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LONDON--(BUSINESS WIRE)--The dramatic resurgence in US upstream M&A activity since mid-2016 has been driven by the vast resource potential and compelling economics in the Permian Basin. Deals in the Permian accounted for 48%, or $24.8 billion, of total US transaction value in 2016 and an astonishing 77% of the $18.5 billion in deals announced in the first 45 days of 2017, per 1Derrick. Although the buyers have been almost exclusively North America based firms, 1Derrick’s analysis suggests that the M&A market could be on the cusp of a second wave of international investments in US unconventional resource plays. 1Derrick has unveiled new proprietary research that will assist European, Asian, and other investors in identifying and evaluating potential M&A opportunities. “The attractiveness of a de-risked US resource play investment to international buyers is reflected in the capital allocations of major US-based firms with a global portfolio,” said Mangesh Hirve, Chief Operating Officer of 1Derrick. “For example, Chevron is boosting Permian investment by 45% despite an overall 11% reduction in total investment, while Occidental Petroleum is doubling its spending in the play from $600 million to $1-1.4 billion. ExxonMobil made its largest acquisition since it bought $1.6 billion in Bakken assets from Denbury Resources in 2012 with its $5.6 billion January 2017 purchase of Delaware Basin properties. International firms with a limited US portfolio may conclude that US shale is a crucial part of a global upstream portfolio. As research providers, we have expanded our offerings to guide them to the most attractive investments.” The first wave of international investments in US unconventional plays began in 2008 with Statoil (Marcellus) and BP (Fayetteville) acquiring acreage from Chesapeake Energy. Activity surged in 2010-12 as the value of transactions with a European or Asia-Pacific buyer totaled over $67 billion. Major European company deals included the 2010 entrance into the Marcellus by BG and Shell, Statoil’s $4.7 billion 2011 purchase of Bakken-focused Brigham Resources, and Shell’s $1.94 billion purchase of Chesapeake’s southern Delaware Basin assets. Significant transactions by Asian and Australian buyers include mining conglomerate BHP Billiton acquiring Petrohawk Energy for $15 billion, Devon and Sinopec forming $2.2 billion JV for five unconventional plays in US and Pioneer and Sinochem forming $1.7 billion Wolfcamp JV. International investment in US shale dropped off dramatically after 2013, with just $825 million spent by European firms and $1.5 billion by Asian buyers in and after 2014. The plunge in oil prices that roiled the entire oil and gas industry virtually brought the international M&A market to a halt. However, a new investment paradigm has been forged in the aftermath of the oil price crisis, one that once again highlights the attractiveness of US unconventional resources. Dramatically lower drilling, completion and lease operating costs and soaring well productivity have resulted in the best Permian acreages offering IRRs of over 50% even at oil prices under $50/bbl. International investors have demonstrated a willingness to pay a premium to enter de-risked plays with predictable costs in which discovered resources can quickly be converted to production. A bonus is a regulatory environment that may provide additional incentives for US oil and gas. Some Asian companies have already signaled the coming of a potential second wave of international investments in the US resource plays. Yantai Xinchao acquired Midland Basin oil fields for $1.08 billion. Meidu acquired assets from Devon and Silver Oak, and Shun Cheong acquired Eagle Ford assets from Stonegate for $278 million. Also, Thai mining company Banpu acquired Marcellus assets from Chief Oil & Gas and Range Resources. Recent reports indicate Osaka Gas, Kogas and Sinochem are also exploring US resource play investments. “European and Asian firms face two major challenges in identifying the right opportunities in the US resource plays,” said 1Derrick’s Ajit Thomas. “The first is unveiling the full opportunity set in a region where a large portion of the available acreage is held by a plethora of private companies and investment entities with little public disclosure. The second is calculating an accurate valuation of the properties by assessing the drilling results and comparable transaction values of nearby acreage. 1Derrick has developed proprietary research to address both challenges.” To help clients discover all potential opportunities, 1Derrick has uncovered and examined hundreds of “stealth” transactions that were never publicly disclosed. These include, for example, more than 20 significant transactions by Double Eagle Energy, which recently sold 71,000 net acres in the Midland Basin to Parsley Energy for $2.8 billion. This exhaustive research effort, which has resulted in the most comprehensive US deals database in the industry, has also revealed the full holdings of more than 60 private companies, most of them private-equity funded. These include Forge Energy (backed by EnCap and Pine Brook), which has 75,000 net acres in Andres, Gaines, Lubbock, and Pecos counties; Steward Energy II (backed by Natural Gas Partners), which has made multiple acquisitions in Yoakum County; and CrownRock, a JV between CrownQuest and Lime Rock Partners, which has completed several transactions in Howard and Martin counties in the Midland Basin. 1Derrick has also translated its proprietary research into comprehensive acreage maps that display the full holdings of both public and private E&P companies. These maps allow prospective buyers to quickly access analysis on transactions involving nearby acreage. Clients can also identify the owners of the properties and follow through with research on the results of recent drilling and completion activities. Among the large private holdings detailed on 1Derrick maps are the 83,000 net acres in Scurry, Midland, Martin, Glasscock, Howard, Reagan, and Crockett counties held by Trail Ridge Energy, backed by Riverstone Holdings and Trilantic Capital Partners; a 65,000-acre JV between Henry Resources and Riverstone-funded Carrier Energy; and 78,000 acres across the Permian owned by Vermilion Cliffs Partners, which is backed by Old Ironsides Energy. 1Derrick’s Mangesh Hirve concluded, “To date, the surge in Permian activity has been fueled by stock-based acquisitions by US public companies. International companies will bring cash to the table, which should provide them with a rich base of opportunities from PE-backed firms and other investors seeking quick, liquid monetization of their holdings. We will continue to evolve our proprietary research to assist international buyers in accessing these opportunities.” 1Derrick (www.1derrick.com), is an independent oil and gas research firm with offices in Houston, New York, London, Singapore, and Bangalore. For more information on 1Derricks’s industry-leading data and analysis, including the new proprietary research on the Permian Basin and other US unconventional plays, please contact Ajit Thomas at Ajit.Thomas@1Derrick.com or 1.646.284.8661.


