DeGolyer and MacNaughton is a petroleum consulting company based in Dallas, Texas, with offices in Houston, Moscow, Calgary*, and Algiers.DeGolyer and MacNaughton was founded in 1936 by Everette Lee DeGolyer and Lewis MacNaughton. In 2004, it acquired Calgary-based Outtrim Szabo Associates forming its office in Canada as a subsidiary company. Wikipedia.
Ilk D.,DeGolyer and MacNaughton |
Blasingame T.A.,Texas A&M University
Society of Petroleum Engineers - SPE Canadian Unconventional Resources Conference 2013 - Unconventional Becoming Conventional: Lessons Learned and New Innovations | Year: 2013
The premise of this work is the development and application of a new methodology to forecast production data in unconventional reservoirs where variable rate and pressure drop data are typically observed throughout production. Decline curve analysis techniques for the estimation of ultimate recovery (EUR) require the constant bottomhole pressure condition during the producing life of the well - whereas it is not regular practice to maintain a constant bottomhole pressure profile throughout production in unconventional reservoirs. Therefore, the applicability of the time-rate decline relations is questionable, and methods to remove pressure variations from rate response are needed for generating future production forecasts. From a conceptual view point, we propose the utilization of the convolution/superposition theory along with the recently developed "empirical" time-rate equations, which are normalized by pressure drop data. In order to avoid non-uniqueness, a workflow is used where model parameters for the "normalized" decline curve equations are identified using diagnostic "qDb" plots. Normalized decline curve equations are then convolved with the pressure drop data to achieve a history match and to forecast production. We provide demonstrative application of this technique using an example from an high pressure high temperature shale gas reservoir. For varying bottomhole pressure cases, we show that our proposed techniques effectively remove pressure variations from the rate history. We present the differences in computed EUR values using decline curve analysis with and without corrections for varying pressures. In addition, forecasts are generated using supplementary plots such as pressure drop normalized rate versus cumulative production. Copyright 2013, Society of Petroleum Engineers.
Luo Z.,DeGolyer and MacNaughton |
Bryant S.,University of Calgary
Energy Procedia | Year: 2014
In large-scale CO2 sequestration project the formation temperature decreases as huge amounts of relatively cool CO2 are injected. Injection induced fractures from injectors are facilitated as the critical pressure in the formation for fracturing is reduced by considerable thermo-elastic stress, which is proportional to the temperature difference between CO2 and reservoir . In this study, we analyze injection induced fracture growth and its impact on CO2 plume migration by a semi-analytical quasi-steady state model in the case that injection induced fractures are permitted by regulators. By parametric analysis with the model, geological properties and operating conditions are investigated to show their sensitivity on fracture growth and CO2 migration. This work provides analytical tools, which enable fast and simple screening of appropriate storage sites and of injection strategy, to predict fracturing and CO2 migration to avoid potential risks. © 2014 The Authors Published by Elsevier Ltd.
Ramirez J.F.,University of Calgary |
Ramirez J.F.,DeGolyer and MacNaughton |
Aguilera R.,University of Calgary
SPE Reservoir Evaluation and Engineering | Year: 2016
Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the US Energy Information Administration, approximately 90% of the oil-production growth comes from six tight-oil plays. The Eagle Ford is one of these plays, and it accounts for 33% of the oil-production growth with a contribution of 1.3 million B/D. This is outstanding. However, oil recoveries as a percentage of the original oil in place (OOIP) are extremely low. This must be improved. A geological challenge in the Eagle Ford shale is the understanding of unconventional fluids distribution over geologic time: Shallower in the structure, there is black oil; deeper and to the south; condensate appears; and at the bottom, dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other unconventional reservoirs (e.g., Duvernay shale in Canada). The low oil recovery and the unusual distribution of fluids led to the key objective of this paper-to identify the main factors that control fluid migration (caused by buoyancy of gas in oil) from one zone to another through geologic time. This was performed by constructing a conceptual cross-sectional compositional simulation model with northwest/southeast orientation that allowed the study of fluid migration, fluid distribution, and fluid contacts throughout 1 million years while maintaining computational time within reasonable limits. The controlling parameters studied were porosity, permeability, pore-throat aperture (rp35), and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same original distribution (i.e., approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact). These fluids are the target of an ongoing research project with the ultimate goal of improving oil recovery from tight reservoirs by means of enhanced oil recovery (EOR) (Fragoso et al. 2015). There is, however, some gas migration through natural fractures to the top of the structure. This migration is interpreted in this study to be responsible for higher initial gas production in some oil wells in the top of the structure. Some operators indicate, however, that rapid gas/oil-ratio increases in the updip oil region are the result of low reservoir pressures and the rapid onset of two-phase flow. It would probably take geochemical evidence to support this conclusion. © Copyright 2016 Society of Petroleum Engineers.
