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News Article | February 21, 2017
Site: www.businesswire.com

DENVER--(BUSINESS WIRE)--Whiting’s (NYSE: WLL) production in the fourth quarter 2016 totaled 10.9 million barrels of oil equivalent (MMBOE), comprised of 84% crude oil/natural gas liquids (NGLs). Fourth quarter 2016 production averaged 118,890 barrels of oil equivalent per day (BOE/d), above the high end of guidance (117,390 BOE/d) and an increase from the third quarter when adjusted for asset sales.(1) Enhanced completions contributed to production exceeding guidance and to lease operating expense (LOE) per BOE coming in at the low end of guidance. LOE also benefited from the sale of higher cost properties and continued efficiency gains in the field. James J. Volker, Whiting’s Chairman, President and CEO, commented, “Whiting delivered another strong quarter. Production grew sequentially when adjusted for asset sales and exceeded the high end of our forecast. Operating expense was at the low end of guidance. We achieved this while generating operating cash flow that exceeded our capital expenditures. Also, our efforts to reshape our balance sheet came to fruition this quarter. We announced the $375 million sale of our North Dakota midstream assets. We received the proceeds on January 3, 2017 and used $275 million to redeem all of our outstanding 2018 notes on February 2, 2017. Since the beginning of 2016, we have sold $725 million of non-core properties and used the proceeds to improve our balance sheet. Asset sales combined with innovative debt exchange transactions and free cash flow reduced debt by $2.4 billion or 42% since March 2016.” Mr. Volker continued, “In 2016, we worked to position the company for strong growth through balance sheet improvement and a focus on operational improvements that resulted in a 42% increase in per well productivity over 2015. In 2017, we are focused on increasing production, reserves and net asset value through a capital efficient plan that further enhances our balance sheet metrics through growth. We project a total capital budget of $1.1 billion in 2017. Based on this capital plan, we forecast that production grows 23% from first quarter to fourth quarter 2017.” The following table summarizes the operating and financial results for the fourth quarter of 2016 and 2015, including non-cash charges recorded during those periods: The following table summarizes the operating and financial results for the full year 2016 and 2015, including non-cash charges recorded during those periods: As previously announced, Whiting closed the sale of its North Dakota midstream assets in January 2017 and received approximately $375 million of proceeds. It subsequently used $275 million of these proceeds to redeem all of its outstanding 2018 Senior Subordinated Notes on February 2, 2017. The remainder was applied to reduce the outstanding balance on the Company’s credit facility. Whiting projects a 2017 capital budget of $1.1 billion. The Company plans to invest $1,060 million of the 2017 capital budget on development activity in its core Williston Basin and DJ Basin areas, which represents 96% of the total budget. It plans to run five rigs and spend $580 million on development activities in the Williston Basin where it targets the Bakken/Three Forks formations and run one rig and spend $420 million on development activities in the DJ Basin where it targets the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. The DJ Basin activities include the planned completion of 105 drilled uncompleted (DUC) wells. In addition, $60 million has been budgeted for non-operated drilling located primarily in the Williston Basin. Based on the 2017 capital budget, the Company forecasts 2017 production of 45.0 to 46.0 MMBOE (123,000 to 126,000 BOE/d). Production is forecast to increase to a fourth quarter average rate of 140,000 BOE/d. This equates to a 23% projected increase from first quarter to fourth quarter 2017. At December 31, 2016, Whiting’s proved reserves totaled 615.5 MMBOE. 47% of year-end 2016 proved reserves were proved developed reserves and 81% of year-end 2016 proved reserves were crude oil and NGLs. Adding back asset sales that totaled 114.4 MMBOE and applying a price neutral (equivalent to the SEC 2015 price deck case) scenario, proved reserves would have totaled 851.5 MMBOE. (1) This represents an increase of 4% relative to year-end 2015 despite a 76% decrease in capital spending from $2.3 billion in 2015 to $554 million in 2016. Whiting controls 735,968 gross (443,839 net) acres in the Williston Basin and 157,178 gross (132,184 net) acres at its Redtail play in the DJ Basin. In the fourth quarter 2016, total net production for the Company averaged 118,890 BOE/d. The Bakken/Three Forks play in the Williston Basin averaged 108,850 BOE/d, an increase of 3% over the third quarter. The Redtail Niobrara/Codell play in the DJ Basin averaged 9,210 BOE/d. Increase