NEW YORK, November 7, 2016 /PRNewswire/ -- Stock-Callers.com has lined up the following Independent Oil and Gas equities for review: Oasis Petroleum Inc. (NYSE: OAS), Denbury Resources Inc. (NYSE: DNR), WPX Energy Inc. (NYSE: WPX), and ConocoPhillips (NYSE: COP). Oil prices dropped on...


Palisch T.T.,Carbo Ceramics | Handren R.J.,Denbury Resources
SPE Production and Operations | Year: 2010

The evolution of fracturing technology has provided the industry with numerous advances, ranging from sophisticated fluid systems to tip-screenout designs to propagation modeling. Interestingly, these advances typically have focused on conventional designs that use a crosslinked-fluid system. However, as the development of unconventional (e.g., tight gas, shales, coalbed methane) or underpressured reservoirs has increased, so has the demand for innovative hydraulic-fracture designs. The most recent of these design changes has been the popular method of placing proppant with slickwater, linear gel, or hybrid treatments. Although our industry has significant expertise in fracture design, most of our experience has been in conventional crosslinked-fluid systems. However, there are many aspects of crosslinked-fluid design that either do not apply to slickwater treatments or, in some cases, are contrary to the requirements of slickwater treatments. This paper will begin by reviewing the motivation, benefits, and concerns with slickwater fracturing and discuss why this seemingly old method has regained popularity over conventional crosslinked designs in many reservoirs. In addition, the authors will detail some of the important theories related to slickwater fracturing, including fracture width and complexity, proppant transport and settling, and conductivity requirements. In each scenario, emphasis will be placed on the different strategy employed compared to crosslinked-fluid designs, and the mistakes or misunderstandings that are frequently made will be highlighted. Where appropriate, laboratory testing, field measurements, reference material, and other resources are presented to support the observations made by the authors. This paper will serve as a resource to any engineer or technician who is designing/pumping slickwater fracs, or who is considering this technology for potential application. By applying the concepts presented in this paper, engineers will be able to appropriately evaluate the potential benefits of using this technique in their completions, as well as draw on the experiences of others to take full advantage of this technology. Copyright © 2010 Society of Petroleum Engineers.


Trademark
Denbury Resources | Date: 2012-09-27

Acquisition of oil, gas, helium and carbon dioxide assets. Extraction of oil, gas, carbon dioxide and helium; Laying, constructing, maintaining and operating pipelines; Drilling for oil, gas, helium and carbon dioxide; Recovery and production of oil, gas, helium and carbon dioxide; Enhanced oil recovery; Tertiary oil recovery. Transportation by pipeline. Exploration and searching for oil, gas, helium and carbon dioxide.


An apparatus is provided for maintaining a steady flow rate and pressure of a carbon dioxide stream at high pressure when a low-pressure source of the carbon dioxide varies with time. Liquid level in an accumulator that is sized to accommodate variations in supply rate is controlled by sub-cooling of liquid entering the accumulator and heating in the accumulator, the sub-cooling and heating being controlled by a pressure controller operable in the accumulator.


NEW YORK, December 19, 2016 /PRNewswire/ -- For today, Stock-Callers.com turns to some equities in the Independent Oil and Gas space to see how current oil prices have affected their most recent performances. Stocks to assess are Oasis Petroleum Inc. (NYSE: OAS), Denbury Resources...


