CALGARY, ALBERTA–(Marketwired – May 4, 2016) – Seven Generations Energy Ltd. (TSX:VII) delivered record production of 88,525 barrels of oil equivalent per day (boe/d) in the first quarter of 2016, up 82 per cent from the same period one year earlier. With the new Cutbank processing plant on-stream, April production averaged more than 105,000 boe/d, putting 7G on track to achieve 2016 production guidance of 100,000 to 110,000 boe/d.
First quarter funds from operations were about $111 million, up 27 percent compared to the same period in 2015, despite benchmark commodity prices that were about 30 percent lower. First quarter capital investment was $267 million, 27 percent lower than during the first quarter of 2015. 7G’s 2016 capital investment program is weighted towards the early part of the year and is in line with the planned investment range of $900 million to $950 million.
2016 growth ramping up with the addition of new processing capacity
“We are continuing to execute our growth as planned. We now have sufficient liquids-rich natural gas processing to meet our Alliance Pipeline transportation volumes which increase to 500 million cubic feet per day (MMcf/d) by late 2018,” said Marty Proctor, 7G’s President and Chief Operating Officer.
“Near the end of the first quarter, we started up our second large natural gas processing plant – Cutbank, about a week ahead of schedule. The capital cost was about 25 percent under budget, largely due to optimization and lessons learned from building the Lator 2 plant in 2015, plus favourable weather for construction. When Cutbank’s 250 MMcf/d of new processing capacity is combined with our Lator complex, we have 510 MMcf/d of natural gas processing capacity. We have five drilling rigs in the field, two completion spreads, and are increasing production as in-field facilities construction projects are complete,” Proctor said.
Drilling faster and cheaper wells, with fewer rigs
“We are drilling wells faster and at a lower cost. We started the year with ten rigs and plan to run five through the remainder of 2016, which we expect will be sufficient to achieve our planned production growth this year. Compared to the first quarter of 2015, our drilling days per well are down 25 percent, and per well costs are down 31 percent. Drilling costs averaged $4.3 million with the horizontal length averaging 2,694 metres in the first quarter of 2016,” Proctor said.
“Our strategic focus on innovation and operational effectiveness in drilling, completions, construction, facilities installation, and the development of our core resource under our Nest 2 lands, put us right on track to profitably grow production. We now have a very large and sophisticated production network built, from our Montney resource to two receipt points on the transcontinental Alliance Pipeline,” said Pat Carlson, 7G’s Chief Executive Officer.
Capturing stronger natural gas prices in the U.S. Midwest
Before December 2015, 7G’s natural gas price was based on an Alberta price at AECO, which often trades at a significant discount to U.S. Midwest prices. With 7G’s natural gas now sold into the Chicago market via Alliance Pipeline, where it receives a Chicago Citygate price, the Company has been able to realize stronger prices than those available in Alberta.
“In 2014 we contracted a ramp up of delivery to 500 MMcf/d, which is approximately 30 percent of the capacity on Alliance Pipeline, by the end of 2018. Anticipating a weak market in Alberta due to production from deferred LNG projects, we contracted delivery of our liquids-rich natural gas all the way to Chicago, and have avoided the congestion and resulting depressed prices in the Alberta market. By reaching the U.S. Midwest region, our first quarter realized natural gas price was $3.24 per thousand cubic feet (Mcf), up 24 percent from a year ago. This higher price, which is partially offset by increased transportation costs to the Chicago area, reflects the stronger U.S. Midwest market. With the grossly over-supplied natural gas market in North America, access to the best markets remains among the toughest obstacles to profitable growth. Matching marketing opportunities with our resource capacity has been our focus for several years and we are seeing the benefits now. However, competition for markets is likely to remain a dominant force in North America’s natural gas business and we are continuing to prioritize the search for superior market arrangements,” Carlson said.
