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Seven Generations Delivers Funds from Operations of $434 Million, $1.19 Per Share, in Second Quarter of 2018

August 03, 2018


  • Funds from operations of $434 million or $1.19 per share, up 62 percent and 63 percent respectively compared to the same periods in 2017. Cash provided by operating activities of $425.2 million, up 119 percent from the same period in 2017.
  • 7G’s realized pricing increased 26 percent compared to the first quarter of 2018. Increasing condensate production, coupled with higher commodity prices, drove the corporate netback to $25.49 per boe, representing an increase of 43 percent from the second quarter in 2017.
  • Condensate production of 69,000 bbls/d and total liquids production of 110,200 bbls/d, up 17 percent and 14 percent respectively from the second quarter of 2017. Natural gas production was 461 MMcf/d, an increase of 13 percent compared to the second quarter of 2017.
  • 7G’s long-term focus on diversified market access saw realized natural gas pricing at $3.79 per Mcf, more than $2.50 per Mcf higher than AECO pricing during the quarter. 
  • A trailing 12-month return on capital employed of 12.1 percent and a cash return on invested capital of 18.8 percent.
  • Continued financial strength with a trailing 12-month ratio of net debt to funds from operations of 1.5x.

“Our second quarter results highlight the cash flow generating capacity of our business. We continue to see our production mix tilting towards the highest value production stream in Canada – condensate. With higher than expected condensate production and pricing, we are earning higher rates of return and generating more cash flow than anticipated. This accelerated free cash flow profile provides us with significant optionality as we head into our annual budgeting process,” said Marty Proctor, 7G’s President & Chief Executive Officer.



($ millions, except boe and per share amounts) (1) Three months ended
June 30,
Three months ended
March 31,
Six months ended
June 30,
  2018 2017 %
2018 %
2018 2017 %
Condensate (mbbl/d)(3) 69.0 59.0 17 67.3 3 68.1 55.3 23
NGLs (mbbl/d)(3) 41.2 37.9 9 41.5 (1) 41.4 37.7 10
Liquids (mbbl/d) 110.2 96.9 14 108.8 1 109.5 93.0 18
Natural gas (MMcf/d) 461.3 409.6 13 473.3 (3) 467.3 397.1 18
Total Production (mboe/d)(4) 187.1 165.2 13 187.7 0 187.4 159.2 18
Liquids % 59% 59% 58% 2 58% 58%
Realized prices                
Condensate ($/bbl) 81.67 58.28 40 73.39 11 77.67 60.90 28
Natural gas ($/Mcf) 3.79 4.09 (7) 3.54 7 3.73 4.22 (12)
NGLs ($/bbl) 13.39 11.45 17 13.33 0 13.35 11.91 12
Total ($/boe)(3)(4) 42.42 33.58 26 38.19 11 40.46 34.50 17
Royalty expense ($/boe) (0.96) (0.62) 55 (1.12) (14) (1.04) (0.91) 14
Operating expenses ($/boe) (6.00) (6.24) (4) (5.73) 5 (5.87) (5.65) 4
Transportation, processing and other ($/boe) (6.93) (5.88) 18 (6.24) 11 (6.72) (5.66) 19
Operating netback before the following(4) 28.53 20.84 37 25.10 14 26.83 22.28 20
Realized hedging gains (losses) ($/boe) (1.04) 0.12 nm (0.78) 33 (0.91) (0.19) 379
Marketing income ($/boe)(1) 0.53 0.43 23 0.62 (15) 0.57 0.30 90
Operating netback ($/boe)(1)(3) 28.02 21.39 31 24.94 12 26.49 22.39 18
G&A per boe ($/boe) (0.82) (0.82) 0 (0.65) 26 (0.73) (0.80) (9)
Finance expense and other ($/boe) (1.71) (2.74) (38) (1.75) (2) (1.74) (2.84) (39)
Corporate netback ($/boe)(1) 25.49 17.83 43 22.54 13 24.02 18.75 28
Financial Results (1)                
Revenue ($)(2) 560.4 608.8 (8) 648.5 (14) 1,214.1 1,238.1 (2)
Liquids and natural gas sales ($)(4) 722.2 504.8 43 645.2 12 1,372.5 994.1 38
Operating income ($)(1) 169.6 59.5 185 129.4 31 299.0 133.6 124
Per share - diluted ($) 0.47 0.16 194 0.36 31 0.82 0.37 122
Net income (loss) ($) (24.6) 178.1 nm 22.7 nm (1.9) 393.3 nm
Per share - diluted ($) (0.07) 0.49 nm 0.06 nm (0.01) 1.08 nm
Funds from operations ($)(1) 434.0 268.1 62 380.8 14 814.8 540.4 51
Per share - diluted ($) 1.19 0.73 63 1.05 13 2.24 1.48 51
Cash provided by operating activities ($) 425.2 193.9 119 424.1 849.3 529.6 60
CROIC (%)(1) 18.8% 18.8% 18.1% 4 18.8% 18.8%
ROCE (%)(1) 12.1% 9.6% 26 10.4% 16 12.1% 9.6% 26
Balance sheet                
Capital investments ($) 562.6 512.5 10 582.6 (3) 1,145.2 874.8 31
Available funding ($)(1) 1,210.3 1,587.1 (24) 1,312.6 (8) 1,210.3 1,587.1 (24)
Net debt ($)(1) 2,263.6 1,797.2 26 2,118.2 7 2,263.6 1,797.2 26
Weighted average shares - basic 358.4 353.4 1 354.9 1 356.7 352.0 1
Weighted average shares - diluted 364.7 365.1 363.5 364.1 364.8 O)) —
(1) See “Non-IFRS Financial Measures” in the “Reader Advisory” at the end of the news release. Certain comparative figures have been adjusted to confirm to current period presentation.
(2) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
(3) Starting in 2018, Seven Generations began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume). 2017 liquids and natural gas sales have been adjusted to conform to this current period presentation.
(4) Excludes the purchase and resale of condensate and natural gas in respect of the company's transportation commitment optimization and marketing activities.


