2.57/Mcf. Due to our fixed price hedges, basis hedges, and our export pipeline volumes, NuVista has less than 14% of our natural gas volumes exposed to spot AECO prices in the fourth quarter of 2018, and 32% in 2019. We have good diversification away from AECO dependence while maintaining winter gas price upside exposure through Nymex. We currently possess WTI hedges for 2019 on 50% of oil & condensate production at a floor price of C$ 80.48/Bbl while gas is hedged at 32% of expected production at a floor price of C$ 2.20/Mcf. All of these percentage figures relate to forecast production net of royalty volumes.
WCS Heavy oil differentials averaged at a US$ 22.25/Bbl discount to WTI in the third quarter of 2018 while Edmonton light sweet and condensate averaged a US$ 6.76/Bbl and US$ 2.68/Bbl discount to WTI respectively. Significant growth in heavy oil production continues in Western Canada. With fall refinery maintenance lowering demand, coupled with high local storage levels and a lack of new export pipeline capacity, there has been significant pressure on heavy oil prices heading into the fourth quarter of 2018. High levels of apportionment on local feeder pipelines and export pipelines have also led to a significant widening of differentials including light sweet and condensate differentials. Heavy oil differential futures have exceeded a US$ 40/Bbl discount to WTI going into late fourth quarter 2018. The light sweet discount has been over US$ 30/Bbl, and condensate has been in the US$ 10-20/Bbl range for the fourth quarter. The long term solution is new export pipeline capacity which will begin with the Enbridge Line 3 replacement project which is expected to be operational in the latter part of 2019. In the short term industry will need to ramp up volumes by rail to get additional volumes to market and may need to curb production volumes. This should lead to moderating differentials in the coming months for heavy oil and in turn for light oil and condensate. Condensate discounts may stay wider than normal for the next few months as industry adjusts, however longer term industry in Alberta continues to have a significant condensate supply shortfall relative to demand. As a result, significant volumes are expected to continue to be imported from the U.S.A. which should lead back to the condensate differential premiums which have typically been experienced.
2019 Guidance Provided and 2018 Guidance Reaffirmed
We are pleased to reaffirm our 2018 production guidance in the range of 38,750 to 40,000 Boe/d. This includes fourth quarter guidance unchanged at 46,000 to 48,500 Boe/d. 2018 adjusted funds flow is also reaffirmed in the range of $260 to $270 million based on current strip pricing1. Our 2018 capital plan remains unchanged in the range of $325 – $350 million.
Given the recent widening of commodity price differentials and a sentiment of capital market uncertainty, we have elected to maintain maximum flexibility in spending commitments for 2019 and beyond. While we have made commitments which allow us to pursue a pace of growth to over 90,000 boe/d in the next few years, we will continue to monitor the economic environment prior to pursuing that rapid pace. As such, we are moderating our 2019 production and capital guidance ranges and we will also maintain them within a broad band for the time being. 2019 capital expenditure expectations are reduced to the range of $300 to $400 million depending on commodity prices and the pace of growth ultimately selected for 2020. This level of reduced spending enables us to maintain maximum financial flexibility heading into 2019. As we move through the year, should commodity prices improve over what we are currently forecasting, we will consider reinstating our original growth plans.
The corresponding 2019 production is expected to be in the range of 52,000 to 56,000 Boe/d, approximately 37% higher than 2018. This forecast includes the impact of a planned outage at SemCAMS K3 plant in the first quarter of 2019. The resulting first quarter production guidance is approximately 43,500 to 46,000 Boe/d, including 4,000 Boe/d of planned downtime. Compared to our prior outlook for 2019, the foregoing represents a midpoint capital guidance reduction of 27% accompanied by a midpoint production guidance reduction of 3.5%.
Given top quality assets and a management team focused upon relentless improvement, NuVista will continue to optimize well results, improve margins, and grow our production profitably toward our long term goal of 110,000 Boe/d. We will do so at a pace which remains in tune with the economic environment and maximizes our return on every dollar invested. 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 guidance and support as we build an ever more valuable future for NuVista.
Please note that our corporate presentation is being updated and will be available at www.nuvistaenergy.com on November 12, 2018. NuVista’s third quarter 2018 condensed interim financial statements and notes to the financial statements and management’s discussion and analysis will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on November 12, 2018 and can also be accessed on NuVista’s website.