Strengthened financial standing
On February 24, 2016, 7G closed a private placement of 21,428,600 common shares at $14 per share, resulting in gross proceeds of $300 million that continued to strengthen the Company’s balance sheet. Seven Generations had $448 million of adjusted working capital at March 31, 2016. When 7G’s $813 million revolving credit facility is combined with adjusted working capital, the Company has about $1.3 billion of available funding. 7G expects to fund its 2016 capital program, between $900 million and $950 million, with cash on hand and funds from operations.
HIGHLIGHTS FOR THE QUARTER ENDED MARCH 31, 2016
- Continued strong production growth averaging 88,525 boe/d, leading to an average in April of more than 105,000 boe/d. First quarter production consisting of 58 percent liquids, with a liquids-to-gas ratio of approximately 227 barrels (bbls) per MMcf of sales gas. Production increased 82 percent from the first quarter of 2015, and was up 14 percent from the fourth quarter of 2015.
- Funds from operations were about $111 million in the first quarter, up 27 per cent compared to the first quarter of 2015, despite a drop in benchmark oil and natural gas prices of about 30 percent.
- Compared to the first quarter of 2015, 7G increased production per share by 76 percent and funds from operations per share by 24 percent during the first quarter of 2016. The Company’s diluted share count increased by 13 percent largely due to the $300 million equity financing in February.
- First quarter capital investment of $267 million, down 27 percent compared to first quarter 2015 and consistent with planned 2016 capital investments of between $900 million and $950 million.
- Operating expenses were $3.85 per barrel, down 21 percent from the first quarter of 2015 as 7G captured economies of scale and improved operating efficiencies.
- Realized natural gas prices increased to $3.24 per Mcf, up 24 percent compared to the first quarter of 2015.
- Seven Generations drilled 15 wells and completed 18 wells, taking the number of producing Montney wells to 117. At the end of the first quarter, approximately 72 wells were in various stages of construction between drilling and tie-in. This inventory of in-progress wells represents significant productive capacity that will be brought on-stream throughout 2016.
- The Cutbank natural gas plant, built and commissioned to process 250 MMcf/d, came online about a week ahead of schedule and capital costs were about 25 percent lower than budgeted.
- 7G completed the 24-inch Cutbank sales pipeline, a 29-kilometre connection to deliver liquids-rich natural gas on the Alliance Pipeline.
- At the Karr condensate stabilization facility, construction was nearly complete at the end of March on the 18,000-barrel tank farm with ten truck loading stations. Commissioning was completed in April.
|2016 FIRST QUARTER FINANCIAL AND OPERATING RESULTS|
|Three months ended
|($ thousands, except per share and volume data)|
|Natural gas (MMcf/d)||225||125||80|
|Condensate and oil ($/bbl)||39.92||47.59||(16||)|
|Natural gas ($/Mcf)||3.24||2.62||24|
|Liquids and natural gas revenues||$||23.34||$||24.73||(6||)|
|Netback prior to hedging||12.93||13.43||(4||)|
|Realized hedging gain||4.50||11.54||(61||)|
|Operating netback after hedging||$||17.43||$||24.97||(30||)|
|General and administrative expenses per boe||$||0.99||$||1.51||(34||)|
|Selected financial information|
|Liquids and natural gas revenue||187,996||108,540||73|
|Funds from operations (1)||110,654||86,889||27|
|Per share – diluted||0.40||0.32||25|
|Operating income (1)||9,310||23,998||(61||)|
|Per share – diluted||0.03||0.09||(67||)|
|Net income (loss)||138,449||(82,698||)||267|
|Per share – diluted||0.50||(0.34||)||247|
|Total capital investments||267,134||368,400||(27||)|
|Available funding (1)||1,260,447||1,193,385||6|
|Net debt (1)||1,013,427||505,234||101|
|Weighted average shares – diluted||278,932||270,497||3|
|(1)||Operating netback, funds from operations, operating income, available funding and net debt are not defined under International Financial Reporting Standards (IFRS). See “Non-IFRS Financial Measures” in Management’s Discussion and Analysis for the three months ended March 31, 2016 and 2015.|
Drilling days reduced by 25 percent and well costs trimmed 31 percent
Seven Generations drilled 15 first quarter wells, on average, 25 percent faster and at a 31 percent lower cost than in the first quarter of 2015. Wells averaged 2,694 metres of horizontal length, 38.5 days to drill and had an average cost of $4.3 million. 7G began the year running ten drilling rigs targeting the Upper and Middle Montney formation in the Company’s Nest area and ended the first quarter operating five drilling rigs, with the expectation of staying on pace to meet 2016 production guidance.
