Production of 184 Mboe/d up 26 percent per share, per unit operating and well costs down
CALGARY, ALBERTA--(Marketwired - Nov. 2, 2017) - Seven Generations' strong production growth drove funds from operations to $284.3 million or 78 cents per share in the third quarter of 2017, representing a 22 percent increase in funds from operations per share compared to the same period one year ago. Production averaged 183,920 boe/d in the third quarter of 2017, up 39 percent from the third quarter of 2016, with liquids making up 59 percent of 7G's total production.
THIRD QUARTER HIGHLIGHTS
"We grew production and cash flow per share consistent with our plans and we reduced per unit operating and well construction costs. Our diversified market access helped capture attractive natural gas prices, which, combined with our high liquids yields, generated strong returns on capital. We remain focused on improving our operational performance and executing a development program that achieves industry-leading returns," said Marty Proctor, 7G's President and Chief Executive Officer.
7G's market access strategy contributes to record funds from operations
7G's natural gas marketing portfolio provides geographic takeaway capacity and natural gas pricing optionality across North America - the U.S. Midwest, Gulf of Mexico, Alberta and Eastern Canada. 7G's third quarter realized natural gas price prior to hedging was $3.46 per Mcf, significantly higher than Alberta prices.
Per unit operating costs down 13 percent; drilling and completions costs track lower
7G's cost focus reduced third quarter operating costs to $5.43 per boe, down from $6.24 per boe in the second quarter of 2017. Operating costs are expected to trend to historical levels by early 2018. Third quarter drilling and completing costs were also lower, down 7 percent to $11 million per well compared to the second quarter of 2017, while drilling longer wells and completing them with more fracture stages and sand per well.
2017 THIRD QUARTER FINANCIAL AND OPERATING RESULTS
|Three months ended
|Nine months ended
|2017||2016||% Change||2017||2016||% Change|
|($ millions, except per share and volume data)|
|Natural gas (MMcf/d)||453.2||314.0||44||416.0||276.0||51|
|Condensate and oil ($/bbl)||$ 54.75||49.93||10||$ 58.77||48.16||22|
|Natural gas ($/Mcf)||3.46||3.92||(12)||3.94||3.29||20|
|Liquid and natural gas sales||$||31.30||29.64||6||$||33.33||$||27.06||23|
|Royalty (expense) recovery||(0.86)||(0.04)||nm||(0.89||0.17||nm|
|Transportation, processing and other(2)||(6.07)||(6.12)||(1)||(5.62||(5.39)||4|
|Netback prior to hedging||18.94||19.63||(4)||21.25||17.87||19|
|Realized hedging gain (loss)||0.84||1.58||(47)||0.19||2.75||(93)|
|Operating netback after hedging||$||19.78||21.21||(7)||$||21.44||$||20.62||4|
|General and administrative expenses per boe||$||0.65||1.21||(46)||$||0.75||$||1.06||(29)|
|Selected financial information|
|($ millions, except per share and volume data)|
|Liquids and natural gas revenue||529.5||361.7||46||1,524.0||837.1||82|
|Per share - diluted||$||0.17||$||0.14||21||$||0.54||$||0.37||46|
|Net income (loss) for the period||85.7||(2.2)||nm||479.0||78.8||nm|
|Per share - diluted||$||0.24||$||(0.01)||nm||$||1.31||$||0.26||nm|
|Funds from operations(1)||284.3||211.8||34||824.5||520.0||59|
|Per share - diluted||$||0.78||$||0.64||22||$||2.26||$||1.72||31|
|Cash provided by operating activities||314.1||169.2||86||844.2||465.9||81|
|Total capital investments(3)||454.3||207.7||119||1,329.1||694.2||91|
|Adjusted working capital(1)||77.7||629.3||(88)||77.7||629.3||(88)|
|Weighted average shares - basic||354.4||309.8||14||352.8||283.9||24|
|Weighted average shares - diluted||364.0||329.8||10||364.6||303.1||20|
