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VAALCO Energy, Inc. Announces Second Quarter 2017 Results

8 August 2017 - 8:55pm

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- VAALCO Energy, Inc. (NYSE:EGY) today reported operational and financial results for the second quarter 2017.

Second Quarter 2017 and recent key items:

  • Reported income from continuing operations of $2.5 million or $0.04 earnings per share for the second quarter of 2017, compared with a loss from continuing operations of $0.5 million or a loss of $0.01 per share in the same period in 2016
  • Generated operating income of $5.6 million in the second quarter of 2017, up 21% compared with $4.6 million in the same period in 2016
  • Grew Adjusted EBITDAX to $8.6 million, up 11% from $7.7 million in the second quarter of 2016
  • Produced an average of 4,363 barrels of oil per day (BOPD) in the second quarter of 2017, at the high end of the guidance range of 4,100 to 4,400 BOPD
  • Completed the planned 2017 maintenance turnaround with no environmental or safety issues in July 2017

For the second quarter of 2017, VAALCO reported income from continuing operations of $2.5 million, or $0.04 per diluted share. In the same period in 2016, the Company reported a loss from continuing operations of $0.5 million, or a loss of $0.01 per diluted share, and in the first quarter of 2017 reported income from continuing operations of $4.4 million, or $0.07 earnings per diluted share.  The average realized price for crude oil in the second quarter of 2017 was $46.83 per barrel, up 15% from $40.79 per barrel in the second quarter of 2016.  In the first quarter of 2017, the average realized price for crude oil was $51.99 per barrel. Adjusted EBITDAX totaled $8.6 million in the second quarter of 2017 compared with $7.7 million in the same period of 2016, and $10.4 million in the first quarter of 2017.

Adjusted EBITDAX is a Non-GAAP financial measure and is described and reconciled to net income (loss) in the attached table under “Non-GAAP Financial Measures.”

Cary Bounds, VAALCO’s Chief Executive Officer commented: “We remain focused on delivering strong operational and financial results, and I am pleased with our second quarter earnings. We reported earnings per share of $0.04, generated strong operating results and production rates came in at the high end of our guidance range. Our focus in 2017 is to maximize margins through operational excellence and execute on our corporate strategy. As we look to the future, we remain confident in the development opportunities on our offshore Gabon asset, and we are seeking similar growth opportunities in West Africa, where we can leverage our strong operational and technical expertise.”

Gabon and Equatorial Guinea

In the second quarter of 2017, production decreased to 4,363 BOPD compared with 4,622 BOPD in the first quarter of 2017 primarily due to natural decline. 

On July 18, the electrical submersible pump (ESP) in the South Tchibala 2-H well failed, resulting in the well being temporarily shut-in.  The well was producing approximately 1,300 barrels of oil per day gross, or 350 barrels of oil net to the Company, prior to being shut-in.  VAALCO is working to mobilize a hydraulic workover unit to move onto the Avouma platform and replace the ESP system in the well, which is expected to be back on production by the fourth quarter 2017. The Company successfully utilized a hydraulic workover unit to replace the ESP in the well late last year at a significantly lower cost rather than mobilizing a jackup rig.  As a result of recent diagnostic work, the Company believes it has determined the cause of the 2016 ESP failures in this well, and a newly designed pair of ESPs will be installed in the South Tchibala 2-H well during the upcoming workover operation. VAALCO is currently evaluating performing one to two additional workovers in conjunction with the South Tchibala 2-H workover to replace the ESPs.

During July 2017, VAALCO completed its planned 2017 maintenance turnaround for the Etame Marin FPSO and four platforms.  The entire work scope was successfully completed with no environmental or safety issues.  The field was shut-in for nine days during the turnaround and is now back on production. The results of the maintenance and inspection work confirmed the Company’s asset integrity programs continue to be effective.  The next turnaround will be in 2018.

The Company continues to examine alternative, lower cost development options for discoveries in the Mutamba Iroru permit onshore Gabon, and in Block P offshore Equatorial Guinea. These discoveries present unique development opportunities that will be re-evaluated as prices continue to recover.

Discontinued Operations – Angola

The small loss of $0.2 million from discontinued operations for this quarter related to ongoing administrative costs.  In the second quarter of 2016, there was a minimal loss of $20 thousand from discontinued operations, or $0.00 loss per diluted share.  Since September 2016, the Company has reflected an accrual of $15.0 million for a potential payment which represents what VAALCO believes to be the maximum potential amount attributable to VAALCO Angola’s interest under the Block 5 PSA. The Company is in active discussions with representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid will be substantially less than the accrued amount.

Sale of U.S. Properties

On October 17, 2016, the Company signed a letter of intent to sell its entire acreage interests in the East Poplar Unit in Montana for $250,000 and the assumption of asset retirement obligations.  The transaction closed on April 3, 2017.

2017 Second Quarter Financial Results

Total oil and natural gas sales for the second quarter of 2017 were $20.4 million, compared to $18.8 million for the same period in 2016, and $21.3 million in the first quarter of 2017. During the second quarter of 2017, VAALCO sold approximately 414,000 net barrels of oil at an average price of $46.83 per barrel, compared to 436,000 net barrels at an average price of $40.79 per barrel in the second quarter of 2016. Second quarter 2017 revenue was positively impacted by the increase in realized pricing which was offset in part by a decrease in sales volumes compared to the same period in 2016.

Costs and Expenses

Total production expense, excluding workovers, was $9.7 million, or $23.41 per barrel of oil equivalent (BOE) of sales, in the second quarter of 2017, compared to $8.0 million, or $18.16 per BOE of sales, in the second quarter of 2016, and $8.1 million, or $20.44 per BOE of sales in the first quarter of 2017. The second quarter of 2017 costs, excluding workovers, were higher than the second quarter of 2016 primarily due to VAALCO’s increased ownership interest as a result of the November 2016 Sojitz acquisition, costs associated with certain regulatory requirements and FPSO cost escalation. 

Depreciation, depletion and amortization (DD&A) expense was $2.0 million, or $4.76 per BOE of sales in the three months ended June 30, 2017 compared to $1.9 million, or $4.39 per BOE in the comparable period in 2016, and $1.9 million, or $4.74 per BOE in the first quarter of 2017. 

General and administrative (G&A) expense for the three months ended June 30, 2017 was $3.0 million, or $7.36 per BOE, as compared to $4.0 million, or $9.06 per BOE in the three months ended June 2016, and $3.1 million, or $7.94 per BOE in the first quarter of 2017. General and administrative expense includes $0.6 million, $1.0 million, and $0.2 million of non-cash compensation expense for the quarters ended June 30, 2017, June 30, 2016, and March 31, 2017.

Income tax expense for the second quarter of 2017 was $3.1 million compared to $3.0 million for the same period in 2016, and $3.2 million in the first quarter of 2017.  The increase in tax compared to the same period a year ago is primarily attributable to higher revenues from the Company’s operations in Gabon.

Hedging

In order to limit VAALCO’s commodity price risk, in 2016 the Company purchased crude oil puts for part of its 2017 volume. As of June 30, 2017, VAALCO had unexpired crude oil put contracts covering 360,000 barrels of anticipated sales volumes for the period from July 2017 through December 31, 2017 at a weighted average price of $50.00. The Company recorded a non-cash mark-to-market gain of $0.1 million related to the puts during the second quarter of 2017 which was included in “Other, net” in the Condensed Consolidated Statements of Operations. The Company has not entered into additional derivative contracts since June 30, 2017.

Capital Investments/Balance Sheet

During the three months ended June 30, 2017, VAALCO invested approximately $0.3 million in capital expenditures on a cash basis, primarily for equipment and enhancements. The Company has no material commitments for capital expenditures for the balance of 2017.

At the end of the second quarter, VAALCO had an unrestricted cash balance of $20.6 million.  This does not include an additional $0.8 million in restricted cash (related primarily to deposits in Gabon) classified as current assets or the additional $0.9 million of restricted cash classified as long term.

At June 30, 2017, debt, net of deferred financing costs, totaled $13.0 million, of which $8.3 million was classified as current, reflecting the repayment terms of the loan agreement with the IFC.

Conference Call

As previously announced, the Company will hold a conference call to discuss its second quarter financial and operating results August 9th, 2017, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time). Interested parties may participate by dialing (844) 841-1668.  International parties may dial (661) 378-9859.  The confirmation code is 61829267.  This call will also be webcast on VAALCO’s website at www.vaalco.com

An audio replay will be available beginning approximately two hours after the end of the call and be available through August 14, 2017 by dialing (855) 859-2056.  International parties may dial (404) 537-3406. The confirmation code is 61829267.

Forward Looking Statements

This document includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, included in this document that address activities, events, plans, expectations, objectives or developments that VAALCO expects, believes or anticipates will or may occur in the future are forward-looking statements.  These statements may include amounts due in connection with the Company’s withdrawal from Angola, expected sources of future capital funding and future liquidity, future operating losses, future changes in oil and natural gas prices, future strategic alternatives, capital expenditures, future drilling plans, prospect evaluations, negotiations with governments and third parties including with the government of the Republic of Gabon in connection with a revised production sharing contract, expectations regarding processing facilities, reserve growth, and other issues related to our exit from Angola.  These statements are based on assumptions made by VAALCO based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.  Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond VAALCO's control.  These risks include, but are not limited to, oil and gas price volatility, inflation, general economic conditions, the Company's success in discovering, developing and producing reserves, decisions by our current lender or future lenders, the risks associated with liquidity, the risk that our negotiations with the governments of the Republic of Gabon and the Republic of Angola will be unsuccessful, lack of availability of goods, services and capital, environmental risks, drilling risks, foreign regulatory and operational risks, and regulatory changes.  These and other risks are further described in VAALCO's annual report on Form 10-K for the year ended December 31, 2016 and quarterly report on Form 10-Q for the quarter ended June 30, 2017, which will be filed shortly, and other reports filed with the SEC which can be reviewed at http://www.sec.gov, or which can be received by contacting VAALCO at 9800 Richmond Avenue, Suite 700, Houston, Texas 77042, (713) 623-0801.  Investors are cautioned that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.  VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

About VAALCO

VAALCO Energy, Inc. is a Houston, Texas based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil. VAALCO’s strategy is to increase reserves and production through the development and exploitation of international oil and natural gas properties. The Company's properties and exploration acreage are located primarily in Gabon and Equatorial Guinea in West Africa.

Investor Contact

Phil Patman    713-623-0801

VAALCO ENERGY, INC AND SUBSIDIARIESCondensed Consolidated Balance Sheets (Unaudited)(in thousands, except share and per share amounts)   June 30, December 31,  2017  2016 ASSETS      Current assets:      Cash and cash equivalents $20,640  $20,474 Restricted cash  802   741 Receivables:      Trade  8,062   6,751 Accounts with partners, net of allowance  978   3,297 Other, net of allowance  1   120 Crude oil inventory  952   913 Prepayments and other  4,392   4,040 Current assets - discontinued operations  2,578   2,139 Total current assets  38,405   38,475 Property and equipment - successful efforts method:      Wells, platforms and other production facilities  389,192   389,231 Undeveloped acreage  10,000   10,000 Equipment and other  10,283   9,779    409,475   409,010 Accumulated depreciation, depletion and amortization  (384,209)  (380,991)Net property and equipment  25,266   28,019 Other noncurrent assets:      Restricted cash  918   918 Value added tax and other receivable, net of allowance  6,044   5,110 Abandonment funding  8,510   8,510 Total assets $79,143  $81,032 LIABILITIES AND SHAREHOLDERS' EQUITY      Current liabilities:      Accounts payable $14,968  $19,096 Accrued liabilities and other  9,568   10,506 Current portion of long-term debt  8,333   7,500 Accounts with partners  291   - Current liabilities - discontinued operations  15,186   18,452 Total current liabilities  48,346   55,554 Asset retirement obligations  18,947   18,612 Other long term liabilities  283   284 Long-term debt, excluding current portion  4,642   6,940 Total liabilities  72,218   81,390 Commitments and contingencies      Shareholders’ equity (deficit):      Preferred stock, none issued, 500,000 shares authorized, $25 par value  -   - Common stock, 66,348,910 and  66,109,565 shares issued,
$0.10 par value, 100,000,000 shares authorized  6,635   6,611 Additional paid-in capital  70,985   70,268 Less treasury stock, 7,555,095 shares at cost  (37,933)  (37,933)Retained deficit  (32,762)  (39,304)Total shareholders' equity (deficit)  6,925   (358)Total liabilities and shareholders' equity (deficit) $79,143  $81,032 


VAALCO ENERGY, INC AND SUBSIDIARIESConsolidated Statements of Operations(Unaudited)(in thousands, except per share amounts)   Three Months Ended  June 30, 2017 June 30, 2016 March 31, 2017Revenues:         Oil and gas sales $20,425  $18,847  $21,266 Operating costs and expenses:         Production expense  9,866   7,341   7,946 Exploration expense  -   2   - Depreciation, depletion and amortization  1,970   1,942   1,869 General and administrative expense  3,049   4,004   3,127 Other operating expense  -   754   - General and administrative related to shareholder matters  -   18   15 Bad debt expense and other  183   171   98 Total operating costs and expenses  15,068   14,232   13,055 Other operating income (loss), net  230   -   (63)Operating income  5,587   4,615   8,148 Other income (expense):         Interest expense, net  (378)  (1,470)  (403)Other, net  338   (642)  (116)Total other income (expense)  (40)  (2,112)  (519)Income from continuing operations before income taxes  5,547   2,503   7,629 Income tax expense  3,096   3,001   3,194 Income (loss) from continuing operations  2,451   (498)  4,435 Loss from discontinued operations, net of tax  (168)  (20)  (176)Net income (loss) $2,283  $(518) $4,259           Basic net income (loss) per share         Income (loss) from continuing operations $0.04  $(0.01) $0.07 Income (loss) from discontinued operations  (0.00)  (0.00)  (0.00)Net income (loss) $0.04  $(0.01) $0.07 Basic weighted average shares outstanding  58,658   58,464   58,567 Diluted net income (loss) per share         Income (loss) from continuing operations $0.04  $(0.01) $0.07 Income (loss) from discontinued operations  (0.00)  (0.00)  (0.00)Net income (loss) $0.04  $(0.01) $0.07 Basic weighted average shares outstanding  58,658   58,464   58,580 