  Three months ended
June 30,
Three months ended
March 31,
Six months ended
June 30,

Nest Activity

2018 2017 %
2018 %
2018 2017 %
Drilling (1)                
Horizontal wells rig released 24 30 (20) 27 (11) 51 53 (4)
Average measured depth (m) 5,683 5,867 (3) 5,621 1 5,650 5,871 (4)
Average horizontal length (m) 2,470 2,614 (6) 2,459 2,464 2,630 (6)
Average drilling days per well 25 36 (31) 28 (11) 27 35 (23)
Average drill cost per lateral metre ($)(2) 1,399 1,642 (15) 1,500 (7) 1,452 1,555 (7)
Average well cost ($ millions)(2) 3.4 4.2 (19) 3.6 (6) 3.5 4.0 (13)
Completion (1)                
Wells completed 28 33 (15) 20 40 48 47 2
Average number of stages per well 45 38 18 39 15 43 39 10
Average tonnes pumped per well 5,504 5,961 (8) 5,923 (7) 5,679 6,135 (7)
Average cost per tonne(2) 1,208 1,196 1 1,218 (1) 1,212 1,234 (2)
Average well cost ($ millions)(2) 6.6 7.8 (15) 7.2 (8) 6.9 7.6 (9)
Total D&C cost per well ($ millions)(2) 10.0 12.0 (17) 10.8 (7) 10.4 11.6 (10)
(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.
(2) Information provided is based on field estimates and are subject to change.



Third-party processing plant maintenance impacted second quarter production by approximately 3,400 boe/d. 7G has recently expanded its diversion pipeline capacity, which will help mitigate processing facility outages. 7G is on track to complete its third owned and operated processing plant in the fourth quarter of 2018. The plant, located in the Gold Creek area, will have a capacity of 250 MMcf/d, which will increase the company’s processing capacity and further enhance 7G’s ability to mitigate outages. 7G’s 2018 second half production profile is consistent with expectations, with July corporate production averaging about 210,000 boe/d.