News Article | November 3, 2016
Site: globenewswire.com

PLANO, Texas, Nov. 03, 2016 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”) today announced a net loss of $25 million, or $0.06 per diluted share, for the third quarter of 2016.  Excluding special items, the Company reported adjusted net income(1) (a non-GAAP measure) for the quarter of $1 million, or $0.00(1)(2) per diluted share.  Adjusted net income(1) for the third quarter of 2016 differs from the quarter’s GAAP net loss due to the exclusion of (1) a $76 million ($48 million after tax) full cost pool ceiling test write-down, (2) a $29 million ($18 million after tax) gain due to noncash fair value adjustments on commodity derivatives(1) (a non-GAAP measure) and (3) an $8 million ($5 million after tax) gain on debt extinguishment, with the GAAP and non-GAAP measures reconciled in tables beginning on page 7. Sequential and year-over-year comparisons of selected quarterly financial items are shown in the following table: (1)    A non-GAAP measure.  See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors. (2)    Calculated using average diluted shares outstanding of 390.2 million, 372.4 million, and 350.9 million for the three months ended September 30, 2016, June 30, 2016 and September 30, 2015, respectively. (3)    Adjusted cash flows from operations reflects cash flows from operations before working capital changes.  Adjusted cash flow from operations for the three-month period ended June 30, 2016 includes a $28 million payment to Evolution in connection with our settlement agreement to resolve all outstanding disputes and claims.  Excluding these payments, adjusted cash flows from operations would have totaled $121 million for the three months ended June 30, 2016. (4)    Lease operating expenses for the three months ended September 30, 2016, include repair costs at Thompson Field following the weather-related impacts during the second quarter, and for the three months ended September 30, 2015, include a reimbursement for a retroactive utility rate adjustment ($10 million) and an insurance reimbursement for previous well control costs ($4 million).  Excluding these items, lease operating expenses per BOE would have averaged $18.23 and $19.43 for the three months ended September 30, 2016 and 2015, respectively. (5)    Total continuing production excludes production from the Williston Basin sold during the third quarter of 2016 and other minor property divestitures. Phil Rykhoek, Denbury’s CEO, commented, “In the third quarter of 2016, we continued to execute on our plan of optimizing our business and reducing costs, preserving cash and liquidity and reducing leverage.  Even though realized oil prices were in the low $40s for the third quarter of 2016, we generated positive cash flow and slightly positive adjusted net income.  On a sequential basis, our adjusted cash flow and income decreased as the remaining portion of our most favorable hedges ended in the second quarter of 2016, which reduced our average realized price per barrel (including hedges) by approximately $10.  Although our cash costs per barrel of oil equivalent (“BOE”) increased slightly this quarter as a result of lower production and the expense of repairs at Thompson Field following the weather-related flooding during the second quarter, many of the cost savings achieved throughout 2016 will be sustainable as oil prices improve and have become a permanent part of our business going forward. “While our third quarter production was slightly below our expectations due to unexpected downtime at multiple fields during the quarter, production has largely been restored at these fields and we expect our fourth quarter production to be essentially flat, or decline slightly, compared to our total third quarter production.  Therefore, we still expect to be within our original guidance range, as adjusted for property sales. “We made additional progress during the quarter on our goal to reduce debt.  The sale of our non-core Williston assets, which closed at the end of August, provided liquidity which enabled us to repurchase $30 million face amount of our senior subordinated notes in the open market for $21 million.  In addition, we reduced the outstanding balance on our bank credit facility by $60 million from the end of the second quarter.  While these debt reductions are smaller in nature than those during the first half of the year, when added to our open-market repurchases in the first quarter and the debt exchange in the second quarter, we have reduced our debt principal by $562 million this year.  With the recent announcement that our lender group reaffirmed our borrowing base and lender commitments at $1.05 billion in our semiannual borrowing base redetermination, our bank line continues to provide us with significant flexibility as we move into 2017, with over $700 million of credit available to us.” Denbury’s continuing production averaged 60,714 BOE per day (“BOE/d”) during the third quarter of 2016, including 37,199 barrels per day (“Bbls/d”) from tertiary properties and 23,515 BOE/d from non-tertiary properties.  Continuing production excludes production from assets in the Williston Basin (the “Williston Assets”) which were sold during the third quarter of 2016 and other minor property divestitures, which combined volumes totaled 819 BOE/d during the third quarter of 2016, compared to 1,530 BOE/d during the second quarter of 2016 and 1,957 BOE/d during the third quarter of 2015.  Third quarter of 2016 production was 96% oil, similar to that in the prior-year period.  Continuing production in the third quarter of 2016 decreased 4% sequentially and 13% compared to the third quarter of 2015.  As discussed in the Company’s second quarter earnings release, third quarter of 2016 production continued to be impacted by the weather-related downtime at Thompson and Conroe fields due to flooding and damage caused by strong thunderstorms in the Houston area during April and May this year; however, both fields were largely returned to full production by the end of September, and combined production from these two fields was up slightly sequentially.  Most of the sequential quarterly production decline was related to the Company’s tertiary production, which was impacted to some degree by unplanned downtime at some fields and a planned facility turnaround at Tinsley Field.  This production decline was offset in part by continued tertiary production growth at Delhi Field. In analyzing the 13% decline in continuing production from the third quarter of 2015, approximately half of the production decline was due to weather-related shut-in production at Thompson and Conroe fields, production that was shut-in due to economics, the planned downtime at Tinsley Field and unplanned downtime at other fields.  