|(1)||Operating netback, operating income, funds from operations, adjusted working capital, available funding and net debt are not defined under IFRS. See "Non-IFRS Financial Measures" in Management's Discussion and Analysis dated November 1, 2017 for the three and nine months ended September 30, 2017.|
|(2)||Certain comparative figures have been reclassified to conform to current period presentation.|
|(3)||Excluding acquisitions and equity investments.|
DRILLING AND COMPLETIONS
|Three months ended
|Three months ended
|Nine months ended
|Nest Activity||2017||2016||% Change||2017||% Change||2017||2016||% Change|
|Horizontal wells rig released||15||13||15||30||(50)||68||38||79|
|Average measured depth (m)||5,905||5,557||6||5,867||1||5,878||5,716||3|
|Average horizontal length (m)||2,756||2,464||12||2,614||5||2,657||2,614||2|
|Average drilling days per well||33||29||14||36||(8)||35||36||(3)|
|Average drill cost per lateral metre ($)(2)||1,472||1,402||5||1,642||(10)||1,542||1,624||(5)|
|Average well cost ($ millions)(2)||4.0||3.4||18||4.2||(5)||4.0||4.0||-|
|Average number of stages per well||45||33||36||38||18||41||30||37|
|Average tonnes pumped per well||6,425||5,366||20||5,961||8||6,236||4,917||27|
|Average cost per tonne($)(2)||1,094||1,145||(4)||1,282||(15)||1,190||1,115||7|
|Average well cost ($ millions)(2)||7.0||6.2||13||7.6||(8)||7.4||5.5||35|
|Total D&C cost per well ($ millions)(2)||11.0||9.6||15||11.8||(7)||11.4||9.5||20|
|(1)||The drilling and completion counts include only horizontal Montney wells in the Nest. The drilling counts and metrics exclude wells that are re-drilled or abandoned. No wells were abandoned in 2017.|
|(2)||Information provided is based on field estimates and is subject to change.|
Drilling costs per well down 5 percent compared to the second quarter
7G's average drilling cost per well was $4 million in the third quarter of 2017, down from $4.2 million in the second quarter of 2017. 7G's key drilling metric of dollars per lateral metre drilled averaged $1,472 in the third quarter, representing a 10 percent improvement compared to the second quarter of 2017.
Completion costs per well down 8 percent compared to the second quarter
7G's average completion cost per well was $7 million in the third quarter of 2017, down from $7.6 million in the second quarter of 2017. Completions efficiencies were driven by improved water sourcing logistics and a deliberate move to work with fewer and more efficient business partners. Seven Generations is incorporating higher stage counts per well in its completion design, with a third quarter average per well of 45 stages and approximately 6,400 tonnes of proppant. 7G has observed a strong positive relationship between well productivity and stage count, therefore these higher stage count wells are expected to result in above average production rates and economics.
The total average drilling and completion cost per well was $11.0 million in the third quarter of 2017, down from $11.8 million in the second quarter of 2017. Seven Generations continues to pursue ways to drive down costs in both drilling and completions to maximize capital efficiencies.
With an average of seven drilling rigs running in the third quarter, Seven Generations drilled 18 wells, completed 25 wells and brought 39 wells on production. At the end of the third quarter, 7G had 56 wells in various stages of construction between drilling, completion and tie-in. This well inventory reflects the 2017 plan and the number of rigs running at various times during the year.
Seven Generations maintained a strong financial position with available funding of $1.4 billion and net debt of $1.9 billion as of September 30, 2017. 7G plans to fund the remainder of its 2017 capital program through a combination of cash on hand, funds from operations and draws on its credit facility. Reaching a self-funding state, where cash flow is equivalent to or greater than capital investment, remains a key focus for 7G.