Drilling and completions continue to progress with reduced drilling time and lower total well costs that averaged $10 million per well during the second quarter. 7G’s completions continue to advance with the company implementing its tailored completions practice – with completions design reflecting each area’s condensate-to-gas ratio and geological characteristics. By varying stage count, proppant intensities and liner design, 7G intends to enhance well productivity and returns, and optimize full field recoveries.

Operating expenses were $6.00 per boe in the second quarter, which were impacted by facility maintenance. 7G drilled its second and third water disposal wells during the second quarter and now has capacity to handle more than half of its water disposal requirements internally. 7G is building an in-field water pipeline network that will connect its infrastructure to its disposal wells. This project is expected to reduce trucking and water handling costs during the second half of 2018.


7G continues to advance its area-specific artificial lift designs in order to optimize production in higher condensate-gas-ratio areas. As a result, 7G is seeing increasing condensate production from its Nest 1 wells, which were brought online in the first quarter of 2018. These wells each averaged 750 bbls/d of condensate during the first 120 producing days.

The company is also seeing strong results after implementing an enhanced lift design on its recently tied-in 12-well pad in the Nest 1 / Nest 2 transition zone. This pad continues to demonstrate better than anticipated condensate rates and economics, with wells averaging 1,000 bbls/d during the first 50 producing days.

7G continues to develop and delineate highly economic wells across its land base. With an increasing focus on returns and area-specific well design, 7G has segmented its Nest 2 holdings into four sub-regions defined by geological characteristics and condensate-to-gas ratios. In aggregate, 7G’s higher-resolution interpretation indicates increasing condensate production and lower natural gas production across the Nest 2 area relative to the company’s 2018 budget expectations and related 2019 outlooks, released in the fourth quarter of 2017. These Nest 2 sub-regions, identified as North, East, South and West, generate top-tier well economics that, at current commodity prices, are in-line with the company’s previous expectations. Through its enhanced area-specific well spacing and completions designs, 7G believes it will improve its capital efficiency, productivity and forecasting while driving higher returns. Additional details and sub-region economic forecasts are shown in the company’s August corporate presentation, posted on

In Nest 3, 7G’s latest production results from two new wells brought on stream in January remain constructive. To date, the wells have each averaged more than 2,500 boe/d on a constrained basis during their first 2.5 months of production, with an average of 690 bbls/d of condensate per well.

The company also successfully drilled and completed a stacked well pad, which included three Upper Montney, three Middle Montney and one Lower Montney well. 7G anticipates tie-in of these wells during the second half of 2018.


As previously announced, 7G expects 2018 production to be at the lower end of its 200,000 to 210,000 boe/d guidance range, with higher than forecast condensate volumes. Capital investments are expected to remain within a range of $1.675 billion to $1.775 billion. Given the budgeted cycle times arising from 7G’s batch drill, complete and tie-in processes, the company’s first half weighted 2018 capital investments will drive production growth in the second half of the year.

Higher than forecast condensate and lower than forecast natural gas production, combined with an improved understanding of the Nest resource, will enable 7G to optimize its capital allocation, production growth and full cycle returns. The company is currently reviewing its capital allocation plans for 2019 and expects to announce its 2019 capital budget and updated production guidance in the fourth quarter of 2018.

Conference Call

7G management will hold a conference call to discuss results and address investor questions today, August 2, 2018 at 9 a.m. MT (11 a.m. ET).

Participant Dial-In Numbers
Dial in - toll free: (877) 390-7644
Dial in - toll: (647) 252-4486
Audience passcode: 5191705
Webcast link:

Replay dial in toll-free: (855) 859-2056
Replay dial in toll: (404) 537-3406
Audience passcode: 5191705
Duration: August 2, 2018 - August 9, 2018


Seven Generations Energy

Seven Generations Energy is a low-supply cost, growth-oriented energy producer dedicated to stakeholder service, responsible development and generating strong returns from its liquids-rich Kakwa River Project in northwest Alberta. 7G’s corporate office is in Calgary, its operations headquarters is in Grande Prairie and its shares trade on the TSX under the symbol VII.