VAALCO ENERGY, INC AND SUBSIDIARIESConsolidated Statements of Cash Flows(Unaudited)(in thousands)   Six Months Ended  June 30, 2017 June 30, 2016CASH FLOWS FROM OPERATING ACTIVITIES:      Net income (loss) $6,542  $(8,142)Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:      Loss (income) from discontinued operations  344   (7,786)Depreciation, depletion and amortization  3,839   4,180 Other amortization  201   1,076 Unrealized foreign exchange gain  (580)  (102)Stock-based compensation  783   1,434 Commodity derivatives loss  50   578 Bad debt provision  281   514 Other operating income, net  (167)  (18)Change in operating assets and liabilities:      Trade receivables  (1,314)  (2,010)Accounts with partners  2,610   9,043 Other receivables  58   (52)Crude oil inventory  (39)  (65)Value added tax and other receivable  (1,130)  (1,236)Prepayments and other  395   (334)Accounts payable  (4,274)  (11,591)Accrued liabilities and other  (977)  144 Net cash provided by (used in) continuing operating activities  6,622   (14,367)Net cash provided by (used in) discontinued operating activities  (4,049)  15,996 Net cash provided by operating activities  2,573   1,629 CASH FLOWS FROM INVESTING ACTIVITIES:    (Increase) decrease in restricted cash  (61)  265 Acquisitions  64   - Property and equipment expenditures  (1,032)  (10,448)Proceeds from the sale of oil and gas properties  250   - Premiums paid  -   (824)Net cash used in continuing investing activities  (779)  (11,007)Net cash used in discontinued investing activities  -   (2,221)Net cash used in investing activities  (779)  (13,228)CASH FLOWS FROM FINANCING ACTIVITIES:    Proceeds from the issuances of common stock  38   - Borrowings  4,167   - Debt repayment  (5,833)  - Debt issuance costs  -   (77)Net cash used in continuing financing activities  (1,628)  (77)Net cash provided by discontinued financing activities  -   - Net cash used in financing activities  (1,628)  (77)NET CHANGE IN CASH AND CASH EQUIVALENTS  166   (11,676)CASH AND CASH EQUIVALENTS:
      BEGINNING OF PERIOD  20,474   25,357 END OF PERIOD $20,640  $13,681 


VAALCO ENERGY, INC AND SUBSIDIARIESSelected Financial and Operating Statistics(Unaudited)    Three Months Ended  June 30, 2017 June 30, 2016 March 31, 2017NET SALES DATA:         Oil (MBbls)  414  436  394Natural Gas (MMcf)  -  35  -Oil equivalents (MBOE)  414  442  394Average daily sales volumes (BOE/day)  4,549  4,857  4,378NET PRODUCTION DATA         Oil (MBbls)  397  430  416Natural Gas (MMcf)  -  35  -Oil equivalents (MBOE)  397  436  416Average daily production volumes (BOE/day)  4,363  4,796  4,622AVERAGE SALES PRICES:         Oil ($/Bbl) $46.83 $40.79 $51.99Natural Gas ($/Mcf)  0.00  1.64  0.00Weighted average price ($/BOE)  46.83  40.14  51.99COSTS AND EXPENSES (PER BOE OF SALES):         Production expense $23.83 $16.61 $20.17Production expense, excluding workovers*  23.41  18.16  20.44Depreciation, depletion and amortization  4.76  4.39  4.74General and administrative expense**  7.36  9.06  7.94Property and equipment expenditures, cash basis $264 $8,965 $768 *Workover costs excluded from the three months ended June 30, 2017, June 30, 2016 and March 31, 2017 are $0.2 million, ($0.7) million and ($0.1)  million.  **General and administrative expenses include $1.52, $2.29 and $0.39 per BOE of non-cash stock-based compensation expense in the three months ended June 30, 2017, June 30, 2016 and March 31, 2017. 

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDAX is a supplemental non-GAAP financial measure used by VAALCO’s management and by external users of the Company’s financial statements, such as industry analysts, lenders, rating agencies, investors and others who follow the industry as an indicator of the Company’s ability to internally fund exploration and development activities and to service or incur additional debt. Adjusted EBITDAX is a non-GAAP financial measure and as used herein represents net income before discontinued operations, interest income (expense) net, income tax expense, depletion, depreciation and amortization, impairment of proved properties, exploration expense, non-cash and other items including stock compensation expense and commodity derivative loss.

Adjusted EBITDAX has significant limitations, including that it does not reflect the Company’s cash requirements for capital expenditures, contractual commitments, working capital or debt service. Adjusted EBITDAX should not be considered as a substitute for net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. Therefore, the Company’s Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies.

The table below reconciles the most directly comparable GAAP financial measures to Adjusted EBITDAX.

VAALCO ENERGY, INC AND SUBSIDIARIESReconciliations of Non-GAAP Measures(Unaudited)(in thousands) Reconciliation of Net income (loss) to Adjusted         EBITDAX Three Months Ended  June 30, 2017 June 30, 2016 March 31, 2017Net income (loss) $2,283  $(518)  4,259Add back:         Impact of discontinued operations  168   20   176Interest (income) expense, net  378   1,470   403Income tax expense  3,096   3,001   3,194Depreciation, depletion and amortization  1,970   1,942   1,869Exploration expense  -   2   -Non-cash or unusual items:         Stock-based compensation  629   1,014   154Shareholder matters  -   18   15Commodity derivative loss (gain)  (130)  578   180Equipment write-offs  -   -   63Bad debt expense  183   171   98          Adjusted EBITDAX $8,577  $7,698  $10,411

 

Categories: State

Penn Virginia Corporation Reports Second Quarter 2017 Results and Provides Operational Update

8 August 2017 - 5:33pm

---Recently Announced Acquisition of Eagle Ford Properties
Expected to Provide Significant Long-Term Upside---

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (“Penn Virginia” or the “Company”) (NASDAQ:PVAC) today announced its financial and operational results for the second quarter 2017.

Recent Key Operational and Second Quarter Highlights 

• Production reached 10,159 BOEPD in the second quarter of 2017, of which 74% was crude oil, an increase of approximately 8% over the first quarter of 2017;  

• The Lager 3H well continues to exceed the Company’s type curve with a current flow rate of approximately 1,000 barrels of oil equivalent per day (“BOEPD”), of which 70% is crude oil, with over 95 days online and active choke management;

• The recently completed Zebra 6H and 7H wells have exhibited strong initial production rates and are outperforming the Company’s type curve;

• Entered into a definitive agreement to acquire 19,600 net acres contiguous to the Company’s core operations in the Eagle Ford, offering an expanded well inventory including the opportunity for extended reach laterals (“XRLs”) with PV10 breakeven pricing of less than $30 per barrel;

• Comparing the second and first quarters of 2017:

  • Total product revenues increased by 5% to $36.3 million, of which 89% was generated by crude oil sales;
  • Total direct operating expenses increased 1% to $12.9 million, but decreased 6% on a per barrel of oil equivalent (“BOE”) basis to $13.96 per BOE;
  • Operating income was $11.4 million, down 1%;
  • Net income was $21.3 million, as compared to $28.1 million, with the decrease primarily associated with lower derivatives income; and
  • Adjusted EBITDAX(1) was $23.1 million, an increase of almost 15%;

• The Company’s borrowing base under its credit facility was increased over 55%, from $128 million to $200 million in the second quarter of 2017.  At the end of the quarter, the Company had liquidity of approximately $172 million.

(1)  Adjusted EBITDAX is a non-GAAP measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based measures appear at the end of this release. 

Management Comment 

“During the second quarter, we continued to build on the positive momentum we achieved in the first quarter,” said John A. Brooks, Interim Principal Executive Officer and Chief Operating Officer. “Our recently announced acquisition of contiguous assets in the Eagle Ford will allow us to further accelerate our production growth.” 

Mr. Brooks continued, “The recent success we have seen with our drilling program, especially with the strong performance of the Lager 3H in Area 2, gives us confidence in our ability to further capitalize on opportunities within our legacy acreage and the properties we are acquiring.  This strategic transaction is a bolt on to our existing acreage footprint so our operating team knows the area very well. Most important, the acquisition provides Penn Virginia the opportunity for drilling a significant number of XRLs that generate superior economics. 

“On the acquired acreage, we have identified 91 gross locations in the lower Eagle Ford formation, with 43 of these locations identified for XRLs, including 26 locations that have the potential to be 10,000 feet or greater. Beyond the superior economics associated with drilling longer laterals complemented by higher working interests, we also see further upside in testing the upper Eagle Ford/Austin Chalk, centralizing operations and gaining scale.” 

Mr. Brooks concluded, “While we see significant opportunity across our soon to be expanded core acreage position, we remain focused on ensuring we maintain a healthy balance sheet and ample liquidity. We will do this by continuing to focus on high return projects and capital discipline, including primarily drilling within cash flow with a target leverage ratio of net debt to EBITDAX of 1.5x or below.  As we implement our capital plan on the combined assets, we believe we will achieve this goal by the end of 2018.”

Devon Eagle Ford Acquisition

As previously announced, Penn Virginia entered into a definitive agreement to acquire Eagle Ford assets located primarily in Lavaca County, Texas for $205 million in cash from Devon Energy Corporation (“Devon”). The Company anticipates the acquisition will close on September 30, 2017, with an effective date of March 1, 2017. Penn Virginia expects the purchase price will be adjusted downwards by approximately $15 million to reflect estimated net cash flows from the effective date to closing, resulting in a net purchase price of approximately $190 million. The acquisition is expected to be funded with $150 million of new committed debt financing and borrowings under the Company’s credit facility.

The acquisition is accretive to Penn Virginia under all measures, including earnings, cash flow and net asset value per share.  Further, the Company estimates it is purchasing the acreage at an attractive price of approximately $2,900 per net acre, after reducing for production value, the aforementioned purchase price adjustment, over-riding royalty interest in non-acquired acreage, and the value of the acquired midstream assets.

Second Quarter 2017 Operating Results

Total production in the second quarter of 2017 increased approximately 8% to 10,159 BOEPD, or 925 thousand barrels of oil equivalent (“MBOE”). Approximately 74%, or 685 MBOE, was from crude oil, 14% from natural gas liquids (“NGLs”), and 12% from natural gas.

The table below shows production results and related operating information for the Company's Area 1 (two-string) and Area 2 (three-string) lower Eagle Ford wells: 

                          24 Hour IP Average Gross Daily Production Rates(1) 30-Day Average Gross Daily Production Rates(1) Gross / Net WellsLateral Length Frac Stages Proppant  Oil RateEquivalent RateOil Percentage Oil RateEquivalent RateOil Percentage  Feet lb per foot BOPD/1000ftBOEPD/1000ft  BOPD/1000ftBOEPD/1000ft 2-String Area 1 Type Curve  6,000302,000 22525190% 16918990%Sable Pad (4H - 5H)(2)2 / 1.26,401322,404 39942394% 17418594%Axis Pad (1H - 3H)3 / 1.97,056352,484 27829993% 16717993%Kudu Pad (6H - 9H)4 / 1.75,429272,415 26128392% 15216294%Lager 3H(3)(4)1 / .47,920402,452 24531777% 17524073%Zebra Pad (6H-7H)(3)2 / .94,726282,876 28732289% 20822394%                                                                                           (1)  Wellhead rate only.  The natural gas liquids yield is 135 to 155 barrels per million cubic feet of natural gas.(2) Excludes the Sable 6H which had operational issues and only had 9 open stages at the time of measuring the 24-hour and 30-day IP rates.  The remaining stages were subsequently opened to flow.(3) Choke management in effect.(4) Area 2 well with higher expected gas to oil ratio than Area 1 type curve.


Penn Virginia drilled seven gross (2.3 net) and turned to sales seven gross (3.0 net) Eagle Ford wells during the quarter. 

During the second quarter of 2017, Penn Virginia turned to sales four wells from the Kudu pad, located in the northern portion of Area 1. The Company has an average working interest of 43.7% in each of the Kudu wells. On average, the wells had a 30-day IP of 806 BOEPD (94% oil), or 162 BOEPD per 1,000 feet of lateral.

The Zebra 6H and 7H wells on the two-well Zebra pad were also completed and turned to sales in the second quarter. These two wells targeted the lower Eagle Ford Shale in Area 1. The wells were drilled approximately 400 feet apart. The Company has a 42.5% working interest and is the operator of both wells. On average, the wells had a 30-day IP of 1,058 BOEPD (94% oil), or 223 BOEPD per 1,000 feet of lateral.

The Company’s first well that utilized its slickwater completion design in Area 2 of the lower Eagle Ford Shale was completed in April 2017.  The Lager 3H well has been on line for over 95 days with cumulative production of approximately 136 MBOE (70% oil) and is currently producing approximately 1,000 BOEPD.  As a result of the acquisition, Penn Virginia will increase its working interest in the Lager 3H well from approximately 41% to 96%.