Completions costs down 18 percent
7G completed 18 wells in the first quarter of 2016, each with an average of 27 stages and an average of 4,770 tonnes of proppant, for an average cost of $5.6 million, down 18 percent compared to one year earlier and 8 percent less than the fourth quarter of 2015.
Innovation continues to show promise for increased resource recovery
“We are seeing encouraging results from the four slickwater well completions we pumped in the first quarter compared to our traditional nitrogen foam completions. We also increased proppant sand injections, pumping four first quarter wells with proppant densities greater than two tonnes per metre. Early results from these slickwater and higher density completions suggest improvement over the previous design. Combined, these initiatives are helping reduce costs and increase productivity,” Proctor said.
DRILLING AND COMPLETIONS
|Drilling||Q1 2016||Q1 2015|
|Net Hz Wells Rig Released(1)||15||22.5|
|Average Measured Depth (m)||5,936||5,901|
|Average Horizontal Length (m)||2,694||2,717|
|Average Drilling Days per Well||38.5||51|
|Average Drilling Cost per Lateral Metre ($/m)||1,597||2,476|
|Average well cost ($MM)||4.3||6.2|
|(1)During the drilling of Kakwa100/2-19-63-4 W6 on Pad 8-25, the well was abandoned due to pipe stuck in the wellbore that could not be recovered. This well is not reported in the above list.|
|Completions||Q1 2016||Q1 2015|
|Net Wells Completed||18||16.5|
|Average Number of Stages per Well||27||30|
|Average Tonnes Pumped per Well||4,770||4,200|
|Average well cost ($MM)||5.6||6.8|
Super Pads seven and eight now operating, ninth Super Pad under construction
During the first quarter, 7G’s seventh and eighth Super Pads were brought on production, and construction was progressing on schedule and budget for 7G’s ninth Super Pad, which is expected to be commissioned in the third quarter of 2016. With nine Super Pads and the addition of compression at two existing pad sites, the Company’s total field gathering and processing capacity will increase to 510 MMcf/d of natural gas and more than 100,000 bbls/d of field condensate. The newly designed Mega Pads will see select Super Pads expanded from 50 MMcf/d to 100 MMcf/d with the inclusion of additional compression and dehydration capacity. At the end of the first quarter, 7G had two satellite pads and six well tie-ins under construction and an inventory of approximately 72 wells at various stages of construction between drilling and tie-in.
Karr condensate loading stations built
At the Karr condensate stabilization facility, construction of an 18,000-barrel tank farm with ten truck loading stations was completed in April. Planned 2016 investments at Karr include a second 25,000 bbl/d stabilization train and a second sales condensate pipeline to increase shipments on the Pembina system.
First quarter commodity prices continued to languish at long-term lows with benchmark oil and natural gas prices down about 30 percent year-over-year. Despite weaker prices, first quarter funds from operations increased 27 percent to about $111 million compared to the same period in 2015, largely due to increased production. First quarter operating netbacks were $17.43 per boe after hedging, down 30 percent in the past year due to the approximate 30 percent drop in benchmark prices and the expiry of higher-priced hedges put in place before the commodity price fall. Higher production and continued efficiency gains lowered operating expenses on a per boe basis helping to partially offset the realized price declines.