in 90-Day Average Production Rate per Well Reflects Quality of Whiting Acreage and Technology. In 2016, Whiting’s 90-day production rate per well in the Williston Basin averaged 1,057 BOE/d. This was a 42% increase over 2015 and an 84% increase over 2014. The Company attributes this primarily to an improvement in completion technology in combination with high-graded drilling activity. Since 2014, Whiting has more than doubled the sand volume per well from 3.6 million pounds to over 8 million pounds. It has also increased the number of effective entry points through the addition of perforation clusters and the application of diverter technology. These technology improvements create a more extensive fracture network near the wellbore that enhances well productivity and ultimate recovery from the reservoir. Williston Basin Large Volume Completions Continue to Exceed Expectations. During the fourth quarter, Whiting completed 25 new wells that produced for 30 or more days. The average 30-day production rate for these wells was 1,754 BOE/d. The average well was completed with 8.5 million pounds of sand. Four of the wells completed during the quarter incorporated over 10 million pounds of sand. On average, these wells are tracking a 1.5 MMBOE type curve. Testing Enhanced Completions and Longer Laterals at Redtail. In January 2017, Whiting put a completion crew to work at its Redtail play in Weld County, Colorado that targets the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. The Company plans to test enhanced completion designs that incorporate additional frac stages (50 versus a standard of 40) and higher sand volumes (8 million pounds versus a standard of 4.5 million pounds) in a 7,500’ lateral. It also plans to complete approximately 34 longer lateral (10,000’ versus a standard of 7,500’) wells in 2017. Other Financial and Operating Results The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2016 and 2015: A summary of production, cash revenues and cash costs on a per BOE basis is as follows: The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three months and full-year ended December 31, 2016. Outlook for First Quarter and Full-Year 2017 The following table provides guidance for the first quarter and full-year 2017 based on current forecasts, including Whiting’s full-year 2017 capital budget of $1.1 billion: Whiting is 53% hedged for 2017 as a percentage of December 2016 production. The following summarizes Whiting’s crude oil hedges as of January 3, 2017: For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2016, to be filed with the Securities and Exchange Commission. The Company’s management will host a conference call with investors, analysts and other interested parties on Wednesday, February 22, 2017 at 11:00 a.m. EST (10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting’s fourth quarter and full year 2016 financial and operating results. Participants are encouraged to pre-register for the conference call by clicking on the following link: http://dpregister.com/10097021. Callers who pre-register will be given a unique telephone number and PIN to gain immediate access on the day of the call. Those without internet access or unable to pre-register may join the live call by dialing: (877) 328-5506 (U.S.); (866) 450-4696 (Canada) or (412) 317-5422 (International) to be connected to the call. Presentation slides will be available at http://www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled "Presentations & Events." A telephonic replay will be available beginning one to two hours after the call on Wednesday, February 22, 2017 and continuing through Wednesday, March 1, 2017. You may access this replay at (877) 344-7529 (U.S.); 855-669-9658 (Canada) or (412) 317-0088 (International) and enter the pass code 10097021. You may also access a web archive at http://www.whiting.com beginning one to two hours after the conference call. Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, natural gas and natural gas liquids primarily in the Rocky Mountains region of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and Montana and Niobrara play in northeast Colorado. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit http://www.whiting.com. This news release contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. These risks and uncertainties include, but are not limited to: declines in or extended periods of low oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness, ability to comply with debt covenants and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; the potential impact of changes in laws, including tax reform, that could have a negative effect on the oil and gas industry; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption “Risk Factors” in our Quarterly Report on Form 10-Q for the period ended September 30, 2016 and Annual Report on Form 10-K for the period ended December 31, 2015. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.