The remaining decline is largely due to natural production declines based on the Company’s lower capital spending level, offset in part by continued tertiary production growth at the Company’s Delhi and Bell Creek fields. The Company estimates that its production decline for the full year will be in line with its anticipated decline after adjusting for the asset sales and weather related impacts, and it currently estimates that its full-year 2016 production will range between 64,000 BOE/d and 65,000 BOE/d, with production for the remainder of the year anticipated to be relatively flat or slightly lower than the total production levels during the third quarter of 2016.  As of September 30, 2016, the Company estimates that approximately 2,000 BOE/d of production remained shut in attributable to uneconomic wells, a reduction of approximately 600 BOE/d from similar estimates as of June 30, 2016, primarily due to the Williston Asset sale. Denbury’s average realized oil price per Bbl, excluding derivative settlements, was $43.45 in the third quarter of 2016, compared to $43.38 in the second quarter of 2016 and $45.74 in the prior-year third quarter.  Including derivative settlements, Denbury’s average realized oil price per Bbl was $42.12 in the third quarter of 2016, compared to $52.61 in the second quarter of 2016 and $71.32 in the prior-year third quarter.  The oil price realized relative to NYMEX oil prices (the Company’s NYMEX oil price differential) in the third quarter of 2016 was $1.57 per Bbl below NYMEX prices, compared to a differential of $2.18 per Bbl below NYMEX in the second quarter of 2016 and $0.96 per Bbl below NYMEX in the third quarter of 2015. The Company’s total lease operating expenses in the third quarter of 2016 were $107 million, a decrease of 6% on an absolute-dollar basis when compared to the third quarter of 2015.  When normalized to exclude reimbursements of $14 million in the prior-year third quarter ($10 million for a retroactive utility rate adjustment and $4 million for an insurance reimbursement), lease operating expenses decreased 17% compared to the third quarter of 2015.  These reductions were due to cost decreases in most lease operating expense categories, the most significant of which included (1) a decrease in workover costs and repairs primarily as a result of reduced failures, (2) lower power costs due to lower usage and rates, (3) lower CO expense resulting from a decrease in CO injection volumes, and (4) lower Company labor costs resulting from a reduction in force.  During the third quarter of 2016, the Company’s CO use further declined to 458 million cubic feet per day, a decrease of 32% when compared to the third quarter of 2015.  Sequentially, lease operating expenses increased 7% on an absolute-dollar basis and 10% on a per-BOE basis between the second and third quarters of 2016.  The increase on an absolute-dollar basis was primarily due to increased repair costs at Thompson Field following the weather-related events of the second quarter of 2016.  Adjusting for the weather-related cost impacts at Thompson Field, lease operating expenses per BOE of $18.82 would have been $18.23 for the three months ended September 30, 2016. Taxes other than income, which includes ad valorem, production, and franchise taxes, decreased $5 million from the prior-year third quarter level due primarily to lower ad valorem taxes in 2016 and a decrease in severance taxes due to lower oil and natural gas revenues. General and administrative expenses were $25 million in the third quarter of 2016, decreasing $8 million, or 25%, from the prior-year third quarter level.  This reduction was primarily due to a reduction in headcount, which has resulted in lower employee compensation and related costs. Interest expense, net of capitalized interest, decreased to $25 million in the third quarter of 2016, compared to $39 million in the third quarter of 2015.  As a result of the Company’s debt exchange transactions completed in May 2016, interest expense in the third quarter of 2016 excludes approximately $13 million of interest on the Company’s new 9% Senior Secured Second Lien Notes due 2021 because it is recorded as debt for financial reporting purposes and is therefore not reflected as interest expense.  Cash interest, including the portion of interest recorded as debt, decreased approximately $2 million from the prior-year quarter. As a result of the continued decrease in average commodity pricing compared to 2015 levels, the Company recognized a full cost pool ceiling test write-down of $76 million during the third quarter of 2016, compared to $479 million during the second quarter of 2016 and $1.8 billion during the third quarter of 2015.  In determining these write-downs, the Company is required to use the average rolling first-day-of-the-month NYMEX oil and natural gas prices for the preceding 12 months, adjusted for market differentials by field.  The preceding 12-month NYMEX prices averaged $41.68 per Bbl for crude oil for the period ended September 30, 2016, down from $43.12 per Bbl for the period ended June 30, 2016 and $59.21 per Bbl for the period ended September 30, 2015. Denbury’s overall depletion, depreciation, and amortization (“DD&A”) rate was $9.72 per BOE in the third quarter of 2016, compared to $18.48 per BOE in the prior-year third quarter and $11.34 per BOE in the second quarter of 2016, with the decreases primarily driven by a reduction in depletable costs resulting from the full cost pool ceiling test write-downs recognized during 2015 and the first half of 2016, as well as an overall reduction in future development costs and lower production volumes, partially offset by reductions in proved oil and natural gas reserve quantities. Payments on settlements of oil and natural gas derivative contracts were $7 million in the third quarter of 2016, compared to receipts of $52 million in the second quarter of 2016 and receipts of $161 million in the prior-year third quarter.  These settlements resulted in a decrease in average net realized prices of $1.29 per BOE in the third quarter of 2016, compared to increases of $8.86 per BOE in the second quarter of 2016 and $24.46 per BOE in the third quarter of 2015. Denbury’s effective tax rate for the third quarter of 2016 was 37.2%, consistent with the Company’s statutory rate of 38%, and up from 24.6% in the prior-year third quarter. As previously disclosed, the Company’s borrowing base under its senior secured bank credit facility (the “Facility”) was reaffirmed at the previously existing amount of $1.05 billion during the fall 2016 semiannual borrowing base redetermination, the same amount committed by the banks to loan under the Facility.  A total of $260 million of borrowings were outstanding under the Facility as of September 30, 2016, a decrease of $60 million from the level outstanding as of June 30, 2016.  