Tye R.S.,DeGolyer and MacNaughton
Journal of Coastal Research | Year: 2013
Industry-accepted methods for estimating the subsurface dimensions of fluvial channel and channel-belt bodies were evaluated on their conceptual and physical bases. Geocellular models of fluvial reservoirs were built using several of these methods in conjunction with core and wireline-log data from the Krasnoleninskoye field, Russia. The objective was to use typical oil-field data and existing modeling technology to build geologically accurate geocellular models for fielddevelopment planning. Uncertainty in stratigraphic interpretation and geocellular modeling of fluvial reservoirs can be reduced by using floodplain deposits as pseudo-chronostratigraphic horizons to limit the miscorrelation of sandstone bodies, identifying and mapping paleovalleys constituting sandstone-prone fairways, and applying the physical relationships among maximum bankfull channel depth, channel width, and channel-belt width. A drawback to existing reservoir-modeling software is that it builds statistically based models conditioned to well data, but it does not incorporate physical-sedimentary laws. Therefore, reservoir zones in geocellular models must mimic paleovalley trends to prevent channel-body placement in a geologically inappropriate setting. Channels constrained by a geologically reasonable range of estimated dimensions (e.g., width, thickness, sinuosity) are distributed within the alluvial valleys along with the correct proportions of overbank-sandstone and floodplain deposits. Subsurface data interpreted from the standpoint of the physical-depositional processes they record, and with the recognition of the large- and small-scale sedimentation units comprising channel-bar and channel-fill strata, reveal how these strata vary from bar head to bar tail, and how the channel's geometry and migration style influenced the resultant vertical profile. Recognition of upperbar deposits and their transition into natural-levee and/or floodplain deposits defines the maximum bankfull channel depth from which channel width and channel-belt width are estimated. Maximum bankfull channel depths of two Krasnoleninskoye fluvial reservoirs were estimated using core data in conjunction with thickness measurements based on wireline-log data. As a comparison, estimates of maximum bankfull channel depth were calculated based upon the relationships of cross-set thickness to dune height and dune height to flow depth using cross-set thicknesses measured in the cores. Estimated channel widths and channel-belt widths range by a factor of 2 to 5, depending upon the calculation method. Realizations of the Krasnoleninskoye fluvial strata show channel-body dimensions and channel-body morphologies comparable to the Santee River, South Carolina, alluvial valley, in which straight, meandering, and anastomosed channel reaches occur within a 4 by 11 km area. Thus, stochastic, but geologically realistic geocellular models of fluvial reservoirs are achievable if the model structure accurately defines alluvial valleys, valleys are populated with channel bodies appropriately sized by maximum bankfull channel-depth estimates, and one abandons the traditionally held belief that alluvial stratigraphy varies due to, and can be predicted from, the planform morphology of the river system from which it formed. © Coastal Education & Research Foundation 2013.
Collins P.W.,DeGolyer and MacNaughton |
Badessich M.F.,YPF S.A. |
Ilk D.,DeGolyer and MacNaughton
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2015
Model-based production analysis using analytical or numerical models is not a new phenomenon and is considered a robust technique for analyzing and forecasting production data; however, its application to unconventional reservoir systems often proves problematic due to model non-uniqueness resulting from long-term transient flow regimes. This non-uniqueness, an unavoidable fact when analyzing inverse problems, is worsened by the uncertainty surrounding input model parameters when attempting to describe reservoir systems with a great deal of complexity (e.g. very low permeability, geomechanical effects, near-critical fluids, natural fracturing, etc.). The problem facing the engineer presents itself when different combinations of input parameters yield nearly identical history matches but very different time-rate profiles and estimated ultimate recovery (EUR) values when forecasting future production for a particular well. A systematic framework that covers the full range of uncertainty for all relevant input parameters would clearly mitigate the ambiguity of production analysis and forecasting under uncertain conditions. In this work it is proposed that experimental design, which is a statistical technique used to describe or optimize a process by systematically analyzing the effect of the various controllable and uncontrollable factors of a system on an output (e.g. EUR), can provide such a framework. In this work, a methodology combining model-based production analysis with experimental design is used to history match and forecast fractured vertical and multi-fractured horizontal oil wells in the Vaca Muerta Shale with high-frequency time-rate-pressure data. The primary objectives of this work are to provide a comprehensive overview of the Vaca Muerta shale, outline experimental design as it relates to model-based production analysis, quantify uncertainties in model input parameters, and finally history match and forecast two wells that are producing in the Vaca Muerta Shale. © Copyright 2015, Society of Petroleum Engineers.