Seven Generations continues to deliver on its disciplined, rolling three-year hedging program with a significant portion of its AECO-exposed volumes currently hedged at a minimum price of $2.50 per gigajoule. 7G had the following risk management contracts as at September 30, 2017:
|Crude Oil||Natural Gas||Foreign Exchange|
|WTI Collars||WTI 3 Way Collars||Chicago Citygate Swaps||AECO 7A Collars||CAD/USD Swaps|
|Period||bbl/d||C$/bbl||bbl/d||C$/bbl||MMBtu/d||US$/ MMBtu||GJ/d||C$/GJ||USD $MM||US$/C$|
|2017 remainder||15,000||$63.94 - $77.39||9,000||$41.11/$56.67/$76.83||220,000||$2.96||60,000||$2.50 - $3.03||59.9||1.3085|
|2018||15,250||$61.69 - $78.23||12,000||$40.83/$56.25/$75.54||185,000||$2.89||50,000||$2.50 - $2.99||195.3||1.3165|
|2019||12,000||$59.38 - $77.81||7,500||$41.00/$56.33/$75.92||100,000||$2.88||50,000||$2.50 - $2.99||105.0||1.2992|
|2020||3,000||$57.50 - $73.33||1,500||$40.00/$55.00/$70.98||12,500||$2.77||-||-||12.6||1.3039|
Debt refinancing will save 7G about $25 million per year
In September, 7G commenced a refinancing transaction to issue US$700 million of 5.375% senior unsecured notes due in 2025. This refinancing, which was completed in October, also retired US$700 million of 8.25% senior unsecured notes due in 2020. The debt refinancing will result in annual interest savings of about $25 million and extend the note's maturity by five years.
The improved terms and costs will provide 7G with greater financial flexibility in the years ahead with 7G's currently undrawn $1.4 billion credit facility maturing in 2021 and its earliest senior unsecured note maturity now in 2023.
As 7G continues evolving, it is vital to the success of the organization that all aspects of strategy be carefully led, including the management of risks around core development, the delineation of future inventory opportunities and the evaluation of processing, infrastructure and market development. In order to place increasing focus on the management of 7G's strategic objectives, Chris Law will take on a new role as Executive Vice President, Strategy Management. Chris will serve as Chief Financial Officer until a new CFO is appointed.
"Chris is an important member of the Seven Generations leadership team. He has played a key role in devising and financing the strategy that has helped bring 7G to where we are today. As we move forward, Chris will help increase our focus on the key strategic initiatives that are crucial to advancing our business and our future success," Proctor said.
Capital investments were $454.3 million in the third quarter, totaling $1.3 billion year to date. As previously announced, Seven Generations experienced well cost inflation in the first half of the year. 7G has also proactively placed early orders for compressors for Super Pad construction to avoid installation delays in 2018 due to the increasing delivery times for field equipment. In order to combat cost creep, 7G has taken several focused steps in the second half of the year as discussed in the operations highlights section and will focus on efficiencies in well cycle times. Expected capital expenditures on the base investment program have moved to the high end of 7G's annual capital investment guidance of $1.5 to $1.6 billion.
Beyond that, opportunities exist for advancement of key 2018 investments, which combined with the base investment program, are expected to result in fourth quarter capital spending of $300 to $350 million, bringing full-year 2017 capital investment to approximately $1.65 billion. Key initiatives added to 2017 include the development of a five-well pad in 7G's core Nest 1 area. This pad is designed to provide important tests in both inter-well spacing and an upgraded completions design. In addition, expanded investments in water infrastructure related to 2018 completions are anticipated to be completed in the fourth quarter. 7G is also adding new pipe infrastructure that interconnects several gas gathering systems. This connection is expected to be completed in the second quarter of 2018 and will provide 7G with the option to send natural gas into either the Alliance pipeline system or the NGTL pipeline system to optimize natural gas and natural gas liquids price realizations as well as build contingent market access options should there be processing plant disruptions.
The 2018 capital budget is expected to be approved and announced on Wednesday, November 15, 2017. An investor day will be held on Thursday, November 16, 2017 from 8:30 a.m. to 12:30 p.m. at the Metropolitan Centre in Calgary. Details are available on www.7genergy.com.