7G continues to maintain a position of financial strength. Combining the Company’s $813 million credit facility with adjusted working capital, which includes $287 million of net proceeds from the February equity raise, 7G has about $1.3 billion of available funding. Balance sheet strength and access to capital remain a top priority.
Managing market risk
Seven Generations employs financial hedges to partially protect funds from operations against commodity price volatility. Seven Generations’ hedge targets include up to 65 percent of forecasted production volumes (net of royalties) for the upcoming four quarters, up to 35 percent of forecasted volumes for the next four quarters after that and up to 20 percent for the four quarters beyond that period. Price targets are established at levels that are expected to provide a threshold rate of return on capital investment based on a combination of benchmark oil and natural gas prices, projected well performance and capital efficiencies.
|7G Commodity Price Hedge Position – March 31, 2016||2016||2017||2018|
|WTI hedged (bbls/d)*||13,667||9,750||7,250|
|Average floor ($C/bbl)||70.05||66.80||60.80|
|Average ceiling ($C/bbl)||80.35||77.64||72.93|
|Natural gas hedging|
|Gas hedged (MMBtu/d)||123,333||105,000||47,500|
|Average Chicago Citygate swap ($US/MMBtu)||3.19||3.10||2.80|
|Average swap ($C/MMBtu)**||4.01||4.00||3.83|
|Currency exchange hedging|
|$US notional hedged (MM)||108.21||118.82||48.46|
|Average rate ($C/$US)||1.2562||1.2879||1.3690|
|*||Includes C$40.00/bbl puts of sold puts on 3-way collars for 2,000 bbls/d in 2017 and 4,000 bbls/d in 2018.|
|**||Chicago Citygate natural gas price converted to C$/MMbtu at average C$/US$hedge rate.|
OUTLOOK – Investing to fill infrastructure and drive towards cash flow self sufficiency
Seven Generations continues to plan a 2016 capital investment program of $900 million to $950 million directed at drilling and completing wells to help achieve a self-funding state of producing free cash flow. 2016 production is expected to average 100,000 to 110,000 boe/d, which, at the midpoint, would represent an approximate 75 percent increase over 2015 average production of 60,400 boe/d. In 2016, 7G’s liquids are expected to range between 55 and 60 percent of total production.
“With our two new processing plants built and operating we are very well positioned to incrementally grow production towards our contracted firm transportation capacity on Alliance Pipeline that averages approximately 350 MMcf/d in 2016 and steps up to 500 MMcf/d in late 2018. We also have contracted 107 MMcf/d of lean gas delivery to the TransCanada Pipeline system starting in 2018,” said Proctor.
On April 21, 2016, the Government of Alberta announced additional royalty details and technical formulas for its Modernized Royalty Framework (MRF). Based on a detailed review of the program, 7G believes that the MRF will allow for similar development economics for Nest 2 wells and it will incentivize experimentation to improve returns. For 7G, rates of return on expected Montney drilling and development do not appear to have changed materially, and are in line with the government’s stated target of keeping internal rates of return neutral, compared to the existing royalty structure. In addition, the inclusion of total proppant pumped, plus measured and true vertical depth, in the new royalty equations provides 7G a more suitable framework to remain competitive in the North American natural gas business, and provides the opportunity to increase both rates of return and royalties generated per well. This achieves the resource owners’ objective of creating a win-win for the government and industry. Seven Generations Energy commends the Alberta government for producing a royalty framework that is expected to provide a stable platform for keeping Alberta’s natural gas industry competitive and for attracting long-term investment.
7G management plans to hold a conference call to discuss results and address investor questions on Wednesday, May 4, 2016 at 8:00 a.m. MT (10 a.m. ET).
|Participant Dial-In Numbers:|
|Operator Assisted Toll-Free||(877) 291-4570|
|Local or International||(647) 788-4919|
|Conference Call ID:||87611761|
|Encore Dial In:||(800) 585-8367 or (416) 621-4642|
|Available:||May 4, 2016 – May 18, 2016|
Event Link: http://www.gowebcasting.com/7474
Seven Generations Energy
Seven Generations is a low-supply-cost, high-growth Canadian natural gas 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
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”. 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.