1 Strip pricing assumptions for 4Q 2018: WTI $US68.00/Bbl, NYMEX Gas $US3.14/MMBTU, AECO gas $2.05/GJ, CAD:USD 1.3083 FX
| Corporate Highlights | ||||||||||||||||
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||
| ($ thousands, except per share and $/Boe) | 2018 | 2017 | % Change | 2018 | 2017 | % Change | ||||||||||
| FINANCIAL | ||||||||||||||||
| Petroleum and natural gas revenue | 150,956 | 83,100 | 82 | 412,843 | 246,737 | 67 | ||||||||||
| Adjusted funds flow (1) (2) | 72,610 | 41,526 | 75 | 200,813 | 124,098 | 62 | ||||||||||
| Per share – basic | 0.39 | 0.24 | 63 | 1.12 | 0.72 | 56 | ||||||||||
| Per share – diluted | 0.38 | 0.24 | 58 | 1.12 | 0.71 | 58 | ||||||||||
| Net earnings (loss) | 3,467 | (4,366 | ) | (179 | ) | 32,159 | 59,718 | (46 | ) | |||||||
| Per share – basic | 0.02 | (0.03 | ) | (167 | ) | 0.18 | 0.35 | (49 | ) | |||||||
| Per share – diluted | 0.02 | (0.03 | ) | (167 | ) | 0.18 | 0.34 | (47 | ) | |||||||
| Total assets | 2,063,558 | 1,160,031 | 78 | |||||||||||||
| Assets acquired | 617,765 | 326 | — | 617,765 | 560 | — | ||||||||||
| Capital expenditures | 65,817 | 97,981 | (33 | ) | 263,359 | 274,643 | (4 | ) | ||||||||
| Net debt (1) (2) | 493,344 | 233,713 | 111 | |||||||||||||
| End of period basic common shares o/s | 225,142 | 173,598 | 30 | |||||||||||||
| OPERATING | ||||||||||||||||
| Daily Production | ||||||||||||||||
| Natural gas (MMcf/d) | 143.3 | 109.3 | 31 | 134.8 | 100.3 | 34 | ||||||||||
| Condensate & oil (Bbls/d) | 12,819 | 9,273 | 38 | 11,969 | 8,773 | 36 | ||||||||||
| NGLs (Bbls/d) (3) | 3,385 | 1,908 | 77 | 2,984 | 1,723 | 73 | ||||||||||
| Total (Boe/d) | 40,080 | 29,405 | 36 | 37,419 | 27,206 | 38 | ||||||||||
| Condensate, oil & NGLs weighting | 40 | % | 38 | % | 40 | % | 39 | % | ||||||||
| Condensate & oil weighting | 32 | % | 32 | % | 32 | % | 32 | % | ||||||||
| Average selling prices (4) (5) | ||||||||||||||||
| Natural gas ($/Mcf) | 3.41 | 3.43 | (1 | ) | 3.43 | 3.62 | (5 | ) | ||||||||
| Condensate & oil ($/Bbl) | 80.74 | 51.94 | 55 | 78.95 | 57.31 | 38 | ||||||||||
| NGLs ($/Bbl) | 34.61 | 24.63 | 41 | 35.38 | 22.36 | 58 | ||||||||||
| Netbacks ($/Boe) | ||||||||||||||||
| Petroleum and natural gas revenues | 40.94 | 30.72 | 33 | 40.41 | 33.22 | 22 | ||||||||||
| Realized gain (loss) on financial derivatives | (3.65 | ) | 1.22 | — | (2.71 | ) | 0.61 | — | ||||||||
| Royalties | (1.43 | ) | (0.85 | ) | 68 | (1.12 | ) | (0.99 | ) | 13 | ||||||
| Transportation expenses | (3.09 | ) | (2.51 | ) | 23 | (3.12 | ) | (2.71 | ) | 15 | ||||||
| Operating expenses | (9.82 | ) | (10.26 | ) | (4 | ) | (10.06 | ) | (10.53 | ) | (4 | ) | ||||
| Operating netback (2) | 22.95 | 18.32 | 25 | 23.40 | 19.60 | 19 | ||||||||||
| Corporate netback (2) | 19.69 | 15.36 | 28 | 19.63 | 16.72 | 17 | ||||||||||
| SHARE TRADING STATISTICS | ||||||||||||||||
| High | 9.57 | 8.02 | 19 | 9.89 | 8.02 | 23 | ||||||||||
| Low | 6.99 | 5.91 | 18 | 6.69 | 5.33 | 26 | ||||||||||
| Close | 7.50 | 7.55 | (1 | ) | 7.50 | 7.55 | (1 | ) | ||||||||
| Average daily volume | 656,805 | 393,134 | 67 | 576,795 | 458,424 | 26 | ||||||||||
(1) Refer to Note 14 “Capital Management” in NuVista’s financial statements and to the sections entitled “Adjusted funds flow” and “Liquidity and capital resources” contained in NuVista’s MD&A.