Collins P.W.,DeGolyer and MacNaughton |
Ilk D.,DeGolyer and MacNaughton
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2015
Production forecasting in unconventional reservoir systems is not an easy task and should not be soley accomplished using empirical decline curve analysis. Advanced analytical and numerical models have facilitated the analysis of unconventional systems; however, it is almost always impractical to analyze and forecast hundreds of wells using these techniques. The focus of this work is to demonstrate a practical and timely methodology using model based production analysis as the foundation for the analysis and forecasting of each producing well in a particular area/field in an unconventional reservoir. The methodology is founded on a thorough diagnostic assessment of all available data, thorough production analysis of key wells, and extension to the remaining wells using key information from the diagnostic analysis. The methodology includes three main components: production diagnostics, model-based analysis for representative wells, and production forecasting. Production diagnostics is performed on a single well basis to identify flow regimes and performance metrics of each well, and performed on a multi-well basis to compare performance and identify characteristic behavior which can lead to well groupings and the selection of representative wells for analysis. Representative well(s) from each group are analyzed using model-based analysis incorporating non-linear behaviors associated with the production performance. A systematic analysis procedure is followed to account for the uncertainty on well/reservoir parameters affecting production behavior by utilizing an experimental design methodology. Multiple history matches are obtained accounting for uncertainties such as drainage area, permeability, etc. Following model-based analysis, production forecasts are developed for the corresponding history matches. Based on either a statistical distribution of EUR values or a deterministic approach, characteristic low/mid/high time-rate profiles can be derived. These profiles are extended to other wells via scaling factors to determine EUR values. Coming full circle, the scaling factors are then compared to well/reservoir data using maps and cross plots of performance metrics obtained from diagnostics to aid in the performance based analysis of the group. © Copyright 2015, Society of Petroleum Engineers.
Freeman C.M.,Lawrence Berkeley National Laboratory |
Moridis G.,Lawrence Berkeley National Laboratory |
Ilk D.,DeGolyer and MacNaughton |
Blasingame T.A.,Texas A&M University
Journal of Petroleum Science and Engineering | Year: 2013
Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight gas and shale gas systems featuring horizontal wells with multiple hydraulic fractures. Despite a few analytical models, as well as a small number of published numerical studies, there is currently little consensus regarding the large-scale flow behavior over time in such systems, particularly regarding the dominant flow regimes and whether or not reservoir properties or volumes can be estimated from well performance data.We constructed a fit-for-purpose numerical simulator which accounts for a variety of production features pertinent to these systems-specifically ultra-tight matrix permeability, hydraulically fractured horizontal wells with induced fractures of various configurations, multiple porosity and permeability fields, and desorption. These features cover the production mechanisms which are currently believed to be most relevant in tight gas and shale gas systems.We employ the numerical simulator to examine various tight gas and shale gas systems and to identify and illustrate the various flow regimes which progressively occur over time. We perform this study at fine grid discretization on the order of 1. mm near fractures to accurately capture flow effects at all time periods. We visualize the flow regimes using specialized plots of rate and pressure functions, as well as maps of pressure and sorption distributions.We use pressure maps to visualize the various flow regimes and their transitions in tight gas systems. In a typical tight gas system, we illustrate the initial linear flow into the hydraulic fractures (i.e., formation linear flow), transitioning to compound formation linear flow, and eventually transforming into elliptical flow. We explore variations of possible shale gas system models. Based on diffusive flow (with and without desorption), we show that due to the extremely low permeability of shale matrix (a few nanodarcies), the flow behavior is dominated by the extent of and configuration of the fractures.This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs. © 2013.
Rondon J.,DeGolyer and MacNaughton |
Barrufet M.A.,Texas A&M University |
Falcone G.,Texas A&M University |
Falcone G.,Clausthal University of Technology
Flow Measurement and Instrumentation | Year: 2012
This paper presents the performance evaluation of a novel sensor designed to measure the in situ viscosity of a fluid flowing at downhole conditions. The device provides a mechanism to allow the passage of solid particles (i.e. sand) and has a self-cleaning ability should any build-up of these particles restrict the flowing area. The sensor was assembled in a closed flow loop to prevent measurement error due to partial vaporization of the samples at higher temperatures, and it was tested and calibrated with mixtures of glycerin and water. Differential pressures, flow rates and temperatures were acquired and used to determine the viscosity of two crude oils (and mixtures of those) with viscosities ranging from 0.001 to 0.03 Pa.s (1 to 30 cp ) and temperatures from 37.8 to 71.1°C (100 to 160°F). Flow rates were controlled to maintain linearity in the differential pressure response to ensure a laminar flow regime. Viscosity measurements were validated with independent measurements using a Brookfield viscometer and the agreement was within 2%. Using data from this sensor, new viscosity mixing rules were developed to allow determination of mixture compositions from viscosity measurements or mixture viscosities for given compositions. This paper also presents a generalized mathematical model to describe the performance of the sensor with Newtonian and non-Newtonian fluids. The model characterizes the response of the sensor as a function of the parameters from a power-law model rheological description and the geometry of the device. The experimental data suggest the validity of this model for predicting the sensor response under realistic operating conditions. The model can be used to calculate optimum dimensions to fabricate a device for customized applications. Potential applications include the estimation of diluent to be added to a more viscous fluid to achieve a target viscosity reduction, fluid identification from wireline formation testers, smart well fluid monitoring, enhanced mud logging, and fracture fluid characterization. © 2011 Elsevier Ltd.