Husinec A.,Lawrence University | Harman C.A.,Whiting Petroleum Corporation | Regan S.P.,University of Massachusetts Amherst | Mosher D.A.,Rensselaer Polytechnic Institute | And 2 more authors.
AAPG Bulletin | Year: 2012

Depositional sequences capped by peritidal carbonates and breccias on the Aptian Adriatic carbonate platform, Croatia, were studied to evaluate evidence for glacioeustasy within an age framework constrained by carbon-isotope chemostra-tigraphy. Sequence Adi (17-60-m [56-197-ft] thick; uppermost Barremian-lower Aptian) is dominated by shallow subtidal parasequences. Sequence Ad2 (7-13-m [23-43-ft] thick; lower Aptian-lowermost upper Aptian) contains oceanic anoxic event (OAE) la, associated with lagoonal laminated carbonates. Sequence Ad3 (3-8-m [10-26-ft] thick) probably is lower upper Aptian and likely is separated by a major hiatus from sequence Ad4 (8-20-m [26-66-ft] thick; uppermost Aptian), which spans OAElb. Both Ad2 and Ad3 are dominated by peritidal parasequences updip in the lower transgressive systems tract and upper highstand systems tract and by subtidal parasequences elsewhere, whereas sequence Ad4 is dominated by shallow subtidal parasequences. Low accommodation rates (4.0-6.0 cm [1.6-2.4 in.] in the earliest Aptian, decreasing to approximately 1.0 cm/k.y. [0.3 in./k.y.] later) promoted widespread breccia development during relative sea level falls, aided by tectonic warping. The sequence-capping breccias, eccentricity-dominated cyclicity, restriction of peritidal facies to late highstands, and coeval off-shelf oxygen-isotope records all suggest that sea level falls occurred during times of cooling and had a significant glacioeustatic component. These intermittent cooler periods and continental ice buildup punctuated the Aptian greenhouse climate. © 2012. The American Association of Petroleum Geologists. All rights reserved.


Curnow J.S.,Whiting Petroleum Corporation | Tutuncu A.N.,Colorado School of Mines
Society of Petroleum Engineers - SPE Hydraulic Fracturing Technology Conference, HFTC 2016 | Year: 2016

The benefits of hydraulic fracturing horizontal wells in unconventional reservoirs for production enhancement are evident; however, the best methods to truly increase recovery efficiency through these stimulations are still under examination. Analogous to how operators and service companies discovered that Barnett-style slickwater treatments were not successful in all reservoirs, companies are beginning to recognize the importance of engineered stimulations, specifically in regard to geomechanics. Rather than perforating for only production purposes, hydraulic fracturing design has now turned its focus to perforating for reservoir rock stimulation. Enhanced fracture network complexity through induced fractures greatly increases the contact area and reservoir drainage for maximum productivity. However, to accomplish the stimulation of both primary and secondary fracture networks, the coupled behaviors of geomechanics and fluid flow in response to the hydraulic fracturing operations must be considered. In this research study, development of a coupled geomechanics and fluid flow model for the purpose of hydraulic fracture design optimization through the evaluation of different stimulation patterns with primary focus on how the stress and strain distributions within the reservoir that affect porosity and permeability, ultimately influence flow has been discussed in detail. The patterns under consideration include the Zipper, Texas Two-Step, and Modified Zipper designs. Although the Texas Two-Step Pattern requires a special down-hole tool and as such is very difficult operationally to perform, it is being considered in this analysis for conceptual purposes concerning the stress behavior within a single lateral well. Furthermore within these patterns, the well locations and hydraulic fracture properties have been analyzed to determine the optimum design for a shale oil reservoir based on recovery efficiency and generated fracture complexity. The results of this study indicate that with the staggered fracture placement offered by the Modified Zipper Pattern, a highly conductive secondary complex fracture network is generated allowing for enhanced hydrocarbon recovery. In comparison to the Zipper and Texas Two-Step Patterns, the Modified Zipper Pattern reduces the stress anisotropy within the formation to a much greater extent, aiding in the fracture generation process to increase the flow area. This advantage coupled with its high oil recovery factor and potential for greater drilling density discerns the Modified Zipper as the ideal pattern for the development of an Eagle Ford-Type shale oil reservoir. Copyright 2016, Society of Petroleum Engineers.


Rodrigues P.E.,Whiting Petroleum Corporation | Batzle M.L.,Colorado School of Mines
Geophysics | Year: 2015

Although heavy oils are an enormous resource and a common seismic monitoring target, their geophysical properties remain poorly understood. The shear modulus is of particular interest, because under the right conditions, these oils can transmit S-waves. However, there is a large uncertainty on how to measure the shear modulus of heavy oils. The use of the rheometer, common in chemical engineering applications, has been proposed as a good alternative to tension/compression techniques. Rheometers are an attractive alternative for measuring the shear modulus because of their widespread use and availability. In order to test the validity of the rheometer as a method to measure the shear modulus of heavy oils for geophysical applications, we tested two samples using techniques familiar to geophysics (tension/ compression and ultrasonic) and compared the results with the rheometer measurements. We noticed a difference in the measured shear modulus between the two techniques. The samples showed a solid-like behavior when tested in the tension/ compression equipment while behaving liquid-like in the rheometer. Both measurements were done in the linear regime (in which there is no change in modulus with amplitude), indicative of the potential presence of two linear viscoelastic regimes (LVRs) at different amplitudes. We developed a model that explains the presence of the two LVRs for heavy oils with a large content of resins and asphaltenes and at temperatures that allows the formation of large aggregates. We analyzed the presence of the two LVRs in terms of the weak interaction that appeared between aggregates when subjected to small-amplitude strains, resulting in a solid-like behavior; those weak interactions were not present when the sample was subjected to larger strains resulting in a liquid-like behavior. © 2015 Society of Exploration Geophysicists.