Penn Virginia is actively managing the choke size on the Zebra pad and Lager 3H in order to maintain pressure, which should ultimately increase recoverable reserves. These three wells are currently outperforming the Company's type curve.  Additionally, given the success of the Lager 3H well, the Company is accelerating drilling in Area 2. The Schacherl-Effenberger pad, which was originally designed as a one-well pad, will now be a two-well pad. These two wells are scheduled to be drilled in fourth quarter of 2017.

The Company has begun completion operations on its eight-well "super pad", consisting of the adjoining four-well Chicken Hawk pad and the four-well Jake Berger pad. Two of the wells are targeting the upper Eagle Ford Shale/lower Austin Chalk and six wells are targeting the lower Eagle Ford Shale, testing the "stack and stagger" completion technique. The wells are in Area 1 and spaced approximately 400 feet apart and are expected to be turned to sales in late third quarter.

In the second quarter of 2017, the Company leased and/or extended approximately 1,000 net acres, increasing its core acreage position to approximately 57,000 net acres with approximately 530 gross (more than 350 net) drilling locations. Approximately 93 percent of Penn Virginia’s core acreage is held by production.

Second Quarter 2017 Financial Results 

Total product revenues were $36.3 million in the second quarter of 2017 compared to $34.7 million in the first quarter of 2017, primarily due to an 8% increase in production that was partially offset by a decline in commodity prices.  Crude oil sales contributed approximately 89% of total product revenues.

The average realized price for crude oil declined 4% from the previous quarter to $47.25 per barrel in the second quarter of 2017.  Including cash settlements from oil derivatives, the realized price for crude oil was $46.57, which was 1% higher than the first quarter. The realized price of NGLs decreased from $19.34 per barrel in the previous quarter to $15.59 per barrel ($0.37 per gallon) in the second quarter.  The realized price of natural gas was $2.88 per thousand cubic feet (Mcf), a 6% decrease from the previous quarter.  The total realized equivalent price for all production without the impact of derivatives during the second quarter was $39.24 per BOE. 

Total direct operating expenses consisting of cash general & administrative (“G&A”) expense, lease operating expense (“LOE”), gathering, processing & transportation expense (“GPT”), and severance and ad valorem taxes were $12.9 million, or $13.96 per BOE, in the second quarter of 2017 compared to $12.7 million, or $14.89 per BOE, in the first quarter. 

Operating income was $11.4 million in the second quarter of 2017 as compared to operating income of $11.6 million in the previous quarter due to higher depreciation, depletion and amortization expense.

Net income for the second quarter of 2017 was $21.3 million, or $1.42 per diluted share, compared to a net income of $28.0 million, or $1.87 per share, in the first quarter of 2017.  Significantly contributing to the decrease was a lower gain on derivatives of $11.0 million in the second quarter of 2017 compared to a $17.0 million gain in the previous quarter.  

Adjusted EBITDAX(1) was $23.1 million in the second quarter of 2017, a 15% increase from the first quarter of 2017.  Significantly contributing to the second quarter increase was an 8% increase in volumes, most of which was attributable to crude oil.

(1)  Adjusted EBITDAX is a non-GAAP measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based measures appear at the end of this release.

Hedging Update

Penn Virginia has hedged a substantial portion of its proved developed crude oil production through the end of 2019. The Company is currently unhedged with respect to NGL and natural gas production. Upon closing of the pending Devon transaction, Penn Virginia expects to hedge a significant portion of the oil and natural gas production associated with the acquired production.

The table below sets forth the Company’s current oil hedge positions:

 Oil Volumes
Barrels Per Day  Average Swap Price ($/barrel)2017 (remaining)4,408  $48.5920184,476  $49.3720192,916  $49.75

Capital Resources and Liquidity

As of June 30, 2017, Penn Virginia had $37.0 million outstanding on its credit facility and liquidity of $172.3 million, consisting of $163.0 million undrawn capacity on its credit facility, $0.8 million outstanding in issued letters of credit, and $10.1 million of cash. As of August 4, 2017, the Company had outstanding borrowings of $47 million and liquidity of $158 million, including $6 million in cash.

The Company expects to finance the recently announced acquisition with $150 million of new committed debt financing and borrowings under the Company’s credit facility. In addition, Penn Virginia is in discussions with its bank lending group to further amend and increase its reserve-based credit facility beyond the current borrowing base of $200 million.

The Company is committed to maintaining financial discipline and a strong balance sheet with a targeted net debt to EBITDAX of 1.5x or below. Penn Virginia believes it will achieve that level by the end of 2018 through the development of the combined assets.

Guidance

The table below sets forth the Company’s current operational guidance for 2017 and 2018, which has been updated to reflect the closing of the pending acquisition on September 30, 2017.

   2017
 2018
 Production (BOEPD)  % oil   % oil  Third quarter9,200 - 9,600 74%      Fourth quarter (exit rate)14,600 - 15,200 74% 21,000 -23,000 74%  Full year10,600 - 11,200 73% 20,000 - 22,000 74% Realized Price Differentials         Oil (off WTI, per barrel)$2.00 - $2.50        Natural gas (off Henry Hub, per MMBtu)$0.10 - $0.20       Direct operating expenses         Cash G&A expense ($ millions)$12 - $14        Lease operating expense (per BOE)$5.00 - $5.50        GPT expense (per BOE)$2.75 - $3.00        Ad valorem and production taxes (% of production revenues)5.75% - 6.25%       Capital expenditures ($ millions)$140 - $160   $220 - $240           

Average daily production in the 2017 third quarter is expected to be 9,200 to 9,600 BOEPD with approximately 74% of production comprised of crude oil. The Company anticipates a decline in volume in the third quarter compared to the second quarter due to a delay in the completion of the eight-well “super pad” to late in the third quarter.  The Company expects total 2017 production volumes to range between 3.9 and 4.1 MMBOE, or 10,600 to 11,200 BOEPD, with approximately 73% comprised of crude oil. Capital spending for the full year 2017 is anticipated at $140 million to $160 million, with approximately 90% being directed to drilling and completions in the Eagle Ford.  Penn Virginia expects well costs to increase slightly from previous guidance with its Area 1 Gen 3 design wells anticipated to cost between $5.0 million and $5.2 million, and its Gen 4 design wells expected to cost between $5.3 million to $5.7 million for an average 6,000-foot lateral.

Second Quarter 2017 Conference Call 

A conference call and webcast covering second quarter 2017 financial and operational results is scheduled for Wednesday, August 9, 2017 at 11:00 a.m. EDT.  Prepared remarks will be followed by a question and answer period. Investors and analysts may participate via phone by dialing toll free 877-316-5288 (international: 734-385-4977) five to 10 minutes before the scheduled start time, or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start time to download supporting materials and install any necessary audio software.  An on-demand replay of the webcast will also be available at our website beginning shortly after the webcast.

EnerCom Conference

Penn Virginia will participate in EnerCom’s 22nd The Oil & Gas Conference® to be held in Denver, CO on August 14-17, 2017. Penn Virginia’s presentation will begin at 12:05 ET on Wednesday, August 16, 2017.  A link to the webcast and presentation will be available on the Company's website at www.pennvirginia.com.

About Penn Virginia Corporation

Penn Virginia Corporation is an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions of the United States, with a primary focus in the Eagle Ford Shale in south Texas.  For more information, please visit our website at www.pennvirginia.com.

Cautionary Statement Regarding Estimates and Guidance The estimates and guidance presented in this release do not include any acquisitions of additional properties, including the Devon acreage. These estimates and guidance are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and current operating costs. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe the estimates and guidance, and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Projections regarding the Devon acreage that we do not yet own or operate are inherently more speculative than statements regarding our acreage. Actual results may differ materially from estimates and guidance. Please read “Forward Looking Statements.”

Forward-Looking Statements 

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. We use words such as "guidance," "projects," "estimates," “expects," "continues," "intends," “plans,” "believes," forecasts," "future," and variations of such words or similar expressions in this press release to identify forward-looking statements. Because such statements include assumptions, risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: timing, costs and unknown risked related to the pending acquisition, the Company’s ability to realize expected benefits of the pending acquisition and the risk the acquisition in not consummated as expected; potential adverse effects of the completed bankruptcy proceedings on our liquidity, results of operations, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy; our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting; plans, objectives, expectations and intentions contained in this press release that are not historical; our ability to execute our business plan in the current commodity price environment; any decline in and volatility of commodity prices for oil, NGLs, and natural gas; our anticipated production and development results; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; our ability to contract for drilling rigs, frac crews, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and natural gas reserves; drilling and operating risks; concentration of assets; our ability to compete effectively against other oil and gas companies; leasehold terms expiring before production can be established and our ability to replace expired leases; costs or results of any strategic initiatives; environmental obligations, results of new drilling activities, locations and methods, costs and liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key employees; counterparty risk related to the ability of these parties to meet their future obligations; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity breaches; litigation that impacts us, our assets or our midstream service providers; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the SEC. Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. The statements in this release speak only as of the date of this release. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law. 


PENN VIRGINIA CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited (in thousands, except per share data)               Successor Successor Predecessor Successor Predecessor   Three Months Three Months Three Months Six Months Six Months   Ended Ended Ended Ended Ended   June 30, March 31, June 30, June 30, June 30,   2017  2017  2016  2017  2016  Revenues           Crude oil $  32,351  $  30,073  $  32,019  $  62,424  $  57,985  Natural gas liquids (NGLs)    2,043     2,302     2,431     4,345     4,384  Natural gas    1,880     2,343     1,917     4,223     4,319    Total product revenues    36,274     34,718     36,367     70,992     66,688  Gain (loss) on sales of assets, net    (134)    65     910     (69)    757  Other, net     142     203     (125)    345     204    Total revenues    36,282     34,986     37,152     71,268     67,649  Operating expenses           Lease operating    5,370     4,916     5,225     10,286     11,417  Gathering, processing and transportation     2,555     2,551     4,650     5,106     8,468  Production and ad valorem taxes    2,119     1,979     2,163     4,098     2,916  General and administrative     2,873     3,281     12,982     6,154     30,686    Total direct operating expenses    12,917     12,727     25,020     25,644     53,487  Share-based compensation - equity classified awards     848     846     1,966     1,694     1,364  Exploration     -     -     4,320     -     5,647  Depreciation, depletion and amortization    11,076     9,810     11,746     20,886     25,558    Total operating expenses    24,841     23,383     43,052     48,224     86,056  Operating income (loss)    11,441     11,603     (5,900)    23,044     (18,407) Other income (expense)           Interest expense     (1,274)    (538)    (32,221)    (1,812)    (56,655) Derivatives    11,061     17,016     (21,759)    28,077     (17,267) Other    101     -     (6)    101     (1,030) Reorganization items, net    -     -     (7,380)    -     (7,380) Income (loss) before income taxes     21,329     28,081     (67,266)    49,410     (100,739) Income tax benefit (expense)    -     -     -     -     -  Net income (loss)    21,329     28,081     (67,266)    49,410     (100,739) Preferred stock dividends     -     -     (2,820)    -     (5,972) Net income (loss) attributable to common shareholders     $  21,329  $  28,081  $  (70,086) $  49,410  $  (106,711) Net income (loss) per share:           Basic $  1.42  $  1.87  $  (0.79) $  3.30  $  (1.22) Diluted $  1.42  $  1.87  $  (0.79) $  3.27  $  (1.22)             Weighted average shares outstanding, basic     14,992     14,992     89,051     14,992     87,496  Weighted average shares outstanding, diluted    15,050     14,992     89,051     15,097     87,496                            Successor Successor Predecessor Successor Predecessor   Three Months Three Months Three Months Six Months Six Months   Ended Ended Ended Ended Ended   June 30, March 31, June 30, June 30, June 30,   2017  2017  2016  2017  2016  Production           Crude oil (MBbls)    685     608     791     1,293     1,764  NGLs (MBbls)    131     119     187     250     400  Natural gas (MMcf)    653     765     1,070     1,418     2,318  Total crude oil, NGL and natural gas production (MBOE)   925     855     1,156     1,779     2,551              Prices           Crude oil ($ per Bbl) $  47.25  $  49.47  $  40.48  $  48.29  $  32.87  NGLs ($ per Bbl) $  15.59  $  19.34  $  13.01  $  17.38  $  10.95  Natural gas ($ per Mcf) $  2.88  $  3.06  $  1.79  $  2.98  $  1.86              Prices - Adjusted for derivative settlements           Crude oil ($ per Bbl) $  46.57  $  46.19  $  61.20  $  46.39  $  59.49  NGLs ($ per Bbl) $  15.59  $  19.34  $  13.01  $  17.38  $  10.95  Natural gas ($ per Mcf) $  2.88  $  3.06  $  1.79  $  2.98  $  1.86  

 