News Article | February 15, 2017
NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES Athabasca Oil Corporation (TSX:ATH) ("Athabasca" or the "Company") is pleased to announce a balance sheet refinancing transaction which marks the conclusion of a series of strategic steps undertaken over the past year to transform the Company. The comprehensive refinancing plan provides Athabasca multi-year funding certainty and a strong liquidity outlook that will allow the Company to continue to advance its strategic objectives and maintain business flexibility. Athabasca has established itself as an intermediate oil weighted producer with a funded five-year growth outlook and exposure to several of the largest resource plays in Western Canada including the Montney, Duvernay and oil sands. A complementary asset base of high rate of return light oil opportunities and low decline thermal production positions the Company for strong financial sustainability and free cash flow generation in the current environment while maintaining significant exposure to improving oil prices. Athabasca maintains a strong financial position with pro forma net debt on closing of the refinancing transactions estimated at $290 million and $400 million of available liquidity. The Company anticipates sustainable free cash flow generation in 2018 under current strip pricing with net debt to cash flow of less than 2.5x at year-end 2018 and trending lower in subsequent years. The Company is also pleased to provide its 2017 production and capital budget guidance which is adjusted for the Leismer acquisition effective February 1, 2017. Highlights include: Athabasca has a fully funded five-year development outlook capable of delivering a 30% per share production CAGR. The Company retains significant flexibility in future capital allocation decisions to react to operational results and market conditions. Additional details on the refinancing transactions, 2017 guidance and an operational update are provided within this release. Athabasca has entered into agreements to issue the New Notes in the amount of US$450 million. The New Notes, due in 2022 will pay interest at a rate of 9.875% per year and are not subject to maintenance or financial covenants. The New Notes are secured by a second priority lien on substantially all of the assets of Athabasca. The New Notes offering is expected to close on or about February 24, 2017, subject to customary closing conditions. Athabasca intends to use the net proceeds from the offering to repurchase for cash any and all of the Existing Notes pursuant to a cash tender offer. Details of the tender offer are outlined in a separate press release issued today. In conjunction with the New Notes, the Company will establish a $120 million reserve-based credit facility supported by growth in its proved developed producing reserves. The new credit facility is syndicated with seven major financial institutions, with closing anticipated to occur concurrently with the New Notes. RBC Capital Markets, LLC, Goldman, Sachs & Co., Credit Suisse and TD Securities acted as placement agents for Athabasca. Athabasca maintains a strong financial position with current pro forma net debt of approximately $300 million and total liquidity of approximately $400 million. The Company anticipates sustainable free cash flow generation in 2018 with net debt to cash flow of less than 2.5x under current strip pricing and less than 1.5x under GLJ pricing at year-end 2018. This press release shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the New Notes in any state in which such offer, solicitation or sale would be unlawful. The New Notes have not been registered under the United States Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements thereof. The Company has commenced a risk management program designed to protect a base level of cash flow and support its capital plans. The Company intends to hedge a minimum of 20,000 bbl/d for the balance of 2017 with 12,000 bbl/d of WCS hedges already in place at an average price of approximately C$52.75/bbl. Going forward, a multi-year hedging program is expected to form a part of the Company's risk management strategy. Athabasca has granted a Royalty to Burgess Energy on the recently acquired Leismer and Corner leases for $90 million of cash consideration. The Royalty follows the same structure as the existing thermal oil contingent bitumen royalties and ensures the assets are not encumbered at low commodity prices. The Royalty is based on a linear scale (0 - 12%) with a WCS benchmark. The minimum 2% trigger is US$60/bbl WCS at Leismer and Corner (US$75/bbl WTI assuming a US$15/bbl WCS differential). The Royalty is not expected to materially impact economics of future expansion phases or development projects and there are no associated commitments for development. Over the past year Athabasca has raised approximately $400 million through the series of Royalty transactions with Burgess Energy. These transactions unlocked long dated resource value and facilitated the recent acquisition of top tier producing Leismer thermal assets. Athabasca achieved its 2016 corporate guidance with annual production averaging approximately 12,000 boe/d (field estimates) compared to guidance of 11,800 boe/d. Capital spending for the full year was approximately $122 million, also in-line with prior guidance. Annual corporate volumes reflect the Murphy Oil Joint Venture which was completed in May 2016. Q4 2016 production averaged approximately 11,600 boe/d comprised of Light Oil at 3,300 boe/d (54% liquids) and Thermal Oil at 8,300 bbl/d. Leismer averaged approximately 23,800 bbl/d (field estimates) for Q4 2016 with a 2.6x SOR. Athabasca intends to maintain a stable production base between 22,000 - 24,000 bbl/d for the foreseeable future. Operations will be focused on production optimization and drilling additional sustaining and infill wells. The Company has a well-defined development