(2) See “Non-GAAP measurements”.
(3) Natural gas liquids (“NGLs”) include butane, propane and ethane.
(4) Product prices exclude realized gains/losses on financial derivatives.
(5) The average condensate and NGLs selling price is net of pipeline 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
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 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”, “IP60”, “IP90” and “IP180” is defined as the estimated average producing day rate over the initial first 30, 60, 90, and 180 days of production, respectively. 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; plans to deliver future financial returns to shareholders; continued improved efficiencies; the benefits of NuVista’s hedging program and natural gas sales diversification efforts; drilling and completion plans; the timing of the startup of the new SemCAMS Wapiti Gas Plant; the impact of the gas lift pilot project at Bilbo; the timing of completion of the compression station at Pipestone; future exposure to spot AECO prices; future differentials; 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; 2018 and 2019 annual production, capital expenditure and adjusted funds flow guidance; the impact of the planned outage at SemCAMS K3; plans to continue to optimize well results, and plans to improve margins and grow production to NuVista’s 110,000 Boe/d goal 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 financial outlook information ( “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 this 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”, “annualized current quarter adjusted funds flow”,”net debt”, “net debt to annualized current quarter adjusted funds flow”, “operating netback”, and “corporate netback”, to analyze 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 performance on a comparable basis with prior periods and to analyze the liquidity of NuVista.
Adjusted funds flow
NuVista considers adjusted funds flow to be a key measure that provides a more complete understanding of the Company’s ability to generate cash flow necessary to finance capital expenditures, expenditures on asset retirement obligations, and meet its financial obligations. NuVista has calculated adjusted funds flow based on cash flow provided by operating activities, excluding changes in non-cash working capital, asset retirement expenditures and environmental remediation recovery, as management believes the timing of collection, payment, and occurrence is variable and by excluding these items from the calculation, management is able to provide a more meaningful performance measure. More specifically, expenditures on asset retirement obligations may vary from period to period depending on the Company’s capital programs and the maturity of its operating areas, while environmental remediation recovery relates to an incident that management doesn’t expect to occur on a regular basis. The settlement of asset retirement obligations is managed through NuVista’s capital budgeting process which considers its available adjusted funds flow. 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 (loss) 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 (loss) per share.
Net debt
Net debt is used by management to provide a more complete understanding of the Company’s capital structure and provides a key measure to assess the Company’s liquidity. NuVista has calculated net debt based on cash and cash equivalents, accounts receivable and prepaid expenses, accounts payable and accrued liabilities, accrued environmental remediation liabilities, long term debt (credit facility) and senior unsecured notes.
Operating netback and corporate netback (“netbacks”)
NuVista reports netbacks on a total dollar and per Boe basis. Operating netback is calculated as petroleum and natural gas revenues including realized financial derivative gains/losses, less royalties, transportation and operating expenses. Corporate netback is operating netback less general and administrative, deferred share units, and interest expense. Management feels these netbacks are key industry benchmarks and measures of performance for NuVista that provides investors with information that is commonly used by other petroleum and natural gas producers. The measurement on a Boe basis assists management and investors with evaluating NuVista’s operating performance on a comparable basis.
FOR FURTHER INFORMATION CONTACT:
| Jonathan A. Wright President and CEO (403) 538-8501 |
Ross L. Andreachuk VP, Finance and CFO (403) 538-8539 |
Mike J. Lawford Chief Operating Officer (403) 538-1936 |