There were no changes to the terms or conditions of the Facility, and the next regularly scheduled borrowing base redetermination is set to occur on or about May 1, 2017. During the third quarter of 2016, the Company repurchased approximately $30 million principal amount of its outstanding senior subordinated notes in open-market transactions for approximately $21 million. The Company’s 2016 capital budget, excluding acquisitions and capitalized interest, remains unchanged from the previously estimated amount of approximately $200 million.  The capital budget consists of approximately $145 million of tertiary, non-tertiary, and CO supply and pipeline projects, plus approximately $55 million of estimated capitalized costs (including capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs).  Of this combined capital expenditure amount, approximately $146 million (73%) has been incurred through the third quarter of 2016. Denbury management will host a conference call to review and discuss third quarter 2016 financial and operating results, as well as financial and operating guidance for the remainder of 2016, today, Thursday, November 3, at 10:00 A.M. (Central).  Additionally, Denbury has published presentation materials on its website which will be referenced during the conference call.  Individuals who would like to participate should dial 800.230.1093 or 612.332.0226 ten minutes before the scheduled start time.  To access a live webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company’s website at www.denbury.com.  The webcast will be archived on the website, and a telephonic replay will be accessible for at least one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 361970. Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO enhanced oil recovery operations.  For more information about Denbury, please visit www.denbury.com. This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including estimated 2016 production and capital expenditures and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K.  These risks and uncertainties are incorporated by this reference as though fully set forth herein.  These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met.  Actual results may vary materially.  In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date.  Denbury assumes no obligation to update its forward-looking statements. FINANCIAL AND STATISTICAL DATA TABLES AND RECONCILIATION SCHEDULES Following are unaudited financial highlights for the comparative three and nine month periods ended September 30, 2016 and 2015 and the three month period ended June 30, 2016.  All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1. The following information is based on GAAP reported earnings (along with additional required disclosures) included or to be included in the Company’s periodic reports: Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net loss measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations.  Management believes that adjusted net income may be helpful to investors by eliminating the impact of noncash and/or special or unusual items not indicative of our performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company’s ongoing operational results and trends.  Adjusted net income should not be considered in isolation, as a substitute for, or more meaningful than, net loss or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance. (1)    The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period. (2)    Insurance and other reimbursements, comprised of a reimbursement for a retroactive utility rate adjustment ($9.6 million) and an insurance reimbursement for previous well control costs ($4.1 million) during the three and nine months ended September 30, 2015. (3)    Full cost pool ceiling test write-downs related to the Company’s oil and natural gas properties. (4)    Charge to fully impair the carrying value of the Company’s goodwill. (5)    Gain on extinguishment related to open market debt purchases during the three and nine months ended September 30, 2016, and the debt exchange during the three months ended June 30, 2016 and nine months ended September 30, 2016. (6)    Settlements related to previously outstanding litigation, the most significant of which pertaining to a $28 million payment to Evolution in connection with the settlement resolving all outstanding disputes and claims. (7)    Write-off of debt issuance costs associated with the Company’s senior secured bank credit facility, related to reductions in the Company’s lender commitments resulting from (1) the February 2016 amendment and (2) the May 2016 redetermination. (8)    Severance-related payments associated with the Company’s February-2016 workforce reduction. (9)    Transaction costs related to the Company’s debt exchange during the three months ended June 30, 2016 and nine months ended September 30, 2016 and a loss on sublease during the nine months ended September 30, 2016. (10)  The estimated income tax impacts on adjustments to net loss are generally computed based upon a statutory rate of 38%, applicable to all periods presented, with the exception of the write-down on oil and natural gas properties, which are computed individually based upon the Company’s effective tax rate.  In addition, recorded valuation allowances of $30.5 million have been adjusted for the nine months ended September 30, 2015. Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Unaudited Condensed Consolidated Statements of Cash Flows.  Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables.  Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. (1)    The three-month period ended June 30, 2016 and the nine-month period ended September 30, 2016 include a $28 million payment to Evolution in connection with our settlement agreement to resolve all outstanding disputes and claims.  The nine-month period ended September 30, 2016 also includes severance-related payments associated with the 2016 workforce reduction of approximately $9 million.  Excluding these payments, adjusted cash flows from operations would have totaled $121 million for the three months ended June 30, 2016 and $248 million for the nine months ended September 30, 2016. Reconciliation of commodity derivatives income (expense) (GAAP measure) to noncash fair value adjustments on commodity derivatives (non-GAAP measure) Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represents only the net change between periods of the fair market values of open commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period.  Management believes that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” because the GAAP measure also includes settlements on commodity derivatives during the period; the non-GAAP measure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.