PENN VIRGINIA CORPORATION
 CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited (in thousands)                   June 30, December 31,         2017  2016      Assets           Current assets   $  58,684  $  38,884      Net property and equipment      272,461     247,473      Other assets      6,007     5,329        Total assets   $  337,152  $  291,686                  Liabilities and shareholders' equity           Current liabilities   $  59,263  $  62,629      Credit facility      37,000     25,000      Other liabilities       4,193     18,509      Total shareholders' equity     236,696   185,548        Total liabilities and shareholders' equity   $337,152    $291,686                                              CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited (in thousands)                                                                                       Successor Successor Predecessor Successor Predecessor   Three Months Three Months Three Months Six Months Six Months   Ended Ended Ended Ended Ended   June 30, March 31, June 30, June 30, June 30,   2017  2017  2016  2017  2016  Cash flows from operating activities           Net income (loss) $  21,329  $  28,081  $  (67,266) $  49,410  $  (100,739) Adjustments to reconcile net income (loss) to net cash provided by operating activities:            Depreciation, depletion and amortization    11,076     9,810     11,746     20,886     25,558  Accretion of firm transportation obligation    -     -     142     -     317  Derivative contracts:                     Net losses (gains)    (11,061)    (17,016)    21,759     (28,077)    17,267  Cash settlements, net    (466)    (1,992)    16,393     (2,458)    46,952  (Gain) loss on sales of assets, net    134     (65)    (910)    69     (757) Non-cash exploration expense    -     -     857     -     1,713  Non-cash interest expense    800     188     20,920     988     22,189  Share-based compensation (equity-classified)    848     846     1,966     1,694     1,364  Other, net    20     18     (9)    38     (13) Changes in operating assets and liabilities    4,195     (10,728)    11,644     (6,533)    31,922  Net cash provided by operating activities     26,875     9,142     17,242     36,017     45,773  Cash flows from investing activities                     Capital expenditures    (25,842)    (17,741)    (570)    (43,583)    (14,575) Proceeds from sales of assets, net    -     -     -     -     126  Other, net    -     -     1,186     -     1,186  Net cash used in (provided by) investing activities    (25,842)    (17,741)    616     (43,583)    (13,263) Cash flows from financing activities                     Proceeds from credit facility borrowings    7,000     7,000     -     14,000     -  Repayment of credit facility borrowings    -     (2,000)    (5,393)    (2,000)    (5,468) Debt issuance costs paid    (1,090)    -     -     (1,090)    -  Proceeds received from rights offering, net    55     -     -     55     -  Other, net    (25)    (30)    -     (55)    -  Net cash provided by (used in) financing activities    5,940     4,970     (5,393)    10,910     (5,468) Net (decrease) increase in cash and cash equivalents    6,973     (3,629)    12,465     3,344     27,042  Cash and cash equivalents - beginning of period    3,132     6,761     26,532     6,761     11,955  Cash and cash equivalents - end of period $  10,105  $  3,132  $  38,997  $  10,105  $  38,997  

 

PENN VIRGINIA CORPORATION CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited (in thousands)               Successor Successor Predecessor Successor Predecessor   Three Months Three Months Three Months Six Months Six Months   Ended Ended Ended Ended Ended   June 30, March 31, June 30, June 30, June 30,   2017  2017  2016  2017  2016  Reconciliation of GAAP "Net income (loss)" to Non-
GAAP "Adjusted EBITDAX"
           Net income (loss) $  21,329  $  28,081  $  (67,266) $  49,410  $  (100,739) Adjustments to reconcile to Adjusted EBITDAX:           Interest expense    1,274     538     32,221     1,812     56,655  Income tax (benefit) expense    -      -      -      -      -   Depreciation, depletion and amortization    11,076     9,810     11,746     20,886     25,558  Exploration    -      -      4,320     -      5,647  Share-based compensation expense (equity-classified)        848     846     1,966     1,694     1,364  Loss (gain) on sale of assets, net    134     (65)    (910)    69     (757) Accretion of firm transportation obligation    -      -      142     -      317  Adjustments for derivatives:           Net losses (gains)    (11,061)    (17,016)    21,759     (28,077)    17,267  Cash settlements, net    (466)    (1,992)    16,393     (2,458)    46,952  Adjustment for special items:           Reorganization items, net    -      -      7,380     -      7,380  Strategic and financial advisory costs    -      -      6,973     -      18,036  Restructuring expenses    -      (20)    351     (20)    1,099  Adjusted EBITDAX $  23,134  $  20,182  $  35,075  $  43,316  $  78,779   Adjusted EBITDAX represents net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization expense, and share-based compensation expense, further adjusted to exclude the effects of gains or losses on sale of assets, accretion of firm transportation obligation, non-cash changes in the fair value of derivatives, strategic and financial advisory costs, restructuring expenses and other non-cash items.  We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating, investment recommendations of companies within the oil and gas exploration and production industry.  We use this information for comparative purposes within our Industry.  Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss).  Adjusted EBITDAX as defined by Penn Virginia may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities.  Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Penn Virginia’s results as reported under GAAP.CONTACT: Contact: Steve Hartman Chief Financial Officer (713) 722-6529 invest@pennvirginia.com
Categories: State

Noble Energy Announces Pricing of Offering of $600 Million of Senior Notes Due 2028 and $500 Million of Senior Notes Due 2047

8 August 2017 - 5:25pm

Houston, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Noble Energy, Inc. (NYSE: NBL) (“Noble Energy” or “the Company”) today announced that it has priced an offering of $600 million of 3.850% senior notes that will mature on January 15, 2028 (“the 2028 notes”), and $500 million of 4.950% senior notes that will mature on August 15, 2047 (“the 2047 notes”), pursuant to an effective shelf registration statement that was previously filed with the Securities and Exchange Commission. The price to the public for the 2028 notes and the 2047 notes are 99.688% and 99.643% of the principal amounts, respectively.

The Company intends to use the net proceeds from the offering, together with cash on hand or available liquidity, to purchase in a cash tender offer or otherwise redeem any and all of its outstanding $1 billion 8.25% senior notes and to pay fees, premiums, expenses and unpaid and accrued interest related to the tender offer or redemption.

The offering is expected to close on August 15, 2017, subject to customary closing conditions. Citigroup Global Markets Inc., J.P. Morgan Securities LLC, MUFG Securities Americas Inc., DNB Markets, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC served as joint book-running managers for the offering. The offering is being made only by means of a prospectus supplement and accompanying prospectus, copies of which may be obtained from Citigroup Global Markets Inc., c/o Broadridge Financial Solutions, 1155 Long Island Avenue, Edgewood, NY 11717, (or telephone toll-free at 800-831-9146 or e-mail at prospectus@citi.com), J.P. Morgan Securities LLC, 383 Madison Avenue, New York, NY 10179, Attention: Investment Grade Syndicate Desk (or telephone collect at 212-834-4533) or MUFG Securities Americas, Inc,1221 Avenue of the Americas, 6th Floor New York, NY 10020 (or telephone at  877-649-6848). An electronic copy of the prospectus supplement will be available on the website of the Securities and Exchange Commission at www.sec.gov.

This announcement is neither an offer to sell nor a solicitation of an offer to buy any of these securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale is unlawful. This announcement shall not constitute a notice of redemption under the indenture governing the Notes.

Noble Energy (NYSE: NBL) is an independent oil and natural gas exploration and production company with a diversified high-quality portfolio of both U.S. unconventional and global offshore conventional assets spanning three continents. Founded more than 80 years ago, the company is committed to safely and responsibly delivering our purpose: Energizing the World, Bettering People's Lives®.

Forward Looking Statements

This news release contains certain “forward-looking statements” within the meaning of federal securities laws. Words such as “anticipates”, “believes”, “expects”, “intends”, “will”, “should”, “may”, and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Energy’s current views about future events and are subject to a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the effects of global, national and regional economic and market conditions, changes in the financial markets and interest rates, the volatility in commodity prices for crude oil and natural gas, the ability to consummate the senior notes offering, tender offer or redemption and other risks inherent in Noble Energy’s businesses that are discussed in Noble Energy’s most recent annual report on Form 10-K and in other Noble Energy reports on file with the Securities and Exchange Commission. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update any forward-looking statements should circumstances or management’s estimates or opinions change.

CONTACT: Investor Contacts: Brad Whitmarsh (281) 943-1670 brad.whitmarsh@nblenergy.com Megan Repine (832) 639-7380 megan.repine@nblenergy.com Megan Dolezal (281) 943-1861 megan.dolezal@nblenergy.com Media Contacts: Reba Reid (713) 412-8441 media@nblenergy.com Deena McMullen (281) 943-1732 media@nblenergy.com

Categories: State

Bonanza Creek Energy Announces Second Quarter 2017 Financial Results and Operational Update

8 August 2017 - 4:00pm
  • Aggressively applying enhanced drilling and completion techniques throughout capital program
  • Completed first pad of DUC wells, early data out-pacing expectations
  • Commenced drilling program at the end of July; first pad expected to complete in fourth quarter
  • Continuing cost reduction program; reduced annualized cash G&A
  • Second quarter production volumes averaged 15.9 MBoe per day

DENVER, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today announces its second quarter 2017 financial results and operating outlook and has posted an updated investor presentation to its corporate website.

Jack Vaughn, Chairman of the Board of Directors commented, "On behalf of the Board of Directors, we are very pleased with our team's swift progress in commencing the Company's 2017 drilling and completion program. Three key objectives of this program are to maximize well performance through completion design enhancements, reduce the cost structure at the field and corporate level, commence operations in the French Lake area, and allocate capital at a pace that preserves the Company's balance sheet. As the team executes the 2017 capital program, the Board of Directors has engaged an executive search firm to identify and review CEO candidates and is simultaneously assessing strategic opportunities. With strong leadership, we believe that Bonanza Creek can become a premier DJ Basin producer."

Second Quarter 2017 Results

For the second quarter of 2017, the Company reported average daily production of 15.9 MBoe per day, in line with the Company's guidance of 15.8 – 16.2 Mboe per day, and a 32% decrease from the second quarter of 2016. The reduction in production volumes from the prior year is a result of having no drilling and completion activity during the previous five quarters. Product mix for the second quarter of 2017 was 51% oil, 22% NGLs, and 27% natural gas. 

Net revenue for the second quarter of 2017 was $44.1 million, compared to $54.5 million for the second quarter of 2016. Crude oil accounted for approximately 74% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $4.45 per Bbl, a 50% decrease from the second quarter of 2016. The significant reduction in the Company's oil differentials is a result of its recently restructured oil purchasing contracts in the Wattenberg. Corporate average realized prices for the second quarter of 2017 are presented below.

Average Realized Prices   Three Months Ended
June 30, 2017
 Oil (per Bbl)44.89 Gas (per Mcf)2.52 NGL (per Bbl)16.71 Boe (Per Boe)30.51 

Lease operating expense ("LOE") for the second quarter of 2017 was $9.4 million, or $6.47 per Boe, a 13% reduction in total LOE compared to $10.7 million or $5.08 per Boe in the second quarter of 2016. Per unit metrics have increased from year to year as a result of declining volumes. These metrics are expected to improve as activity is restarted and production volumes stabilize and increase.

Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the second quarter of 2017.

  Three Months Ended June 30, 2017 Rocky Mountain Mid-Continent Total Company ($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)Lease operating expense$6,808  $5.94  $2,548  $8.46  $9,356  $6.47 Gas plant and midstream operating expense$1,535  $1.34  $1,063  $3.53  2,598  $1.80 Total$8,343  $7.28  $3,611  $11.99  $11,954  $8.27 

The Company's general and administrative ("G&A") expense was $19.1 million for the second quarter of 2017, a 45% increase from the second quarter of 2016. The increase is primarily due to approximately $7.1 million in non-cash stock compensation, which was accelerated in connection with the departure of the Company's former CEO on June 11, 2017, and $1.1 million of post-petition restructuring fees. The Company's recurring cash G&A expense for the second quarter of 2017 was $9.2 million and is exclusive of the aforementioned post-petition restructuring fees. This compares to prior year recurring cash G&A expense of $10.9 million. The benefits of the Company's ongoing G&A cost reduction program are discussed below. Recurring cash G&A is a non-GAAP measure. Please refer to the reconciliation to GAAP general and administrative expense in the financial exhibits to this press release.

Operational Highlights

Testing and Assessing Enhanced Completions
During the second quarter of 2017, the Company completed its first pad of 4 drilled uncompleted ("DUC") wells. These 4,100-foot standard reach lateral ("SRL") wells were completed using approximately 2,000 pounds of sand per lateral foot and utilized approximately 100-foot stage spacing. This enhanced completion design compares to the Company's previous standard design of approximately 1,000 pounds per lateral foot of sand and stage spacing of approximately 160 feet. Flow-back of these wells has utilized the Company's enhanced recovery flow-back protocol, which provides choke management to increase oil cuts and overall recoveries by maintaining down-hole pressures higher for longer and decreasing medium-term decline rates. The DUCs started flowing back on July 2, 2017 and while early, the initial results are encouraging.

The Company commenced its 2017 drilling program at the end of July by spudding a three-well pad, consisting of one, 9,600 foot extended reach lateral ("XRL") well and two SRL wells. The Company expects the first pad to be turned into sales during the fourth quarter.

All of the Company's 2017 drilling and completion activity will utilize various forms of enhanced completion design to maximize well productivity, recovery, and project economics.

In addition to its operated program, the Company plans to participate in approximately 18 gross non-operated wells. These 18 wells will also test enhanced completions and provide informative and useful well data over a broader areal extent of the Company's acreage with lower capital commitments. The operated and non-operated programs will together provide a significant data set of 43 well results. These results will provide key information regarding the potential uplift from various leading-edge completion designs, which will inform the Company's development plans.

French Lake Opportunity
During 2017 and into the beginning of 2018, the Company plans to drill and complete eight XRL wells in its French Lake area. The Company acquired this acreage in the fall of 2014 and, with its financial restructuring and recapitalization complete, the Company is eager to confirm the geology and reservoir performance of the area. Bonanza Creek is pursuing its plans under an agreement with an offset operator, and upon completion of these eight wells, will essentially eliminate all of the Company's near-term lease expiry risk in its Wattenberg acreage. The Company plans to pursue a comprehensive agreement to develop this acreage with the offset operator.