plan for the mid-term which includes the start-up of four predrilled infills on Pad L5, infill opportunities on Pads L3 and L4 and regulatory approval and operational readiness to expand Pad L2. Hangingstone averaged approximately 8,300 bbl/d (field estimates) for Q4 2016 with a 4.9x SOR. Volumes in recent months have been impacted by facility maintenance and ongoing pump conversions which have largely been completed by the end of January. The project is expected to reach name plate capacity of 12,000 bbl/d in 2018 with minimal maintenance capital expected within the first five years of operations. Athabasca's 2017 Thermal Oil budget is approximately $105 million with production guidance of 29,000 - 32,500 bbl/d, adjusted for the Leismer acquisition effective February 1, 2017. The capital program consists of $84 million at Leismer, $15 million at Hangingstone and an additional $6 million for maintaining Athabasca's long dated thermal leases. At Placid, Athabasca currently has two rigs active in the field. 12 wells have been drilled to date and another eight wells are planned before breakup. Facilities construction is underway for a battery which will tie into Athabasca's owned and operated regional infrastructure network. The battery is expected to be in service at the beginning of the second quarter with capacity for growth up to 10,000 bbl/d and 36 mmcf/d. The 7 - 30 - 60 - 23W5 ("7-30") pad was rig released in late September. The four wells were drilled with an average lateral length of approximately 2,350 meters and an average drilling cost of $3.1 million. Completion operations concluded in November and the pad was designed to test ball-drop versus plug and perf design. Of the three wells completed on the 7-30 pad, two were cased hole and one open hole for an average cost of $4.2 million per well. Completions operations on the fourth well have been delayed and the Company anticipates completing the well in conjunction with future drilling operations on this pad site. The 7-30 pad came on production in December. Initial rates are meeting expectations with restricted IP30s of approximately 800 boe/d (278 bbl/mmcf free condensate). Regional volumes will remain restricted by facility capacity until the new Placid battery comes into service this spring. Eight wells have been drilled on the 12-19-60-23 and 16 - 30 - 60 - 23 pads with an average lateral length of approximately 2,500 meters and an average cost of $3.2 million. These wells have been designed for plug and perf completions. Completion operations are underway and both pads are expected to be placed on production before breakup. The Company is drilling its final two pads for the winter program at surface locations 3-4-61-23W5 (4 wells) and 7-33-60-23W5 (4 wells). The pads are expected to be rig released near the end of the first quarter with completions operations to commence in the summer. Decisions regarding second half activity levels will be finalized in the summer and the Company retains flexibility to adapt the program to results and external market conditions. Murphy and Athabasca have finalized 2017 capital plans which are consistent with the development plan contained in the joint development agreement. Core objectives of the program include near-term production and cash flow growth, delineation across all phase windows, optimizing well design and maximizing land retention. The 2017 program will include the spudding of 16 gross wells. The wells include a mix of pad development locations and delineation wells throughout the volatile oil window. Murphy intends to optimize well design with average lateral lengths increasing to approximately 2,800 meters and frac intensity up to approximately 2,000 lbs/ft (~3T/m). The program will target total lateral meters drilled of approximately 45,000 meters and this compares to Athabasca's initial 20 well appraisal campaign of approximately 27,000 meters since 2012. The Company's partner, Murphy, currently has two rigs active in the field. The first two-well pad spud in November of 2016 at Kaybob West (surface location 1-18-64-20W5). The pad was rig released in January with average drill times of 22 days (spud to rig release) and an average lateral length of ~1,400 meters. Completion operations are underway with on-stream timing expected before breakup. Murphy intends to complete the well with proppant intensity of approximately 2,000 lbs/ft. Drilling operations are underway on a two well pad at surface location 4-32-65-20W5 (2,650 meter average lateral length) and a three well pad at 11-18-64-20W5 (2,700 meter average lateral length). Both pads are expected to be rig released before breakup. Athabasca's 2017 Light Oil capital budget is $135 million ($120 million for Placid Montney and $15 million net for Duvernay) with production guidance of 6,500 - 7,500 boe/d and an exit target in excess of 10,000 boe/d. H2 2017 Montney capital will be assessed mid-year. Athabasca's independent qualified reserves evaluators, GLJ Petroleum Consultants ("GLJ") and DeGolyer and MacNaughton Canada Limited ("D&M"), prepared year-end reserve evaluations effective December 31, 2016 for the Company's existing properties and the recently acquired Leismer and Corner properties. Corporately, Athabasca has increased its Proved plus Probable reserves by approximately 210% per share year over year to 1,120 mmboe through the acquisition the Leismer and Corner properties, and a successful light oil drilling program at Greater Kaybob and Greater Placid. Additional details on reserves will be provided in conjunction with Athabasca's year-end disclosure in March. Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta's Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca's common shares trade on the TSX under the symbol "ATH". For more information, visit www.atha.com. This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "believe", "contemplate", "target", "potential" and similar expressions are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company's current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company's industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: the Company's five-year growth outlook and that such growth outlook is fully funded; the anticipated closing of the offering of New Notes and the $120 million credit facility and the use of proceeds therefrom; the benefits expected to be realized by the Company from offering of New Notes and the $120 million credit facility; estimates of sustainable free cash flow generation, net debt to cash flow levels and cash and cash equivalents and liquidity, for certain future periods; expectations with respect to future production hedging levels; estimates of 2017 corporate, Thermal Oil and Light Oil production levels and base decline rates; estimates of 2017 funds flow from operations, operating income and capital expenditures; the capability of the Company's five-year development outlook to deliver potential growth in per share production; the estimated impact of the Royalty on the economics of future expansion phases and development projects; future drilling and completion plans including numbers of wells and the timing thereof; the timing for achievement of name plate capacity at Hangingstone and expectations regarding maintenance capital within the first five years of operations; the timing of facilities construction and in service dates and the capacity thereof; the timing of completion operations; and other matters. Information relating to "reserves" is also deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: closing of the offering of New Notes and the $120 million credit facility and that Athabasca and its security holders will obtain the anticipated benefits thereof; commodity prices for petroleum and natural gas; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business and the effects that such regulatory framework will have on the Company, including on the Company's financial condition and results of operations; the Company's financial and operational flexibility; the Company's financial sustainability, the Company's ability to accelerate development when prices recover; Athabasca's cash-flow break-even commodity price; geological and engineering estimates in respect of Athabasca's reserves and resources; the applicability of technologies for the recovery and production of the Company's reserves and resources; the Company's ability to demonstrate the quality of its asset base and to build large-scale projects; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; the Company's future debt levels; the Company's ability to obtain equipment in a timely and cost-efficient manner; the geography of the areas in which the Company is conducting exploration and development activities; and the Company's ability to obtain equipment in a timely and cost-efficient manner. Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company's Annual Information Form ("AIF") dated March 10, 2016 that is available on SEDAR at www.sedar.com, including, but not limited to: failure to complete the offering of New Notes and the $120 million credit facility on the terms or within the time frames anticipated or at all; fluctuations in market prices for crude oil, natural gas and bitumen blend; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty regimes, environmental risks and hazards; alternatives to and changing demand for petroleum products; the potential for management estimates and assumptions to be inaccurate; dependence on Murphy as the Company's joint venture participant in the Company's Duvernay and Montney assets; the dependence on Murphy as the operator of the Company's Duvernay assets; the substantial capital requirements of Athabasca's projects and the ability to obtain financing for Athabasca's capital requirements; operational and business interruption risks associated with the Company's facilities; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements between Athabasca and such counterparties, and the possible consequences thereof; long term reliance on third parties; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; failure to meet development schedules and potential cost overruns; variations in foreign exchange and interest rates; factors affecting potential profitability; risks related to future acquisition and joint venture activities; reliance on, competition for, loss of, and failure to attract key personnel; uncertainties inherent in estimating quantities of reserves and resources; changes to Athabasca's status given the current stage of development; litigation risk; risks and uncertainties inherent in SAGD and other bitumen recovery processes; risks related to hydraulic fracturing, including those related to induced seismicity; expiration of leases and permits; risks inherent in Athabasca's operations, including those related to exploration, development and production of petroleum, natural gas and oil sands reserves and resources; risks related to gathering and processing facilities and pipeline systems; availability of drilling and related equipment and limitations on access to Athabasca's assets; increases in costs could make Athabasca's projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; environmental risks and hazards; failure to accurately estimate abandonment and reclamation costs; reliance on third party infrastructure; seasonality; hedging risks; risks associated with maintaining systems of internal controls; insurance risks; claims made in respect of Athabasca's operations, properties or assets; competition for, among other things, capital, export pipeline capacity and skilled personnel; the failure of Athabasca or the holder of certain licenses, leases or permits to meet specific requirements of such licenses, leases or permits; risks related to Athabasca's amended credit facilities and senior secured notes; and risks related to Athabasca's common shares. Also included in this press release are estimates of Athabasca's 2017 capital expenditures, funds flow from operations and operating income levels, which are based on the various assumptions as to production levels, commodity prices and currency exchange rates and other assumptions disclosed in this news release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca on February 9, 2017, and is included to provide readers with an understanding of the funding of Athabasca's capital expenditure program in 2017 and an outlook for the Company's activities and results and readers are cautioned that the information may not be appropriate for other purposes. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The financial outlook contained in this New Release was made as of the date of this press release and the Company disclaims any intention or obligations to update or revise such financial outlook, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. The reserves data set forth above is based upon the reports of GLJ and D&M, each dated effective December 31, 2016 and December 31, 2015 and prepared in accordance with the Canadian Oil and Gas Evaluation Handbook. The price forecast used in the 2016 reserve evaluations is the January 1, 2017 GLJ price forecast, which is available on ITS website, www.gljpc.com, and will be contained in the Company's Annual Information Form for the year ended December 31, 2016, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2017. The price forecast used in the 2015 reserve evaluations is the January 1, 2016 GLJ price forecast, which is available in the Company's Annual Information Form for the year ended December 31, 2015, which is accessible on SEDAR at www.sedar.com. There are numerous uncertainties inherent in estimating quantities of bitumen, crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company's properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company's tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company's financial statements and the management's discussion and analysis should be consulted for information at the level of the Company. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregations. The estimated values of future net revenue disclosed in this press release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material. The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2016, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2017. Certain financial and operating results included in this news release including, without limitation, capital spending and production information are based on unaudited estimated results. These estimated results are subject to change upon completion of the audited financial statements for the year ended December 31, 2016, and changes could be material. "BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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. The initial production rates provided in this News Release should be considered to be preliminary. Initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery. The "Funds Flow from Operations", "Light Oil Operating Income", "Thermal Oil Operating Income" and "Net Debt" financial measures contained in this News Release do not have standardized meanings which are prescribed by International Financial Reporting Standards ("IFRS") and they are considered to be non-GAAP measures. Investors should be cautioned that these measures should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with IFRS. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. Funds Flow from Operations is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Funds Flow from Operations measure allows management and others to evaluate the Company's ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. The Light Oil Operating Income measure in this News Release is calculated by subtracting royalties and operating and transportation expenses from petroleum and natural gas sales and midstream revenues received. The Light Oil Operating Income measure allows management and others to evaluate the production results from the Company's Light Oil assets. The Thermal Oil Operating Income measure in this News Release is calculated by subtracting the cost of diluent blending, royalties, operating expenses and transportation expenses from blended bitumen sales received. The Thermal Oil Operating Income measure allows management and others to evaluate the production results from the Company's Thermal Oil assets. The Net Debt measure in this News Release is calculated by subtracting the face value of the Company's long term debt less cash and equivalents. The Net Debt measure is not intended to represent other measures of financial position on the Company's balance sheet that are calculated in accordance with IFRS. The Net Debt financial measure allows management and others to evaluate the Company's funding position and utilization of debt within its capital structure.
News Article | February 16, 2017
SAN ANTONIO--(BUSINESS WIRE)--Abraxas Petroleum Corporation (“Abraxas” or the “Company”) (NASDAQ:AXAS) today provided the following reserve and operational update. Highlights include: As of December 31, 2016, Abraxas’ proved oil and natural gas reserves consisted of approximately 44.7 MMBoe, a net increase of 1.5 MMBoe over 2015 year end reserves of 43.2 MMBoe. December 31, 2016 reserves consisted of approximately 24.2 million barrels of oil, 8.6 million barrels of NGLs and 70.8 billion cubic feet of natural gas. Proved developed producing reserves were 13.9 MMBoe and comprised 31% of proved reserves as of December 31, 2016. The SEC-priced pre-tax PV-10(1) (a non-GAAP financial measure) was $160.6 million, using 2016 average prices of $42.74/bbl of oil and $2.50/mcf of natural gas. Realized pricing, including differentials, used in this calculation equated to $35.54/bbl of oil and $1.41/mcf of natural gas. The majority of the reserve additions came