7G management will hold a conference call to discuss results and address investor questions today, November 2, 2017 at 9 a.m. MT (11 a.m. ET).
|Participant Dial-In Numbers|
|Toll Free:||(877) 390-7644|
|Conference Call ID:||90497992|
|Encore Dial In:||(855) 859-2056 or (404) 537-3406|
|Available:||November 2 - 9, 2017|
Seven Generations Energy
Seven Generations is a low-supply-cost, high-growth Canadian energy developer generating long-life value from its liquids-rich Kakwa River Project, located about 100 kilometres south of its operations headquarters in Grande Prairie, Alberta. 7G's corporate headquarters are in Calgary and its shares trade on the TSX under the symbol VII.
Further information on Seven Generations is available on the company's website: www.7genergy.com.
Non-IFRS Financial Measures and Other Measures
This news release includes certain terms or performance measures commonly used in the oil and natural gas industry that are not defined under IFRS, including "funds from operations", "operating income", "operating netback", "available funding", "net debt" and "adjusted working capital". Operating netback has been calculated on a per boe basis and is determined by deducting royalties, operating and transportation, processing and other expenses from oil and natural gas revenue and, except where otherwise indicated, after adjusting for realized hedging gains or losses. Operating netback is utilized by the company and others to better analyze the operating performance of its oil and natural gas assets. The data presented are intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These non-IFRS measures should be read in conjunction with the company's financial statements and accompanying notes. Readers are cautioned that the non-IFRS measures do not have any standardized meaning and should not be used to make comparisons between the company and other companies without also taking into account any differences in the way the calculations were prepared.
For more information regarding "funds from operations", "operating income", "operating netback", "available funding", "net debt" and "adjusted working capital" see "Non-IFRS Financial Measures" in the company's Management's Discussion and Analysis dated November 1, 2017.
All dollar amounts are presented in Canadian Dollars unless otherwise specified. Per share amounts are presented on a diluted basis.
This news release contains certain forward looking information and statements that involve various risks, uncertainties and other factors. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "should", "believe", "plans", and similar expressions are intended to identify forward looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the company's focus on improving operating performance and achieving industry leading returns; the expectation that operating costs will trend toward historic levels by early 2018; the expectation that increased stage counts in the company's completions design will result in above average production rates and economics; the pursuit of future cost reductions in drilling and completions to maximize capital efficiencies; expected sources of funding; pursuit of cash flow self-sufficiency; the interest savings that will result from the note refinancing transaction that was completed in October; expanded investments in 2017 in water infrastructure related to 2018 completions; the addition of new pipe infrastructure and interconnects in the second quarter of 2018 which are expected to provide market access optionality and help the company optimize gas realizations; expected capital investments in the fourth quarter and for the full year in 2017; and the timing of the announcement of the company's 2018 capital budget and investor day.
With respect to forward-looking information contained in this news release, assumptions have been made regarding, among other things: future oil, NGLs and natural gas prices being consistent with current commodity price forecasts after factoring in quality adjustments at the company's points of sale; the company's continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; drilling and completions techniques and infrastructure and facility design concepts that have been successfully applied by the company elsewhere in its Kakwa River Project may be successfully applied to other properties within the Kakwa River Project; the consistency of the regulatory regime and framework governing royalties, taxes and environmental matters in the jurisdictions in which the company conducts its business and any other jurisdictions in which the company may conduct its business in the future; the company's ability to market production of oil, NGLs and natural gas successfully to customers; the company's future production levels and amount of future capital investment will be consistent with the company's current development plans and budget; the applicability of new technologies for recovery and production of the company's reserves and resources may improve capital and operational efficiencies in the future; the recoverability of the company's reserves and resources; sustained future capital investment by the company; future cash flows from production; the future sources of funding for the company's capital program; the company's future debt levels; geological and engineering estimates in respect of the company's reserves and resources; the geography of the areas in which the company is conducting exploration and development activities, and the access, economic, regulatory and physical limitations to which the company may be subject from time to time; the impact of competition on the company; and the company's ability to obtain financing on acceptable terms.