Production, Capital, and Expense Outlook

The Company is reiterating its production and capital guidance for the remainder of the year and providing initial cost guidance for 2017. As a part of its ongoing cost structure review, the Company executed a reduction in force subsequent to the second quarter, which resulted in a reduction of 25% of its employee base. Based on these changes, the Company now expects its annualized recurring cash G&A expense to be within the range of $30 – $32 million, which compares to $45.6 million of recurring cash G&A in 2016. Recurring G&A expense excludes non-recurring items associated with advisor fees and severance charges. These announced G&A savings, along with continued efforts to reduce LOE and further reduce non-payroll G&A, will help drive Bonanza Creek towards its goal of increasing full-cycle returns.

 Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2017.

Guidance Summary    Three Months Ended
September 30, 2017 Twelve Months Ended
December 31, 2017    Production (MBoe/d)15.8 – 16.2 16.3 – 16.7LOE ($/Boe)  $6.50 – $7.00Midstream expense ($/Boe)  $1.90 – $2.10Cash G&A* ($MM)  $38 – $40Production taxes (% of pre-derivative realization)  7% – 8%Total CAPEX ($MM)  $120 – $130* Cash G&A guidance assumes expected severance costs of $2.0 million in the third quarter of 2017 and nonrecurring expenses of $3.2 million. Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation portion of GAAP G&A.

Financial Highlights

As of the end of the second quarter, the Company had liquidity of $246 million, which included cash on hand of $54 million and $192 million of borrowing capacity under its credit facility.  The Company has no outstanding term debt and its credit facility is undrawn. Based on the terms of the credit facility, the Company's next borrowing base redetermination will occur in April of 2018. The Company's balance sheet strength allows it to be flexible, patient and selective in its investment decisions, and the opportunity to participate in acquisition opportunities and the flexibility to objectively evaluate divestiture candidates.

Commodity Derivative Position
Subsequent to the second quarter, the Company began to implement hedges for oil and gas for the remainder of 2017 through the first half of 2019. As the new wells are turned into sales, the Company plans to add incremental hedges to lock in cash flows and project returns. The Company's current hedge position is summarized in the table below.

  Crude Oil
(NYMEX WTI) Natural Gas
(NYMEX Henry Hub)  Bbls/day Weighted Avg.
Price per Bbl MMBtu/day Weighted Avg.
Price per MMBTU4Q17        Cashless Collar 2,000  $41.50/$51.00 2,600  $3.00/$3.301Q18        Swap —    3,000  3.35Cashless Collar 2,000  $42.00/$52.50 2,600  $2.75/$3.352Q18        Cashless Collar 2,000  $42.00/$52.50 2,600  $2.75/$3.353Q18        Cashless Collar 1,000  $41.00/$52.00 2,600  $2.75/$3.354Q18        Cashless Collar 1,000  $41.00/$52.00 2,600  $2.75/$3.351Q19        Cashless Collar 1,000  $41.00/$54.00 —   April 2019        Cashless Collar 1,000  $41.00/$54.00 —   

Fresh Start Accounting

The Company adopted fresh-start accounting as of April 28, 2017, the effective date of its emergence from Chapter 11 bankruptcy proceedings, resulting in a new corporate entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result, the Company’s unaudited condensed consolidated financial statements subsequent to April 28, 2017 are not comparable to its financial statements prior to April 28, 2017. References to "Predecessor" refer to the Company prior to the adoption of fresh-start accounting while references to "Successor" refer to the Company subsequent to the adoptions of fresh-start accounting. Please review the Company’s second quarter 2017 Form 10-Q for further details regarding fresh-start accounting and the financial information presented at the end of this release.

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on August 9, 2017 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time). A webcast of the live event, as well as a replay,  will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. Dial-in information for the conference call is included below.

TypePhone NumberPasscodeLive Participant877-793-436263290457Replay855-859-205663290457

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated primarily in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains 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 statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; and updated 2017 guidance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2016, filed on March 16, 2017, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Schedule 1: Statement of Operations
(in thousands, expect for per share amounts, unaudited)

 Successor  PredecessorPredecessor April 29, 2017
through June 30,
2017
  April 1, 2017
through April 28,
2017
Three Months
Ended June 30,
2016
Operating net revenues:     Oil and gas sales$28,114   $16,030 $54,530 Operating expenses:     Lease operating expense6,153   3,203 10,737 Gas plant and midstream operating expense1,762   836 3,535 Severance and ad valorem taxes2,408   1,352 4,277 Exploration359   292 677 Depreciation, depletion and amortization4,836   6,853 30,927 Abandonment and impairment of unproved properties—   — 9,875 General and administrative (including $7,949, $391 and $2,380, respectively, of stock-based compensation)16,139   2,998 13,235 Total operating expenses31,657   15,534 73,263 Income (loss) from operations(3,543)  496 (18,733)Other income (expense):     Derivative loss—   — (12,923)Interest expense(195)  (1,088)(16,527)Reorganization items, net—   97,811 — Other income (loss)158   (283)(1,294)Total other income (expense)(37)  96,440 (30,744)Income (loss) from operations before taxes(3,580)  96,936 (49,477)Income tax benefit (expense)—   — — Net income (loss)$(3,580)  $96,936 $(49,477)Comprehensive income (loss)$(3,580)  $96,936 $(49,477)      Basic net income (loss) per common share$(0.18)  $1.88 $(1.00)        Diluted net income (loss) per common share$(0.18)  $1.85 $(1.00)      Basic weighted-average common shares outstanding20,369   49,902 49,277       Diluted weighted-average common shares outstanding20,369   50,486 49,277          
  • The Predecessor Company followed the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
             Successor  PredecessorPredecessor April 29, 2017
through June 30,
2017
  January 1, 2017
through April 28,
2017
Six Months Ended
June 30, 2016
Operating net revenues:     Oil and gas sales$28,114   $68,589 $98,704 Operating expenses:     Lease operating expense6,153   13,128 24,035 Gas plant and midstream operating expense1,762   3,541 7,324 Severance and ad valorem taxes2,408   5,671 7,431 Exploration359   3,699 943 Depreciation, depletion and amortization4,836   28,065 57,306 Impairment of oil and gas properties—   — 10,000 Abandonment and impairment of unproved properties—   — 16,781 Unused commitments—   993 — General and administrative (including $7,949, $2,116, $5,384, respectively, of stock-based compensation)16,139   15,092 30,920 Total operating expenses31,657   70,189 154,740 Loss from operations(3,543)  (1,600)(56,036)Other income (expense):     Derivative loss—   — (13,930)Interest expense(195)  (5,656)(31,074)Reorganization items, net—   8,808 — Gain on termination fee—   — 6,000 Other income (loss)158   1,108 (1,674)Total other income (expense)(37)  4,260 (40,678)Income (loss) from operations before taxes(3,580)  2,660 (96,714)Income tax benefit (expense)—   — — Net income (loss)$(3,580)  $2,660 $(96,714)Comprehensive income (loss)$(3,580)  $2,660 $(96,714)      Basic net income (loss) per common share$(0.18)  $0.05 $(1.97)      Diluted net income (loss) per common share$(0.18)  $0.05 $(1.97)      Basic weighted-average common shares outstanding20,369   49,559 49,204       Diluted weighted-average common shares outstanding20,369   50,971 49,204          
  • The Predecessor Company followed the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.


Schedule 2: Statement of Cash Flows
(in thousands, unaudited)

 Successor  PredecessorPredecessor April 29, 2017
through June
30, 2017
  April 1, 2017
through April
28, 2017
Three Months
Ended June
30, 2016
      Cash flows from operating activities:     Net income (loss)$(3,580)  $96,936 $(49,477)Adjustments to reconcile net income (loss) to net cash provided by operating activities:     Depreciation, depletion and amortization4,836   6,853 30,927 Non-cash reorganization items—   (101,501)— Abandonment and impairment of unproved properties—   — 9,875 Well abandonment costs and dry hole expense64   230 734 Stock-based compensation7,949   391 2,380 Amortization of deferred financing costs and debt premium—   374 1,671 Derivative loss—   — 12,923 Derivative cash settlements—   — 3,893 Other5   (365)4 Changes in current assets and liabilities:     Accounts receivable6,420   (2,826)371 Prepaid expenses and other assets270   1,499 274 Accounts payable and accrued liabilities(19,338)  (36,972)(25,316)Settlement of asset retirement obligations(459)  (155)(34)Net cash used in operating activities(3,833)  (35,536)(11,775)Cash flows from investing activities:     Acquisition of oil and gas properties(4,982)  (6)(284)Exploration and development of oil and gas properties(4,913)  (1,698)(7,881)Payments of contractual obligation—   — (12,000)Increase in restricted cash(2)  — (2)Additions to property and equipment - non oil and gas(161)  (253)(8)Net cash used in investing activities(10,058)  (1,957)(20,175)Cash flows from financing activities:     Payments to credit facility—   (191,667)(14,667)Proceeds from sale of common stock—   207,500 — Deferred restructuring charges—   — (1,684)Payment of employee tax withholdings in exchange for the return of common stock(2,080)  (92)(44)Deferred financing costs—   — (83)Net cash (used in) provided by financing activities(2,080)  15,741 (16,478)Net change in cash and cash equivalents(15,971)  (21,752)(48,428)Cash and cash equivalents:     Beginning of period70,183   91,935 218,599 End of period$54,212   $70,183 $170,171             


 Successor  PredecessorPredecessor April 29, 2017
through June
30, 2017
  January 1,
2017 through
April 28, 2017
Six Months
Ended June
30, 2016
      Cash flows from operating activities:     Net income (loss)$(3,580)  $2,660 $(96,714)Adjustments to reconcile net income (loss) to net cash provided by operating activities:     Depreciation, depletion and amortization4,836   28,065 57,306 Non-cash reorganization items—   (44,160)— Impairment of oil and gas properties—   — 10,000 Abandonment and impairment of unproved properties—   — 16,781 Well abandonment costs and dry hole expense64   2,931 966 Stock-based compensation7,949   2,116 5,384 Amortization of deferred financing costs and debt premium—   374 2,279 Derivative loss—   — 13,930 Derivative cash settlements—   — 11,401 Other5   18 (112)Changes in current assets and liabilities:     Accounts receivable6,420   (6,640)23,415 Prepaid expenses and other assets270   963 (1,348)Accounts payable and accrued liabilities(19,338)  (5,880)(28,457)Settlement of asset retirement obligations(459)  (331)(75)Net cash  (used in) provided by operating activities(3,833)  (19,884)14,756 Cash flows from investing activities:     Acquisition of oil and gas properties(4,982)  (445)(816)Exploration and development of oil and gas properties(4,913)  (5,123)(42,753)Payments of contractual obligation—   — (12,000)(Increase) decrease in restricted cash(2)  118 (2,535)(Additions) deletions to property and equipment - non oil and gas(161)  (454)39 Net cash used in investing activities(10,058)  (5,904)(58,065)Cash flows from financing activities:     Proceeds from credit facility—   — 209,000 Payments to credit facility—   (191,667)(14,667)Proceeds from sale of common stock—   207,500 — Deferred restructuring charges—   — (1,684)Payment of employee tax withholdings in exchange for the return of common stock(2,080)  (427)(273)Deferred financing costs—   — (237)Net cash (used in) provided by financing activities(2,080)  15,406 192,139 Net change in cash and cash equivalents(15,971)  (10,382)148,830 Cash and cash equivalents:     Beginning of period70,183   80,565 21,341 End of period$54,212   $70,183 $170,171                         

Schedule 3: Condensed Consolidated Balance Sheets
(in thousands, unaudited)

 Successor  Predecessor June 30, 2017  December 31,
2016
ASSETS    Current assets:    Cash and cash equivalents$54,212   $80,565 Accounts receivable:    Oil and gas sales18,410   14,479 Joint interest and other3,073   6,784 Prepaid expenses and other4,682   5,915 Inventory of oilfield equipment3,942   4,685 Total current assets84,319   112,428 Property and equipment (successful efforts method):    Proved properties498,229   2,525,587 Less: accumulated depreciation, depletion and amortization(4,266)  (1,694,483)Total proved properties, net493,963   831,104 Unproved properties183,443   163,369 Wells in progress16,100   18,250 Other property and equipment, net of accumulated depreciation of $238 in 2017 and $11,206 in 20165,980   6,245 Total property and equipment, net699,486   1,018,968 Other noncurrent assets2,739   3,082 Total assets$786,544   $1,134,478 LIABILITIES AND STOCKHOLDERS’ EQUITY    Current liabilities:    Accounts payable and accrued expenses$28,586   $61,328 Oil and gas revenue distribution payable22,321   23,773 Revolving credit facility - current portion—   191,667 Senior Notes - current portion—   793,698 Total current liabilities50,907   1,070,466      Long-term liabilities:    Ad valorem taxes20,288   14,118 Asset retirement obligations for oil and gas properties28,938   30,833 Total liabilities100,133   1,115,417      Commitments and contingencies         Stockholders’ equity:    Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2016—   — Predecessor common stock, $.001 par value, 225,000,000 shares authorized,  49,660,683 issued and outstanding as of December 31, 2016—   49 Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of June 30, 2017—   — Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,429,691 issued and outstanding as of June 30, 20174,286   — Additional paid-in capital685,705   814,990 Accumulated deficit(3,580)  (795,978)Total stockholders’ equity686,411   19,061 Total liabilities and stockholders’ equity$786,544   $1,134,478                   

Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)

 Three Months Ended
June 30,
 Six Months Ended
June 30,
 2017 2016 2017 2016Wellhead Volumes and Prices               Crude Oil and Condensate Sales Volumes (Bbl/d)       Rocky Mountains6,189  10,715  6,690  11,190 Mid-Continent1,845  2,270  1,889  2,353 Total8,034  12,985  8,579  13,543         Crude Oil and Condensate Realized Prices ($/Bbl)       Rocky Mountains$44.06  $36.74  $46.32  $30.70 Mid-Continent$47.69  $45.18  $49.94  $40.41 Composite$44.89  $38.21  $47.11  $32.39 Composite (after derivatives)$44.89  $41.51  $47.11  $37.01         Natural Gas Liquids Sales Volumes (Bbl/d)       Rocky Mountains3,046  3,772  3,167  3,594 Mid-Continent452  675  471  697 Total3,498  4,447  3,638  4,291         Natural Gas Liquids Realized Prices ($/Bbl)       Rocky Mountains$16.10  $10.59  $15.99  $11.80 Mid-Continent$20.84  $16.75  $23.45  $14.48 Composite$16.71  $11.53  $16.96  $12.23 Composite (after derivatives)$16.71  $11.53  $16.96  $12.23         Natural Gas Sales Volumes (Mcf/d)       Rocky Mountains20,144  27,450  20,786  28,044 Mid-Continent6,067  7,444  6,249  7,648 Total26,211  34,894  27,035  35,692         Natural Gas Realized Prices ($/Mcf)       Rocky Mountains$2.36  $1.34  $2.48  $1.27 Mid-Continent$3.06  $2.01  $3.17  $2.05 Composite$2.52  $1.48  $2.64  $1.44 Composite (after derivatives)$2.52  $1.48  $2.64  $1.44         Crude Oil Equivalent Sales Volumes (Boe/d)       Rocky Mountains12,592  19,062  13,322  19,458 Mid-Continent3,308  4,186  3,402  4,325 Total15,900  23,248  16,724  23,783         Crude Oil Equivalent Sales Prices ($/Boe)       Rocky Mountains$29.31  $24.68  $30.93  $21.66 Mid-Continent$35.05  $30.78  $36.79  $27.94 Composite$30.51  $25.78  $32.12  $22.80 Composite (after derivatives)$30.51  $27.62  $32.12  $25.44         Total Sales Volumes (MBoe)1,446.9  2,115.5  3,026.9  4,328.7                         

Schedule 5: Per unit operating margins
(unaudited)

 Three Months Ended June 30, Six Months Ended June 30, 2017 2016 Percent
Change
 2017 2016 Percent
Change
Production           Oil (MBbl)731  1,182  (38)% 1,553  2,465  (37)%Gas (MMcf)2,385  3,175  (25)% 4,893  6,496  (25)%NGL (MBbl)318  405  (21)% 659  781  (16)%Equivalent (MBoe)1,447  2,116  (32)% 3,027  4,329  (30)%                  Realized pricing (before derivatives)                Oil ($/Bbl)$44.89  $38.21  17% $46.85  $32.38  45%Gas ($/Mcf)$2.52  $1.48  70% $2.63  $1.44  83%NGL ($/Bbl)$16.71  $11.53  45% $16.86  $12.23  38%Equivalent ($/Boe)$30.51  $25.78  18% $31.95  $22.80  40%                  Per Unit Costs ($/Boe)                 Realized price (before derivatives)$30.51  $25.78  18% $31.95  $22.80  40%Lease operating expense6.47  5.08  27%  6.37   5.55  15%Gas plant and midstream operating expense1.80  1.67  8%  1.75   1.69  4%Severance and ad valorem2.60  2.02  29%  2.67   1.72  55%Cash general and administrative7.46  5.13  45%  6.99   5.90  18%Total cash operating costs$18.33  $13.90  32% $17.78  $14.86  20%Cash operating margin (before derivatives)$12.18  $11.88  3% $14.17  $7.94  78%Derivative cash settlements—  1.84  (100)% —  2.64  (100)%Cash operating margin (after derivatives)$12.18  $13.72  (11)% $14.17  $10.58  34%                  Non-cash items                 Non-cash general and administrative$5.76  $1.13  410% $3.33  $1.24  169%                                            

Schedule 6: Adjusted Net Income (Loss)
(in thousands, except per share amounts, unaudited)

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted net loss as net loss after adjusting first for (1) the impact of certain non-cash items and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate that approximates the Company's effective tax rate in each period. Adjusted net loss is not a measure of net income as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net loss.

  Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017 2016 2017 2016Net Income (Loss) $93,356  $(49,477) $(920) $(96,714)Adjustments to Net Income (Loss):        Derivative loss —  12,923  —  13,930 Derivative cash settlements —  3,893  —  11,401 Gain on termination fee —  —  —  (6,000)Impairment of proved properties —  —  —  10,000 Abandonment and impairment of unproved properties —  9,875  —  16,781 Exploratory dry hole expense 294  734  2,995  966 Stock-based compensation (1) 8,340  2,380  10,065  5,384 Severance costs (1) —  —  —  2,162 Reorganization items (97,811) —  (8,808) — Pre-petition advisory fees (1) —  —  683  — Post-petition restructuring fees (1) 1,422  —  1,422  — Total adjustments before taxes (87,755) 29,805  6,357  54,624 Income tax effect —  —  —  — Total adjustments after taxes $(87,755) $29,805  $6,357  $54,624          Adjusted net income (loss) $5,601  $(19,672) $5,437  $(42,090)Adjusted net loss per diluted share (2) $0.27  $(0.40) $0.27  $(0.86)         Diluted weighted-average common shares outstanding (2) 20,369  49,277  20,369  49,204          (1) Included as a portion of general and administrative expense on the consolidated statement of operations.(2) For the three and six-month periods ended June 30, 2017, the Company used the Successor's diluted weighted average share count to calculated adjusted net income per diluted share.  

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

  Three Months Ended June 30, Six Months Ended June 30,  2017 2016 2017 2016Net Income (loss) $93,356  $(49,477) $(920) $(96,714)Exploration 651  677  4,058  943 Depreciation, depletion and amortization 11,689  30,927  32,901  57,306 Impairment of proved properties —  —  —  10,000 Abandonment and impairment of unproved properties —  9,875  —  16,781 Stock-based compensation 8,340  2,380  10,065  5,384 Severance costs (1) —  —  —  2,162 Gain on termination fee —  —  —  (6,000)Interest expense 1,283  16,527  5,851  31,074 Derivative loss —  12,923  —  13,930 Derivative cash settlements —  3,893  —  11,401 Pre-petition advisory fees (1) —  —  683  — Post-petition restructuring fees (1) 1,422  —  1,422  — Reorganization items (97,811) —  (8,808)  — Income tax benefit —  —  —  — Adjusted EBITDAX $18,930  $27,725  $45,252  $46,267          (1) Included as a portion of general and administrative expense on the consolidated statement of operations.


Schedule 8: Recurring Cash G&A
(in thousands, unaudited)                                                 

Recurring cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines recurring cash G&A as GAAP G&A after adjusting for the impact of non-cash stock compensation expense and non-recurring items.

The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of recurring cash G&A.

  Three Months Ended June 30,  2017 2016General and Administrative $19,137  $13,235 Stock-based compensation (8,340) (2,380)Cash G&A $10,797  $10,855 Post-petition restructuring fees (1,422) — Other non-recurring expense (184) — Recurring Cash G&A $9,191  $10,855 


CONTACT: For further information, please contact: James R. Edwards Director - Investor Relations 720-440-6136 jedwards@bonanzacrk.com

Categories: State

NCS Multistage Holdings, Inc. Announces Second Quarter 2017 Results

8 August 2017 - 3:35pm

Second Quarter Highlights

  • Total revenue of $36.9 million, a 227% year-over-year increase
  • Net loss attributable to NCS of $(4.5) million, a $4.1 million improvement from the prior year
  • Net loss attributable to NCS of $(0.11) per diluted share; ($0.09) adjusted net loss per diluted share
  • Adjusted EBITDA of $4.8 million, a $7.3 million improvement from the prior year, and an Adjusted EBITDA margin of 13%
  • Total liquidity of $130.0 million, comprised of $80.0 million in cash on hand and $50.0 million of revolver capacity

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- NCS Multistage Holdings, Inc. (NASDAQ:NCSM) (“NCS” or the “Company”), a leading provider of highly engineered products and support services that facilitate the optimization of oil and natural gas well completions and field development strategies, today announced its results for the quarter ended June 30, 2017.

Financial Review

Revenues were $36.9 million for the quarter, an increase of $25.6 million, or 227% as compared to the second quarter of 2016. This increase was primarily attributable to an increase in the sale of completions products and services due to higher customer drilling and well completion activity as a result of an improved commodity price environment in the second quarter of 2017 as compared to the second quarter of 2016.

On a sequential basis, total revenues fell by 37% as compared to the first quarter, with a 60% sequential decline in Canadian revenues offset by sequential revenue increases from our U.S. and international operations. The 37% sequential revenue decline is an improvement as compared to the 51% sequential revenue decline during the same period in 2016, with the improvement driven primarily by higher contributions from the less-seasonal U.S. and international markets and the Canadian Deep Basin.

Net loss attributable to NCS was $(4.5) million, or $(0.11) diluted loss per share for the quarter ended June 30, 2017, which included a net expense of $1.0 million ($0.8 million after tax, or $0.02 per diluted share) related to the write-off of debt issuance costs, IPO-related professional expenses, realized and unrealized foreign currency gains and losses and the change in fair value of contingent consideration.  Adjusted net loss attributable to NCS, which excludes these items, was $(3.7) million or $(0.09) per diluted share. This compares to a net loss attributable to NCS of $(8.6) million, or $(0.25) diluted loss per share in the second quarter of 2016, which included a net expense of $0.6 million ($0.4 million after tax, or $0.01 per diluted share) related to restructuring charges and realized and unrealized foreign currency gains and losses. Adjusted net loss attributable to NCS, which excludes these items, was $(8.2) million or $(0.24) per diluted share.

Adjusted EBITDA was $4.8 million for the quarter, an increase of $7.3 million as compared to the second quarter of 2016. Adjusted EBITDA margin for the second quarter of 2017 was 13%, as compared to (22%) for the second quarter of 2016.

For the first half of 2017, the Company reported revenues of $95.5 million, an increase of $61.1 million, or 178% as compared to the first half of 2016. Net income attributable to NCS of $2.1 million in the first half of 2017 compares to a net loss of $(16.7) million in the first half of 2016. Adjusted EBITDA of $24.0 million for the first half of 2017 was an increase of $23.8 million as compared to the first half of 2016.

NCS completed its initial public offering of its common stock on May 3, 2017, thus a portion of the second quarter of 2017 reflects a period during which the Company was privately-owned.

Capital Expenditures and Liquidity

The Company spent $2.2 million in capital expenditures, net, during the second quarter of 2017. These expenditures were made to support the growth of the business, including certain investments to increase sliding sleeve production capacity.

As of June 30, 2017, the Company had $80.0 million in cash, total availability under its revolving facility of $50.0 million and $3.2 million in total debt.  

NCS’s Chief Executive Officer, Robert Nipper, commented, “I am very pleased with our performance in the second quarter. We continue to execute on our strategy to grow our customer base in all of our core geographies, which resulted in record second quarter volumes for NCS across sliding sleeve and AirLock sales as well as wells completed. With the successful completion of our IPO, we are well-positioned to continue to bring innovative products and services to our customers to help them optimize completion designs and field development strategies. I’d like to thank all of our employees for their tremendous efforts during this exciting time for NCS.”

Adjusted EBITDA, Adjusted EBITDA margin, and Adjusted Net (Loss) Earnings per Diluted Share are non-GAAP financial measures. For an explanation of these measures and a reconciliation, refer to “Non-GAAP Financial Measures” below.

Conference Call

The Company will host a conference call to discuss its second quarter 2017 results on Wednesday, August 9, 2017 at 7:30 a.m. Central Time (8:30 a.m. Eastern Time). To join the conference call from within the United States, participants may dial (844) 400-1696. To join the conference call from outside of the United States, participants may dial (703) 736-7385. The conference access code is 58076646. Participants are encouraged to log in to the webcast or dial in to the conference call approximately ten minutes prior to the start time. To listen via live webcast, please visit the Investors section of the Company’s website, http://www.ncsmultistage.com

An audio replay of the conference call will be available shortly after the conclusion of the call and will remain available for approximately seven days. It can be accessed by dialing (855) 859-2056 within the United States or (404) 537-3406 outside of the United States. The conference call replay access code is 58076646. The replay will also be available in the Investors section of the Company’s website shortly after the conclusion of the call and will remain available for approximately seven days.

About NCS Multistage Holdings, Inc.