News Article | February 23, 2017
Site: globenewswire.com

PLANO, Texas, Feb. 23, 2017 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”) today announced a net loss of $386 million, or $0.99 per diluted share, for the fourth quarter of 2016.  Excluding special items, the Company reported an adjusted net loss(1) (a non-GAAP measure) for the quarter of $7 million, or $0.02(1)(2) per diluted share.  Adjusted net loss(1) for the fourth quarter of 2016 differs from the quarter’s GAAP net loss primarily due to the exclusion of a $591 million ($379 million after tax) accelerated depreciation charge associated with the Riley Ridge gas processing facility and related assets, with the GAAP and non-GAAP measures reconciled on tables beginning on page 8. Sequential and year-over-year comparisons of selected quarterly financial items are shown in the following table: Denbury recorded a full-year 2016 net loss of $976 million, or $2.61 per diluted share.  Excluding special items, the Company reported adjusted net income(1) for full-year 2016 of $14 million, or $0.04 per diluted share.  Adjusted net income(1) for the full-year 2016 differs from the GAAP net loss for the year primarily due to the exclusion of (1) an $811 million ($508 million after tax) full cost pool ceiling test write-down, (2) a $591 million ($379 million after tax) accelerated depreciation charge associated with the Riley Ridge gas processing facility and related assets, (3) a $212 million ($132 million after tax) loss on noncash fair value adjustments on commodity derivatives(1), and (4) a $115 million ($71 million after tax) gain on debt extinguishment, with the GAAP and non-GAAP measures reconciled on tables beginning on page 8. Year-over-year comparisons of selected annual financial items are shown in the following table: Phil Rykhoek, Denbury’s CEO, commented, “We are pleased with our results this quarter and the progress we have made on several fronts during this past year.  During 2016 we successfully executed on our goals of optimizing our business, reducing costs, preserving cash and liquidity and reducing debt.  Our cash operating costs, including corporate overhead and interest, for full-year 2016 were just under $34 per BOE, a decrease of $2 per BOE, or 7%, when compared to 2015 and a decrease of over $9 per BOE, or 21%, when compared to 2014.  We ended 2016 with debt principal outstanding of approximately $2.8 billion, a decrease of $530 million from year-end 2015, and a decrease of nearly $800 million from year-end 2014.  Although our production declined in 2016, it was at levels that we expected with capital spending of only around $200 million, all of which was funded from operating cash flow. “Looking ahead, we are excited about Denbury’s future and our plans for returning to growth as oil prices improve, all while we continue our focus on improving the balance sheet, maintaining and enhancing the efficiencies achieved over the last couple of years and pursuing opportunities to increase or accelerate growth.” Denbury’s average realized oil price, excluding derivative contracts, was $48.03 per Bbl in the fourth quarter of 2016, compared to $43.45 per Bbl in the third quarter of 2016.  Including derivative settlements, Denbury’s average realized oil price was $41.93 per Bbl in the fourth quarter of 2016, compared to $42.12 per Bbl in the third quarter of 2016.  The Company’s realized oil price in the fourth quarter of 2016 was $1.22 per Bbl below NYMEX prices, compared to $1.57 per Bbl below NYMEX prices in the third quarter of 2016. Payments on settlements of commodity derivative contracts were $33 million in the fourth quarter of 2016, compared to payments of $7 million in the third quarter of 2016 and receipts of $78 million in the fourth quarter of 2015.  On an annual basis, receipts on settlements of commodity derivative contracts totaled $84 million during 2016, resulting in an increase in average net realized prices of $3.59 per BOE. The Company’s total lease operating expenses in the fourth quarter of 2016 were $106 million, a decrease of $22 million, or 17% on an absolute-dollar basis when compared to the fourth quarter of 2015.  On an annual basis, lease operating expenses totaled $415 million for full-year 2016, a decrease of $100 million, or 19%, from the prior year’s level.  These year-over-year reductions were driven by cost decreases in most lease operating expense categories, the most significant of which included (1) a decrease in workover costs and repairs as a result of reduced well failures, (2) lower power costs mainly due to lower electricity usage, (3) lower CO expense resulting from a decrease in CO injection volumes, and (4) lower Company labor costs resulting from workforce reductions.  During the fourth quarter of 2016, the Company’s CO use averaged 545 million cubic feet per day, a decrease of 23% when compared to the fourth quarter of 2015.  Sequentially, lease operating expenses were relatively flat on an absolute-dollar and per-BOE basis between the third and fourth quarters of 2016. Taxes other than income, which include ad valorem, production and franchise taxes, decreased $6 million, or 26%, from the prior-year fourth quarter level.  On an annual basis, taxes other than income totaled $78 million for full-year 2016, a decrease of $32 million, or 29%, from the prior year’s level, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues, and a decrease in ad valorem taxes generally resulting from lower assessed property values. General and administrative expenses were $29 million in the fourth quarter of 2016, an increase of $1 million, or 5% when compared to the prior-year fourth quarter.  