Rodrigues P.E.,Whiting Petroleum Corporation | Rodrigues P.E.,Colorado School of Mines
Fuel | Year: 2015

Viscosity of heavy oil constitutes an important property that governs the productivity of these reservoirs. The viscosity of these crude oils is highly dependent on many variables like temperature, frequency, and strain amplitude. In this paper we show that viscosity measurements of heavy oils can also depend on a measurement variable like the gap thickness in a parallel plate rheometer. In this paper we measured how the confinement of heavy oils between parallel plates induces an increase in shear modulus. We propose that the increase in shear modulus can be linked to the surface-active nature of heavy oils that can cause re-orientation of the molecules at the surface of the plates and producing a measurable increase in the shear modulus. The findings were observed in three different samples of heavy oils. The results of this work have major implications in the measurement of viscosity of heavy oils but more importantly in the flow of heavy oils in porous media. © 2015 Elsevier Ltd All rights reserved.


DENVER--(BUSINESS WIRE)--Whiting Petroleum Corporation Senior Vice President and CFO Michael Stevens to Present at Bank of America Merrill Lynch Global Energy Conference


News Article | November 21, 2016
Site: www.businesswire.com

DENVER--(BUSINESS WIRE)--Whiting Petroleum Corporation Enters into Sales Agreements for North Dakota Midstream Assets


News Article | October 27, 2016
Site: www.businesswire.com

DENVER--(BUSINESS WIRE)--Whiting Petroleum Corporation Announces Third Quarter 2016 Financial and Operating Results


DENVER--(BUSINESS WIRE)--Whiting Petroleum Corporation (NYSE: WLL) today announced that it gave notice to mandatorily convert $716.8 million of outstanding mandatory convertible notes into shares of Whiting common stock on December 19, 2016. Prior to such notice, holders of $4.2 million of outstanding mandatory convertible notes had voluntarily converted such notes into shares of Whiting common stock. As a result of the mandatory conversion and the voluntary conversions, the Company will have issued approximately 77.6 million shares of its common stock to retire all of the $721.0 million of mandatory convertible senior notes and mandatory convertible senior subordinated notes identified in the chart below. James J. Volker, Whiting’s Chairman, President and CEO, commented, “Upon the completion of this conversion, we will reduce our debt by $721 million. After the conversion and the sale of our North Dakota midstream assets for $375 million that we anticipate to close in early 2017, we will have reduced our debt by $2.3 billion or 41% since March 31, 2016, approximately equal to all the debt assumed in the Kodiak acquisition. We expect these accomplishments to provide Whiting with greater financial flexibility to maximize the value of its premier assets in the North Dakota Bakken / Three Forks and DJ Basin Niobrara / Codell plays where we have 11,676 potential gross drilling locations. As can be seen in our corporate presentation, based on the latest 12 months of data, we rank as the top Bakken operator in terms of initial 90-day average production rates for all operators with more than 10 wells. Such results do not fully reflect the impact of our recent super, 10+ million pound sand volume completions where our initial Bakken / Three Forks wells are tracking at or above a 1.5 million BOE (barrel oil equivalent) type curve for a completed well cost of only $7.5 million. Having achieved this debt reduction target, our enhanced balance sheet and strong hedge position for 2017 should allow us to rapidly develop our top-tier properties and accelerate our growth.” The following table sets forth the aggregate principal amount of each series of mandatory convertible notes that have been or will be converted into shares of Whiting common stock. Pursuant to the terms of the convertible notes, holders of the mandatory convertible notes will also receive accrued and unpaid interest to the conversion date. Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, natural gas and natural gas liquids primarily in the Rocky Mountain region of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and Niobrara play in northeast Colorado. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit http://www.whiting.com. This news release contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. These risks and uncertainties include, but are not limited to: declines in or extended periods of low oil, NGL or natural gas prices; the ability to successfully complete the sale of Whiting’s North Dakota midstream assets on anticipated terms and timetable; our level of success in exploration, development and production activities; risks related to our level of indebtedness, ability to comply with debt covenants and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal Government that could have a negative effect on the oil and gas industry; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; cyber security attacks or failures of our telecommunication systems; and other described under the caption “Risk Factors” in our Quarterly Report on Form 10-Q for the period ended September 30, 2016 and Annual Report on Form 10-K for the period ended December 31, 2015. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.

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