NCS Multistage Holdings, Inc. is a leading provider of highly engineered products and support services that facilitate the optimization of oil and natural gas well completions and field development strategies. The Company provides products and services to exploration and production companies for use in horizontal wells in unconventional oil and natural gas formations throughout North America and in selected international markets, including Argentina, China and Russia. The Company’s common stock is traded on the NASDAQ Global Select Market under the symbol “NCSM.” Additional information is available on the Company’s website, www.ncsmultistage.com

Forward Looking Statements

This press release contains forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Examples of forward-looking statements include, but are not limited to, statements we make regarding the outlook for our future business and financial performance. Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, by their nature, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. As a result, our actual results may differ materially from those contemplated by the forward-looking statements. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to declines in the level of oil and natural gas exploration and production activity within Canada and the United States oil and natural gas price fluctuations; loss of significant customers; inability to successfully implement our strategy of increasing sales of products and services into the United States; significant competition for our products and services; our inability to successfully develop and implement new technologies, products and services; our inability to protect and maintain critical intellectual property assets; currency exchange rate fluctuations; impact of severe weather conditions; restrictions on the availability of our customers to obtain water essential to the drilling and hydraulic fracturing processes; our failure to identify and consummate potential acquisitions; our inability to accurately predict customer demand; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in legislation or regulation governing the oil and natural gas industry, including restrictions on emissions of GHGs; failure to comply with federal, state and local and non-U.S. laws and other regulations; loss of our information and computer systems; system interruptions or failures, including cyber-security breaches, identity theft or other disruptions that could compromise our information; our failure to establish and maintain effective internal control over financial reporting; our success in attracting and retaining qualified employees and key personnel; our inability to satisfy technical requirements and other specifications under contracts and contract tenders and other factors discussed or referenced in our filings made from time to time with the Securities and Exchange Commission. Any forward-looking statement made by us in this press release speaks only as of the date on which we make it. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

 

 NCS MULTISTAGE HOLDINGS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)               Three Months Ended Six Months Ended  June 30, June 30,  2017  2016  2017  2016 Revenues            Product sales $ 29,397  $ 8,747  $ 74,971  $ 25,959 Services   7,460    2,534    20,522    8,429 Total revenues   36,857    11,281    95,493    34,388 Cost of sales            Cost of product sales, exclusive of depreciation
 and amortization expense shown below   15,733    4,936    40,448    14,485 Cost of services, exclusive of depreciation
 and amortization expense shown below   3,152    1,553    7,791    4,699 Total cost of sales, exclusive of depreciation
 and amortization expense shown below   18,885    6,489    48,239    19,184 Selling, general and administrative expenses   16,163    8,417    28,935    16,872 Depreciation   678    450    1,242    902 Amortization   5,973    6,092    11,995    11,863 Change in fair value of contingent consideration   767    —    767    — (Loss) income from operations   (5,609)   (10,167)   4,315    (14,433)Other income (expense)            Interest expense, net   (2,007)   (1,590)   (3,516)   (3,056)Other income (expense), net   64    (37)   1,038    (11)Foreign currency exchange gain (loss)   1,952    (451)   1,011    (6,329)Total other income (expense)   9    (2,078)   (1,467)   (9,396)(Loss) income before income tax   (5,600)   (12,245)   2,848    (23,829)Income tax (benefit) expense   (855)   (3,655)   1,245    (7,113)Net (loss) income   (4,745)   (8,590)   1,603    (16,716)Net loss attributable to non-controlling interest   254    —    456    — Net (loss) income attributable to
 NCS Multistage Holdings, Inc.
 $ (4,491) $ (8,590) $ 2,059  $ (16,716)(Loss) earnings per common share            Basic (loss) earnings per common share attributable to
 NCS Multistage Holdings, Inc. $ (0.11) $ (0.25) $ 0.05  $ (0.49)Diluted (loss) earnings per common share attributable to
 NCS Multistage Holdings, Inc. $ (0.11) $ (0.25) $ 0.05  $ (0.49)Weighted average common shares outstanding            Basic   40,198    34,001    37,119    34,010 Diluted   40,198    34,001    40,188    34,010 

 

 NCS MULTISTAGE HOLDINGS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)         June 30, December 31,  2017  2016 Assets      Current assets      Cash and cash equivalents $ 79,991   $ 18,275  Accounts receivable—trade, net   36,656     32,116  Inventories   22,382     17,017  Prepaid expenses and other current assets   1,561     2,445  Other current receivables   1,284     3,053  Deferred income taxes, net   —    2,116  Total current assets   141,874     75,022  Noncurrent assets      Property and equipment, net   18,307     9,759  Goodwill   141,439     122,077  Identifiable intangibles, net   113,910     118,697  Deposits and other assets   1,491     1,272  Total noncurrent assets   275,147     251,805  Total assets $ 417,021   $ 326,827  Liabilities and Stockholders’ Equity      Current liabilities      Accounts payable—trade $ 10,623   $ 10,258  Accrued expenses   4,749     3,290  Income taxes payable   4,763     — Other current liabilities   1,975     3,223  Current maturities of long-term debt   2,059     772  Total current liabilities   24,169     17,543  Noncurrent liabilities      Long-term debt, less current maturities   1,133     88,394  Other long-term liabilities   8,493     717  Deferred income taxes, net   32,825     42,695  Total noncurrent liabilities   42,451     131,806  Total liabilities   66,620     149,349  Commitments and contingencies      Stockholders’ equity      Preferred stock, $0.01 par value, 1 share authorized, issued, and outstanding at   —    — June 30, 2017 and December 31, 2016, respectively      Common stock, $0.01 par value, 225,000,000 shares authorized, 43,574,326 shares issued      and 43,555,978 shares outstanding at June 30, 2017 and 54,000,000 shares authorized,      34,024,326 shares issued and 34,005,978 shares outstanding at December 31, 2016   436     340  Additional paid-in capital   388,243     237,566  Accumulated other comprehensive loss   (74,422)   (82,015)Retained earnings   23,821     21,762  Treasury stock, at cost; 18,348 shares at June 30, 2017 and at December 31, 2016   (175)   (175)Total stockholders’ equity   337,903     177,478  Non-controlling interest   12,498     — Total equity   350,401     177,478  Total liabilities and stockholders' equity $ 417,021   $ 326,827  

 

NCS MULTISTAGE HOLDINGS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)         Six Months Ended  June 30,  2017  2016 Cash flows from operating activities   Net income (loss) $ 1,603  $ (16,716)Adjustments to reconcile net income (loss) to net cash provided by operating activities:      Depreciation and amortization   13,237    12,765 Amortization of deferred loan cost   289    366 Share-based compensation   1,836    670 Deferred income tax benefit   (8,577)   (5,148)(Gain) loss on sale of property and equipment   (44)   4 Foreign exchange (gain) loss on financing item   (1,780)   6,141 Write-off of deferred loan costs   1,422    — Change in fair value of contingent consideration   767    — Changes in operating assets and liabilities:      Accounts receivable—trade   (3,598)   15,530 Inventories   (4,866)   2,003 Prepaid expenses and other assets   (601)   (233)Accounts payable—trade   60    (2,615)Accrued expenses   1,407    (144)Other liabilities   (679)   38 Income taxes receivable/payable   6,564    (1,775)Net cash provided by operating activities   7,040    10,886 Cash flows from investing activities      Purchases of property and equipment   (3,873)   (301)Proceeds from sales of property and equipment   137    215 Proceeds from short-term note receivable   1,000    — Acquisition of business, net of cash acquired   (5,996)   — Net cash used in investing activities   (8,732)   (86)Cash flows from financing activities      Equipment note borrowings   1,533    — Payments on equipment note   (80)   — Promissory note borrowings   2,955    — Payments on promissory note   (1,216)   — Payment of deferred loan cost related to new credit agreement   (683)   — Payments related to public offering   (2,178)   — Proceeds from related party note receivable   752    — Repayment of term note   (89,077)   — Purchases of treasury stock   —    (175)Proceeds from issuance of common stock, net of offering costs   151,356    50 Net cash provided by (used in) financing activities   63,362    (125)Effect of exchange rate changes on cash and cash equivalents   46    675 Net change in cash and cash equivalents   61,716    11,350 Cash and cash equivalents beginning of period   18,275    9,545 Cash and cash equivalents end of period $ 79,991  $ 20,895 

NCS MULTISTAGE HOLDINGS, INC.
RECONCILIATION OF GAAP TO NON-GAAP FINANCIAL INFORMATION 
(In thousands, except per share data)
(Unaudited)

Non-GAAP Financial Measures

EBITDA is defined as net income (loss) before interest expense, net, income tax expense (benefit) and depreciation and amortization. Adjusted EBITDA is defined as EBITDA adjusted to exclude certain items which we believe are not reflective of ongoing performance or which, in the case of share-based compensation, are non-cash in nature. Adjusted EBITDA margin represents Adjusted EBITDA as a percentage of total revenues. Adjusted Net (Loss) Earnings per Diluted Share is defined as net income (loss) attributable to NCS Multistage Holdings, Inc. adjusted to exclude certain items which we believe are not reflective of ongoing performance. We believe that Adjusted EBITDA and Adjusted Net (Loss) Earnings per Diluted Share are important measures that exclude costs that management believes do not reflect our ongoing operating performance and, in the case of Adjusted EBITDA, certain costs associated with our capital structure. Accordingly, Adjusted EBITDA and Adjusted EBITDA margin are key metrics that management uses to assess the period-to-period performance of our core business operations. We believe that presenting Adjusted EBITDA and Adjusted EBITDA margin enables investors to assess our performance from period to period using the same metrics utilized by management and that Adjusted EBITDA, Adjusted EBITDA margin and Adjusted Net (Loss) per Diluted Share enable investors to evaluate our performance relative to other companies that are not subject to such factors.

EBITDA, Adjusted EBITDA, Adjusted EBITDA margin and Adjusted Net (Loss) Earnings per Diluted Share (our “non-GAAP financial measures”) are not defined under generally accepted accounting principles (“GAAP”), are not measures of net income, income from operations or any other performance measure derived in accordance with GAAP, and are subject to important limitations. Our non-GAAP financial measures may not be comparable to similarly titled measures of other companies in our industry and are not measures of performance calculated in accordance with GAAP. Our non-GAAP financial measures have important limitations as analytical tools and you should not consider them in isolation or as substitutes for analysis of our financial performance as reported under GAAP and they should not be considered as alternatives to net income (loss) or any other performance measures derived in accordance with GAAP as measures of operating performance or as alternatives to cash flow from operating activities as measures of our liquidity.

The tables below set forth reconciliations of our non-GAAP financial measures to the most directly comparable measure of financial performance calculated under GAAP:

 

ADJUSTED NET (LOSS) EARNINGS PER DILUTED SHARE                           Three Months Ended Six Months Ended  June 30, 2017 June 30, 2016 June 30, 2017 June 30, 2016  Effect on
Net Loss
(After-
Tax)
 Impact on
Diluted Earnings
Per Share
 Effect on
Net Loss
(After-
Tax)
 Impact on
Diluted Earnings
Per
Share
 Effect on
Net Income
(After-
Tax)
 Impact on
Diluted
Earnings
Per Share
 Effect on
Net Loss
(After-
Tax)
 Impact on
Diluted
Earnings
Per Share
Net (loss) income attributable to
NCS Multistage Holdings, Inc. $ (4,491) $ (0.11) $ (8,590) $ (0.25) $ 2,059  $ 0.05  $ (16,716) $ (0.49)Adjustments (after tax)                        Write-off of debt issuance costs (a)   1,076    0.03    —    —    1,070    0.03    —    — Restructuring charges (b)   —    —    103    —    —    —    176    — IPO-related professional expense (c)   580    0.01    —    —    1,692    0.04    —    — Realized and unrealized (gains) losses (d)   (1,480)   (0.03)   316    0.01    (826)   (0.02)   4,441    0.13 Change in fair value of contingent consideration (e)   580    0.01    —    —    577    0.01    —    — Adjusted net (loss) income attributable
 to NCS Multistage Holdings, Inc. $ (3,735) $ (0.09) $ (8,171) $ (0.24) $ 4,572  $ 0.11  $ (12,099) $ (0.36)

_____________________

(a) Includes the remaining debt issuance costs of $1,422 related to the prior credit agreement that were expensed when the debt was repaid with a portion of our net proceeds from the initial public offering of shares of our common stock (“IPO”) during the three months ended June 30, 2017.

(b)Represents severance and other expenses associated with headcount reductions and other cost savings initiated as part of our restructuring initiatives.

(c) Represents costs of professional services incurred in connection with our IPO.

(d) Represents realized and unrealized foreign currency translation gains and losses primarily in respect of our indebtedness.

(e) Represents the change in the fair value of the earn-out associated with the Repeat Precision, LLC acquisition.

 

 NCS MULTISTAGE HOLDINGS, INC.
RECONCILIATION OF GAAP TO NON-GAAP FINANCIAL INFORMATION 
(In thousands)
(Unaudited)

ADJUSTED EBITDA AND ADJUSTED EBITDA MARGIN               Three Months Ended Six Months Ended  June 30, June 30,  2017  2016  2017  2016 Net (loss) income $ (4,745) $ (8,590) $ 1,603  $ (16,716)Income tax (benefit) expense   (855)   (3,655)   1,245    (7,113)Interest expense, net (a)   2,007    1,590    3,516    3,056 Depreciation   678    450    1,242    902 Amortization   5,973    6,092    11,995    11,863 EBITDA   3,058    (4,113)   19,601    (8,008)Share-based compensation (b)   1,499    339    1,836    670 Restructuring charges (c)   —    148    —    251 Professional fees (d)   1,155    184    2,946    260 Unrealized foreign currency loss (e)   19,361    729    19,440    6,633 Realized foreign currency gain (f)   (21,313)   (278)   (20,451)   (304)Change in fair value of contingent consideration (g)   767    —    767    — Other (h)   246    501    (136)   698 Adjusted EBITDA $ 4,773  $ (2,490) $ 24,003  $ 200 Adjusted EBITDA Margin  13%  (22%)  25%  1%

_____________________

(a) Includes the remaining debt issuance costs of $1,422 related to the prior credit agreement that were expensed when the debt was repaid with a portion of our net proceeds from the IPO during the three months ended June 30, 2017.