Reader Advisory

Non-IFRS Financial 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”, “corporate netback”, “operating netback”, “return on capital employed” or “ROCE”, “cash return on invested capital” or “CROIC”, “adjusted EBITDA”, “marketing income”, “operating income”, “adjusted working capital”, “available funding” and “net debt”. The data presented is 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 the 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 additional information about these measures, please see “Advisories and Guidance – Non-IFRS financial measures” in Management's Discussion and Analysis dated August 1, 2018, for the three and six months ended June 30, 2018 and 2017.

Forward-Looking Information Advisory

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: expected production, capital investment, funds from operations and cash flow; increased condensate and lower gas production expected from the Nest 2 area relative to previous forecasts; the Nest 2 sub-regions generating top-tier well economics in-line with the company’s previous expectations; expected processing capacity, increased processing capacity redundancy, and the timing of the completion of a new wholly-owned gas processing facility in the Gold Creek area; expectation that tailoring completions designs for different development areas will enhance forecasting, well productivity, capital efficiencies, returns and optimize full field recoveries; expectation that first half capital investments will drive production growth in the second half of 2018; the expectation that an in-field water pipeline network and disposals wells will be able to handle more than half of 7G’s water disposal requirements and will reduce water handling costs and trucking in the second half of 2018; the ability to optimize production in higher condensate-gas-ratio areas with changes in artificial lift design; plans to announce the company’s 2019 capital budget and related production guidance in the fourth quarter of 2018.

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 completion techniques to be utilized; 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; 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 company’s Annual Information Form for the year ended December 31, 2017, dated March 13, 2018 (the AIF)which is available on SEDAR at, 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 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; the potential for security deposits to be 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 for 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 common shares that are publicly traded and the company’s senior notes and other indebtedness.

Any financial outlook and future-oriented financial information contained in this news release regarding prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action based on management’s assessment of the relevant information that is currently available. Projected operational information contains forward-looking information and is based on a number of material assumptions and factors, as are set out above. These projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the company’s operations for any period will likely vary from the amounts set forth in these projections and such variations may be material. Actual results will vary from projected results. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The forward-looking information and statements contained in this news release speak only as of the date hereof and the company does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Note Regarding Oil and Gas Metrics

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.

Note Regarding Initial Production

Early production rates provided in this news release reflect results from wells drilled in the Upper / Middle Montney formation. Readers are cautioned that such early production rates are not necessarily indicative of longer-term performance or ultimate recovery.

bbl barrel
bbls barrels
boe barrels of oil equivalent
C5+ pentanes plus or condensate
CROIC cash return on invested capital
EBITDA earnings before interest, taxes depreciation and amortization
d day
D&C drilling and completions
G&A general and administrative expenses
IFRS International Financial Reporting Standards
m metres
mboe thousand barrels of oil equivalent
mbbl thousands of barrels
mcf thousand cubic feet
MMcf million cubic feet
Nest the Nest 1, Nest 2 and Nest 3 areas combined
Nest 1 the “Nest 1” area shown in the map provided in the company’s August Corporate Presentation, which is available on the company’s website at

Nest 2 the “Nest 2” area shown in the map provided in the company’s August Corporate Presentation, which is available on the company’s website at
Nest 3 the “Nest 3” area shown in the map provided in the company’s August Corporate Presentation, which is available on the company’s website at
NGLs natural gas liquids
nm not meaningful information
ROCE return on capital employed
TSX Toronto Stock Exchange

Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven Generations Energy, 7G, we, our and the company.


Marty Proctor, President & CEO

Derek Aylesworth, Chief Financial Officer

Investor Relations
Brian Newmarch, Vice President, Capital Markets
Phone: 403-718-0700

Media Relations
Alan Boras, Director, Communications & Stakeholder Relations
Phone: 403-767-0772

Seven Generations Energy Ltd.
Suite 4400, 525 - 8th Avenue SW
Calgary, AB T2P 1G1

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