from the Williston Basin, where Abraxas benefited from an upward revision in the Company’s Middle Bakken type curve to 832 MBoe from 530 MBoe at December 31, 2015 (853 MBoe at strip pricing which extends the economic life of the well). Abraxas also benefited from an upward revision in the Company’s first bench Three Forks type curve to 709 MBoe from 530 MBoe at December 31, 2015 (726 MBoe at strip pricing which extends the economic life of the well). In Ward County, Abraxas also added 5 gross (1.8 net) locations of proved undeveloped reserves on the Company’s Caprito lease in the Wolfcamp A2 zone at 571 MBoe (588 MBoe at strip pricing which extends the economic life of the well). Abraxas also sold 1.2 MBoe of reserves during 2016. The independent reserve engineering firm DeGolyer and MacNaughton prepared a complete engineering analysis on 98% of Abraxas’ proved reserves on a Boe basis. The following table outlines changes in Abraxas’ proved reserves from December 31, 2015: Production for the fourth quarter of 2016 is expected to average approximately 7,955 Boepd (4,923 barrels of oil per day, 10,087 mcf of natural gas per day, 1,350 barrels of NGL per day). Abraxas volumes were partially impacted by freeze offs in the Bakken and Permian in December 2016. During 2016, Abraxas also successfully closed two asset sales with approximately 175 Boepd of associated production and effective dates of June 1 and October 1, 2016. Despite the curtailments and asset sales, production for the year ending December 31, 2016 averaged approximately 6,181 Boepd (3,750 barrels of oil per day, 8,633 mcf of natural gas per day, 993 barrels of NGL per day) or the approximate midpoint of Abraxas’ guidance of 6,200 Boepd. Capital expenditures for the year ended December 31, 2016 are expected to be approximately $31.7 million or approximately 9% below the Company’s revised $35 million budget. In Ward County, Texas, Abraxas recently spud a two well pad in the Caprito 98-201H and Caprito 98-301H in February, 2017. The Caprito 98-301H will target the Wolfcamp A2 zone, which Abraxas targeted in the Caprito 99-101H (renamed to the Caprito 99-302H). The Caprito 98-201H will target an additional prospective zone in the Wolfcamp A1. Abraxas estimates it will own a working interest of approximately 88% in the Caprito 98-201H and 98-301H, respectively. At Abraxas’ North Fork prospect, in McKenzie County, North Dakota, the Company completed the intermediate sections of the Stenehjem 6H-9H and the lateral of the Stenehjem 9H. Abraxas is currently drilling the lateral of the Stenehjem 8H. Abraxas working interest in the Stenehjem 6H-9H is approximately 75%. In Atascosa County, Texas, Abraxas plans to spud an Eagle Ford test in April 2017 on the Company’s Red Eye Unit. Although Abraxas remains encouraged by the Austin Chalk, the Company believes enhanced completion techniques (specifically the use of diverters) could significantly improve the economic viability when applied to the Eagle Ford formation. Testing the Eagle Ford will have the added benefit of holding acreage through the entire lower Eagle Ford and maintaining the Austin Chalk rights. Abraxas will have a 100% working interest in the Red Eye 1H. Bob Watson, President and CEO of Abraxas, commented, “We are pleased to report our fifth consecutive year of significant production and reserve growth. Obviously, 2016 was a transformational year as our change in Bakken completion design led to a significant increase in our Bakken type curve and our first Wolfcamp completion opened up a multi-year low-risk development for Abraxas. Although the last two weeks of 2016 were plagued by downtime caused by freeze-offs, we are pleased that our annual production guidance still came in at the middle of the range. On the positive front, our gas volumes in the Permian, which were curtailed for almost a year and a half, have been producing at full rates since mid-January. We expect this to continue as a result of our third party processer making substantial upgrades to their facility. “We are embarking on a more aggressive development campaign in 2017 to capitalize on our 2016 success. By the end of the second quarter of 2017 we should have four operated Bakken wells, two operated Permian wells and one operated Eagle Ford well on production or set for completion. This will lead to a significant increase in our daily volumes. With a pristine balance sheet with over $95 million of liquidity, a solid hedging profile and a multi-year inventory of highly economic development wells ahead of us in the Bakken and Wolfcamp, we are well positioned to drive multiple-years of exceptional growth and returns for our shareholders.” (1) The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2015 and 2016: Abraxas Petroleum Corporation is a San Antonio based crude oil and natural gas exploration and production company with operations across the Rocky Mountain, Permian Basin and South Texas regions of the United States. Safe Harbor for forward-looking statements: Statements in this release looking forward in time involve known and unknown risks and uncertainties, which may cause Abraxas’ actual results in future periods to be materially different from any future performance suggested in this release. Such factors may include, but may not be necessarily limited to, changes in the prices received by Abraxas for crude oil and natural gas. In addition, Abraxas’ future crude oil and natural gas production is highly dependent upon Abraxas’ level of success in acquiring or finding additional reserves. Further, Abraxas operates in an industry sector where the value of securities is highly volatile and may be influenced by economic and other factors beyond Abraxas’ control. In the context of forward-looking information provided for in this release, reference is made to the discussion of risk factors detailed in Abraxas’ filings with the Securities and Exchange Commission during the past 12 months.