On an annual basis, general and administrative expenses decreased $35 million, or 24%, from 2015 to 2016 primarily due to a reduction in headcount, which resulted in lower employee compensation and related costs. Interest expense, net of capitalized interest, decreased to $22 million in the fourth quarter of 2016, compared to $40 million in the fourth quarter of 2015.  As a result of the Company’s debt exchange transactions completed in May 2016, interest expense in the fourth quarter of 2016 excludes approximately $13 million of interest on the Company’s 9% Senior Secured Second Lien Notes due 2021 because this interest was previously recorded as debt for financial reporting purposes and therefore not reflected as interest expense.  Cash interest, including the portion of interest recorded as debt, decreased approximately $4 million from the prior-year quarter.  See page 14 of this press release for supporting schedules providing more detailed information about the Company’s interest expense. Depletion, depreciation, and amortization (“DD&A”) increased to $647 million during the fourth quarter of 2016, compared to $112 million in the fourth quarter of 2015.  Excluding an accelerated depreciation charge of $591 million for the Riley Ridge gas processing facility and related assets, which is discussed in further detail below, Denbury’s DD&A rate was $10.05 per BOE in the fourth quarter of 2016, compared to $16.96 per BOE in the fourth quarter of 2015.  The decrease from the prior-year fourth quarter was primarily driven by a reduction in depletable costs resulting from the full cost pool ceiling test write-downs recognized during 2015 and the first nine months of 2016.  For full-year 2016, excluding the accelerated depreciation charge, Denbury’s DD&A rate was $10.89 per BOE, compared to $19.99 per BOE in 2015, with the decrease also driven by the full cost pool ceiling test write-downs noted above. The Company placed the Riley Ridge gas processing facility into service during the fourth quarter of 2013, and was successful in running the facility for part of 2014 before additional issues arose related to optimal operation of the facility and sulfur build-up in the gas supply wells.  In mid-2014, the gas processing facility was shut-in and to date remains shut-in.  During this period, the Company has searched for and evaluated a number of potential options in an effort to remedy the existing issues, and its evaluation is still ongoing.  Current projected costs to remedy these issues and successfully operate the gas processing facility are not commercially reasonable investments based on a variety of factors, including (1) the substantial capital expenditures required to implement any corrective option, (2) current projected commodity prices, and (3) projections of the Company’s EOR activities and their timing, resulting CO requirements and other assumptions. Due to the extended shut-in status of the Riley Ridge gas processing facility and management’s recently updated analysis of cost estimates and engineering options to remedy the existing issues, the Company reassessed the estimated useful life of the gas processing facility and related assets during the fourth quarter of 2016 and recorded an accelerated depreciation charge of $591 million.  The Company plans to continue engineering work and analysis to determine if there are alternative options to remediate the sulfur build-up in the gas supply wells and to assess its ability to reduce the costs thereof; however, the timing of completion and results of such analysis are currently uncertain. Furthermore, while Riley Ridge is a potential source of CO for flooding fields in the Rocky Mountain region, the Company has formed alternative plans to develop its future CO EOR floods, which CO volumes management currently anticipates could be supplied through existing CO sources. Denbury’s effective tax rates for the fourth quarter and full-year 2016 were 35% and 36%, respectively, slightly below the Company’s estimated 38% statutory rate. Denbury’s continuing production averaged 60,685 BOE/d during the fourth quarter of 2016, in line with management’s expectations, and was 96% oil, with CO tertiary properties accounting for 62% of overall production.  On a sequential-quarter basis, continuing production in the fourth quarter of 2016 was essentially flat with continuing production in the third quarter of 2016, with production from the Company’s CO tertiary properties increasing slightly. Excluding sold properties, Denbury’s continuing production for full-year 2016 averaged 62,998 BOE/d, down 11% from the prior-year’s level.  Approximately one-third of the production decline was attributable to production shut-in due to economics and weather-related shut-in production at Thompson and Conroe fields, with the remainder largely due to natural production declines.  Further production information is provided on page 12 of this press release. Denbury management will host a conference call to review and discuss fourth quarter and full-year 2016 financial and operating results, together with its financial and operating outlook for 2017, today, Thursday, February 23, at 10:00 A.M. (Central).  Additionally, Denbury has published presentation materials on its website which will be referenced during the conference call.  Individuals who would like to participate should dial 800.230.1074 or 612.332.0226 ten minutes before the scheduled start time.  To access a live audio webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company’s website at www.denbury.com.  The webcast will be archived on the website, and a telephonic replay will be accessible for at least one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 361971. Denbury’s 2017 Annual Meeting of Stockholders will be held on Wednesday, May 24, 2017, at 8:00 A.M. (Central), at Denbury’s corporate offices located at 5320 Legacy Drive, Plano, Texas.  The record date for determination of shareholders entitled to vote at the annual meeting is the close of business on Monday, March 27, 2017. Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO enhanced oil recovery operations.  For more information about Denbury, please visit www.denbury.com. This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K.  These risks and uncertainties are incorporated by this reference as though fully set forth herein.  These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met.  Actual results may vary materially.  In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date.  Denbury assumes no obligation to update its forward-looking statements. FINANCIAL AND STATISTICAL DATA TABLES AND RECONCILIATION SCHEDULES Following are unaudited financial highlights for the comparative three and twelve month periods ended December 31, 2016 and 2015 and the three month period ended September 30, 2016.  All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1. The following information is based on GAAP reported earnings, with additional required disclosures included in the Company’s Form 10-K: Adjusted net income (loss) is a non-GAAP measure provided as a supplement to present an alternative net loss measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations.  Management believes that adjusted net income (loss) may be helpful to investors by eliminating the impact of noncash and/or special or unusual items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company’s ongoing operational results and trends.  Adjusted net income (loss) should not be considered in isolation, as a substitute for, or more meaningful than, net loss or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance. (1) The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period. (2) Reduction in a contingent consideration liability related to a prior acquisition. (3) Insurance and other reimbursements, comprised of a reimbursement for a retroactive utility rate adjustment ($9.6 million) and an insurance reimbursement for previous well control costs ($4.1 million). (4) Full cost pool ceiling test write-downs related to the Company’s oil and natural gas properties during the periods presented, and impairment of third-party accounts receivable and write-off of building leasehold improvements during the three months and year ended December 31, 2015. (5) Charge to fully impair the carrying value of the Company’s goodwill. (6) Accelerated depreciation charge associated with the Riley Ridge gas processing facility and related assets. (7) Gain on extinguishment related to open market debt purchases during the three months ended September 30, 2016 and year ended December 31, 2016, and the debt exchange during the year ended December 31, 2016. (8) Settlements related to previously outstanding litigation, the most significant of which pertaining to a $28 million payment to Evolution in connection with the settlement resolving all outstanding disputes and claims. (9) Write-off of debt issuance costs associated with the Company’s senior secured bank credit facility, related to reductions in the Company’s lender commitments resulting from (1) the February 2016 amendment and (2) the May 2016 redetermination. (10) Severance-related payments associated with the Company’s February-2016 workforce reduction. (11) Transaction costs related to the Company’s debt exchange and a loss on sublease. (12) The estimated income tax impacts on adjustments to net loss are generally computed based upon a statutory rate of 38%, applicable to all periods presented, with the exception of the impairments of long-lived and other assets, which are computed individually based upon the Company’s effective tax rate.  In addition, recorded valuation allowances have been adjusted, including $2.9 million and $33.6 million during the years ended December 31, 2016 and 2015, respectively. Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) Adjusted cash flow from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows.  Adjusted cash flow from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables.  Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. (1) For the year ended December 31, 2016, includes a $28 million payment to Evolution in connection with the Company’s settlement agreement to resolve all outstanding disputes and claims and severance-related payments associated with the 2016 workforce reduction of approximately $9 million.  Excluding these payments, adjusted cash flows from operations would have totaled $301 million during the year ended December 31, 2016. Reconciliation of commodity derivatives income (expense) (GAAP measure) to noncash fair value adjustments on commodity derivatives (non-GAAP measure) Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represents only the net change between periods of the fair market values of open commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period.  Management believes that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” because the GAAP measure also includes settlements on commodity derivatives during the period; the non-GAAP measure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. (1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields. (2) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016. (1) Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company’s new 2021 Senior Secured Notes, most of which is accounted for as debt and therefore not reflected as interest for financial reporting purposes. (1) Excludes $229 million of future interest payable on the notes as of December 31, 2016, accounted for as debt for financial reporting purposes.


News Article | October 3, 2016
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Chris Kendall has been elevated to president of Denbury Resources Inc., Plano, Tex., as part of the firm’s ongoing succession planning process.

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