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 for the three months ended March 31, 2016.
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: planned capital investment in 2016; expected production and production growth; expected processing and transportation capacity and utilization; achievement of 2016 production guidance; expectation that five drilling rigs will be sufficient to achieve planned production growth; expectation that 7G will fund its 2016 capital with cash on hand and funds from operations; expectation that 7G’s inventory of in-progress wells will be brought on stream throughout 2016; the expected productive capacity of in-progress wells; the expected commissioning of 7G’s ninth Super Pad in the third quarter of 2016; increased field gathering and processing expected with the completion of the ninth Super Pad; hedging targets; expectation that hedging will provide certain threshold rates of return; ability to double the processing capacity of the newly designed Super Pads; the continued focus on operational effectiveness in drilling, completions and facilities installation; expectation that future investments at the Company’s Karr facility will include a second 25,000 bbls/d stabilization train and a second sales condensate pipeline to increase shipments on the Pembina Pipeline system; expected liquids ratios; achievement of a self-funding state with positive free cash flow; the expectation that the Modernized Royalty Framework will provide a stable platform for keeping Alberta’s natural gas business profitable and for attracting long-term investment and the ability to generate long life value from the Kakwa River Project.
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; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory 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; the applicability of technologies for recovery and production of the Company’s reserves and resources; the recoverability of the Company’s reserves and resources; future capital investments to be made by the Company; future cash flows from production; 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 this forward-looking information as a result of the risks and risk factors that are described in the Company’s Annual Information Form dated March 8, 2016 for the year ended December 31, 2015 (the “AIF”), 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 or the enforcement thereof; 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; 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; operating hazards and uninsured risks; the possibility that Company’s drilling activities may encounter sour gas; execution of the Company’s business plan; failure to acquire or develop replacement reserves; the concentration of the Company’s assets in the Kakwa River Project area; 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; dependence on employees and contractors; third-party claims regarding the Company’s right to use technology and equipment; expiry of certain leases for undeveloped leasehold acreage in the near future; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the Company’s activities and the Canadian oil and gas industry; weather related risks, fires and natural disasters; extensive competition in the Company’s industry; changes in the Company’s credit ratings; dependence upon a limited number of customers; terrorist attacks or armed conflict; loss of information and computer systems; security deposits may 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; third-party credit risk including risk associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; litigation; sufficiency of internal controls; third-party breach of agreements or failure of counterparties to meet their commitments; impact of expansion into new activities on risk exposure; risks related to the senior unsecured notes and other indebtedness, including potential inability to comply with the covenants in the credit agreement related to the Company’s credit facilities and/or the covenants in the indentures in respect of the senior secured notes.
|AECO||physical storage and trading hub for natural gas on the TransCanada Alberta system which is the delivery point for various benchmark Alberta index prices|
|boe(1)||barrels of oil equivalent|
|IFRS||International Financial Reporting Standards|
|LNG||liquefied natural gas|
|Mcf||thousand cubic feet|
|MMboe||millions of barrels of oil equivalent|
|MMBtu||million British thermal units|
|MMcf||million cubic feet|
|MRF||Modernized Royalty Framework|
|Nest 2||means the higher return prospects within the Nest|
|Nest||means the primary development block of the Kakwa River Project.|
|NGLs||natural gas liquids|
|TSX||Toronto Stock Exchange|
|WTI||West Texas Intermediate|
|$MM||millions of dollars|
|$US||United States dollars|
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.|
Chris Law, Chief Financial Officer
Brian Newmarch, Director, Capital Markets
Director, Communications and Stakeholder Relations
Seven Generations Energy Ltd.
Suite 300, 140 – 8th Avenue SW
Calgary, AB T2P 1B3