Actual results could differ materially from those anticipated in the forward-looking information that is contained herein as a result of the risks and risk factors that are set forth in the annual information form for the year ended December 31, 2016 dated March 7, 2017, which is available on SEDAR at www.sedar.com, including, but not limited to: volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; general economic, business and industry conditions; variance of the company's actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; risks related to the exploration, development and production of oil and natural gas reserves and resources; negative public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities, including changes in government regulation, royalties and taxation; potential legislative and regulatory changes; the rescission, or amendment to the conditions, of groundwater licenses of the company; management of the company's growth; the ability to successfully identify and make attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions or businesses; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; adoption or modification of climate change legislation by governments; the absence or loss of key employees; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the company does not control; the ability to satisfy obligations under the company's firm commitment transportation arrangements; the uncertainties related to the company's identified drilling locations; the high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; the risks of fires, floods and natural disasters; the possibility that the company's drilling activities may encounter sour gas; execution risks associated with the company's business plan; failure to acquire or develop replacement reserves; the concentration of the company's assets in the Kakwa River Project; unforeseen title defects;
aboriginal claims; failure to accurately estimate abandonment and reclamation costs; development and exploratory drilling efforts and well operations may not be profitable or achieve the targeted return; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves or production; limited intellectual property protection for operating practices and dependence on employees and contractors; third-party claims regarding the company's right to use technology and equipment; expiry of certain leases for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties acquired now or in the future to produce as projected and inability to determine reserve and resource potential, identify liabilities associated with acquired properties or obtain protection from sellers against such liabilities; changes in the application, interpretation and enforcement of applicable laws and regulations; restrictions on drilling intended to protect certain species of wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the company's activities and the oil and gas industry; alternatives to and changing demand for petroleum products; extensive competition in the company's industry; changes in the company's credit ratings; third party credit risk; dependence upon a limited number of customers; lower oil, NGLs and natural gas prices and higher costs; failure of 2D and 3D seismic data used by the company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedging instruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; security deposits required under provincial liability management programs; reassessment by taxing authorities of the company's prior transactions and filings; variations in foreign exchange rates and interest rates; risks associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential litigation; variation in future calculations of non-IFRS measures; sufficiency of internal controls; breach of agreements by counterparties and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of the company to respond quickly to competitive pressures; and the risks related to the company's common shares that are publicly traded and the company's senior notes and other indebtedness.
Definitions and Abbreviations
Terms and abbreviations that are used in this news release that are not otherwise defined herein are provided below:
|AECO||physical storage and trading hub for natural gas on the TransCanada Alberta transmission system which is the delivery point for various benchmark Alberta index prices|
|bbl or bbls||barrel or barrels|
|boe||barrels of oil equivalent(1)|
|C$or CAD||Canadian dollars|
|D&C||drilling and completions|
|IFRS||International Financial Reporting Standards|
|mbbl||thousands of barrels|
|mboe||thousands of barrels of oil equivalent(1)|
|Mcf||thousand cubic feet|
|MMBtu||million British thermal units|
|MMcf||million cubic feet|
|Nest||means the primary development block of the Kakwa River Project|
|Nest 1||the "Nest 1" area that is shown in the corporate presentation available on 7G's website|
|NGLs||natural gas liquids|
|NGTL||Nova Gas Transmission Ltd.|
|nm||not meaningful information|
|SEDAR||System for Electronic Document Analysis and Retrieval|
|TSX||Toronto Stock Exchange|
|US$or USD||United States dollars|
|WTI||West Texas Intermediate|
Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven Generations Energy, 7G or the company.
(1) Seven Generations has adopted the standard of 6 Mcf: 1 bbl when converting natural gas to boes. Condensate and other NGLs are converted to boes at a ratio of 1 bbl: 1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based roughly on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the company's sales point. Given the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.
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