(b) Represents non-cash compensation charges related to share-based compensation granted to our officers, employees and directors.

(c) Represents severance and other expenses associated with headcount reductions and other cost savings initiated as part of our restructuring initiatives.

(d) Represents costs of professional services incurred in connection with our IPO, refinancings and the evaluation of proposed acquisitions.

(e) Represents unrealized foreign currency translation gains and losses primarily in respect of our indebtedness.

(f) Represents realized foreign currency translation gains and losses with respect to principal and interest payments related to our indebtedness.

(g) Represents the change in the fair value of the earn-out associated with the Repeat Precision, LLC acquisition.

(h) Represents the impact of a research and development subsidy that is included in income tax expense (benefit) in accordance with GAAP, fees incurred in connection with refinancing our credit facilities, arbitration awards, board of directors fees and travel expenses prior to our initial public offering as permitted by the terms of our prior credit agreement and other charges and credits. The board of directors fees and travel expenses were previously reported on a separate line item, however with the repayment of our prior credit facility, we will not be including such fees and travel expenses incurred in periods following our IPO when calculating Adjusted EBITDA.

 

 NCS MULTISTAGE HOLDINGS, INC.
REVENUE BY GEOGRAPHIC AREA
(In thousands)
(Unaudited)               Three Months Ended Six Months Ended  June 30, June 30,  2017 2016 2017 2016United States            Product Sales $ 12,815 $ 2,319 $ 25,128 $ 5,250Services   2,588   1,052   5,350   2,235Total United States   15,403   3,371   30,478   7,485Canada            Product Sales   12,422   5,943   44,612   19,982Services   4,059   1,174   13,541   5,467Total Canada   16,481   7,117   58,153   25,449Other Countries            Product Sales   4,160   485   5,231   727Services   813   308   1,631   727Total Other Countries   4,973   793   6,862   1,454Total            Product Sales   29,397   8,747   74,971   25,959Services   7,460   2,534   20,522   8,429Total $ 36,857 $ 11,281 $ 95,493 $ 34,388CONTACT: Contacts Ryan Hummer Chief Financial Officer (281) 453-2222 IR@ncsmultistage.com
Categories: State

Western Refining Logistics, LP Reports Second Quarter 2017 Results

8 August 2017 - 3:30pm
  • Net income of $18.7 million; EBITDA of $34.8 million, up 9.5% versus Q2 2016
  • Increased quarterly distribution to $0.4675 per unit; 14th consecutive increase since IPO
  • Distributable cash flow of $26.4 million, up 5.0% compared to Q2 2016

SAN ANTONIO, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Western Refining Logistics, LP (NYSE:WNRL) today reported second quarter 2017 net income attributable to limited partners of $18.7 million, or $0.24 per common limited partner unit, which compares to $17.9 million and $0.33, respectively, in the second quarter 2016. Second quarter 2017 EBITDA was $34.8 million and distributable cash flow was $26.4 million; this compares to $31.8 million and $25.1 million, respectively, for the second quarter 2016.

"WNRL had another successful quarter as we saw increases in net income, EBITDA, and distributable cash flow resulting in our 14th consecutive quarter of distribution growth.  These results were driven primarily by increases in crude oil movements in the Delaware Basin and the recent acquisition of the St. Paul Park logistics assets," said Doug Johnson, President of WNRL.  "Our Wholesale fuel business also had a good quarter due to strong margins and we saw strong growth in our crude oil and asphalt trucking volumes in the Delaware."

On July 25, 2017, the board of directors declared a quarterly cash distribution for the second quarter 2017 of $0.4675 per unit, or $1.87 per unit on an annualized basis. This distribution represents a 15% compound annual growth rate since WNRL's October 2013 initial public offering.

Johnson concluded, “We continue to see rig activity and crude oil production growth in the Delaware Basin and believe WNRL is well-positioned to fully leverage its logistics assets.”

About Western Refining Logistics, LP

Western Refining Logistics, LP is a growth-oriented master limited partnership formed to own, operate, develop and acquire terminals, storage tanks, pipelines and other logistics assets related to the terminalling, transportation and storage of crude oil and refined products. Headquartered in El Paso, Texas, Western Refining Logistics, LP's assets include approximately 705 miles of pipelines, approximately 12.4 million barrels of active storage capacity, distribution of wholesale petroleum products and crude oil and asphalt trucking.

More information about Western Refining Logistics, LP is available at www.wnrl.com.

Non-GAAP Financial Measures

In addition to our financial information presented in accordance with U.S. generally accepted accounting principles (GAAP), management utilizes non-GAAP measures to facilitate comparisons of past performance. This press release and supporting schedules include the non-GAAP measures Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) and Distributable Cash Flow. We believe certain investors and financial analysts use EBITDA and Distributable Cash Flow to evaluate WNRL’s financial performance and liquidity between periods and to compare WNRL's performance to certain competitors. We believe certain investors and financial analysts use Distributable Cash Flow to determine the amount of cash available for distribution to our unitholders. These additional financial measures are reconciled from the most directly comparable measures as reported in accordance with GAAP and should be viewed in addition to, and not in lieu of, financial information that we report in accordance with GAAP.

Cautionary Statement on Forward-Looking Statements

This press release contains forward-looking statements. The forward-looking statements reflect WNRL’s current expectation regarding future events, results or outcomes. The forward-looking statements contained herein include statements related to, among other things: the continued growth of Delaware Basin rig activity and crude oil production; WNRL’s ability to increase net income, EBITDA and distributions; increases in crude oil production; WNRL’s ability to fully leverage its logistics assets; and the consideration and discussion of a merger, consolidation or combination of assets held by and securities issued by WNRL with Andeavor Logistics LP, formerly known as Tesoro Logistics LP.  These statements are subject to the general risks inherent in WNRL’s business. These expectations may or may not be realized and some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, WNRL’s business and operations involve numerous risks and uncertainties, many of which are beyond its control, which could result in WNRL’s expectations not being realized, or otherwise materially affect WNRL’s financial condition, results of operations, and cash flows. Additional information relating to the uncertainties affecting WNRL’s business is contained in its filings with the Securities and Exchange Commission to which you are referred. The forward-looking statements are only as of the date made. Except as required by law, WNRL does not undertake any obligation to (and expressly disclaims any obligation to) update any forward-looking statements to reflect events or circumstances after the date such statements were made, or to reflect the occurrence of unanticipated events.

Potential Merger and IDR Buy-In

During the second quarter, Andeavor (NYSE: ANDV), formerly known as Tesoro Corporation, indicated it had authorized management to work with the board of directors and management of Andeavor Logistics (NYSE: ANDX) to consider and begin to negotiate a merger of Andeavor Logistics and WNRL. In addition, Andeavor has indicated it has authorized their management to work with the board of directors and management of Andeavor Logistics to consider changes to the capital structure of Andeavor Logistics with respect to the incentive distribution rights ("IDRs").

Management believes it will be able to complete negotiations and announce the transactions during the third quarter of 2017.

Forward Looking Statements

This communication contains certain statements that are “forward-looking” statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. Words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “predict,” “project,” “future,” “potential,” “intend,” “plan,” “assume,” “believe,” “forecast,” “look,” “build,” “focus,” “create,” “work” “continue” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the proposed acquisition by Andeavor Logistics LP (“ANDX”) of WNRL, synergies and the shareholder value to result from the combined company, and the proposed buy-in of ANDX’s incentive distribution rights by Andeavor (“ANDV”) in exchange for common units of ANDX. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. For example, the negotiation and execution, and the terms and conditions, of definitive agreements relating to the proposed transactions and the ability of ANDX, WNRL and/or ANDV, as applicable, to enter into or consummate such agreements, the risk that the proposed transactions do not occur, expected timing and likelihood of completion of the proposed transactions, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed acquisition that could reduce anticipated benefits or cause the parties to abandon the transactions, the ability to successfully integrate the businesses, the occurrence of any event, change or other circumstances that could cause the parties to abandon the transactions, risks related to disruption of management time from ongoing business operations due to the proposed transactions, the risk that any announcements relating to the proposed transactions could have adverse effects on the market price of ANDX’s common units, WNRL’s common units or ANDV’s common stock, the risk that the proposed transaction and its announcement could have an adverse effect on the ability of ANDX, WNRL and ANDV to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally, the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies, the risk that the combined company may not buy back shares, the risk of the amount of any future dividend ANDX may pay, and other factors. All such factors are difficult to predict and are beyond ANDX’s, WNRL’s or ANDV’s control, including those detailed in ANDX’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on ANDX’s website at http://andeavorlogistics.com/ and on the SEC’s website at http://www.sec.gov, those detailed in WNRL’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on WNRL’s website at http://www.wnrl.com and on the SEC website at http://www.sec.gov, and those detailed in ANDV’s website at http://www.andeavor.com and on the SEC website at http://www.sec.gov. ANDX’s, WNRL’s and ANDV’s forward-looking statements are based on assumptions that ANDX, WNRL and ANDV believe to be reasonable but that may not prove to be accurate. ANDX, WNRL and ANDV undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances that occur, or which we become aware of, except as required by applicable law or regulation. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

No Offer or Solicitation

This communication relates to a proposed business combination between WNRL and ANDX and the proposed transaction between ANDX and ANDV. This communication is for informational purposes only and is neither an offer to purchase, nor a solicitation of an offer to sell, any securities in any jurisdiction pursuant to the proposed transactions or otherwise, nor shall there be any sale, issuance or transfer or securities in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.

Additional Information and Where to Find It

In the event that the parties enter into definitive agreements with respect to the proposed transactions, ANDX and WNRL intend to file a registration statement on Form S-4, containing a consent statement/prospectus (the “S-4”) with the SEC. This communication is not a substitute for the registration statement, definitive consent statement/prospectus or any other documents that ANDX, WNRL or ANDV may file with the SEC or send to unitholders in connection with the proposed transaction. UNITHOLDERS OF ANDX AND WNRL AND SHAREHOLDERS OF ANDV ARE URGED TO READ ALL RELEVANT DOCUMENTS FILED WITH THE SEC, INCLUDING THE FORM S-4 AND THE DEFINITIVE CONSENT STATEMENT/PROSPECTUS INCLUDED THEREIN IF AND WHEN FILED, AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. When available, investors and security holders will be able to obtain copies of these documents, including the consent statement/prospectus, and any other documents that may be filed with the SEC in the event that the parties enter into definitive agreements with respect to the proposed transactions free of charge at the SEC’s website, http://www.sec.gov. Copies of documents filed with the SEC by ANDX will be made available free of charge on ANDX’s website at http://andeavorlogistics.com/ or by contacting ANDX’s Investor Relations Department by phone at 1-800-837-6768. Copies of documents filed with the SEC by WNRL will be made available free of charge on WNRL’s website at http://www.wnrl.com or by contacting WNRL’s Investor Relations Department by phone at 1-800-837-6768. Copies of documents filed with the SEC by ANDV will be made available free of charge on ANDV’s website at http://www.andeavor.com or by contacting ANDV’s Investor Relations Department by phone at 1-800-837-6768.

Results of Operations

The following tables set forth WNRL's summary historical financial and operating data for the periods indicated below:

 Three Months Ended Six Months Ended June 30, June 30, 2017 2016   2017 2016 (Unaudited) (In thousands, except per unit data)Revenues:       Fee based:       Affiliate$67,783  $53,965  $133,260  $105,893 Third-party703  677  1,322  1,367 Sales based:       Affiliate139,770  126,525  264,837  224,054 Third-party419,253  397,435  832,782  715,327 Total revenues627,509  578,602  1,232,201  1,046,641 Operating costs and expenses:       Cost of products sold:       Affiliate137,150  123,870  259,849  219,019 Third-party403,180  380,386  797,780  680,827 Operating and maintenance expenses47,269  42,991  92,116  87,649 Selling, general and administrative expenses8,023  6,007  14,766  11,371 Gain on disposal of assets, net(2,936) (802) (3,227) (901)Depreciation and amortization9,784  9,553  19,516  18,891 Total operating costs and expenses602,470  562,005  1,180,800  1,016,856 Operating income25,039  16,597  51,401  29,785 Other income (expense):       Interest and debt expense(6,576) (6,414) (13,184) (13,466)Other income (expense), net15  14  37  (104)Net income before income taxes18,478  10,197  38,254  16,215 Benefit (provision) for income taxes250  (217) 360  (478)Net income18,728  9,980  38,614  15,737 Less net loss attributable to General Partner—  (7,894) —  (16,144)Net income attributable to limited partners$18,728  $17,874  $38,614  $31,881         Net income per limited partner unit:       Common - basic$0.24  $0.33  $0.52  $0.61 Common - diluted0.24  0.33  0.52  0.61 Subordinated - basic and diluted—  0.36  0.51  0.64         Weighted average limited partner units outstanding:        Common - basic60,962  26,409  53,364  25,429 Common - diluted60,971  26,427  53,372  25,441 Subordinated - basic and diluted—  22,811  7,562  22,811 


 Three Months Ended Six Months Ended June 30, June 30, 2017 2016   2017 2016 (Unaudited) (In thousands)Cash Flow Data       Net cash provided by (used in):       Operating activities$28,311  $28,951  $71,657  $47,964 Investing activities(8,788) (6,874) (13,895) (15,111)Financing activities(32,290) (33,168) (61,883) (59,896)Capital expenditures8,847  7,732  14,317  16,088 Other Data       EBITDA (1)$34,838  $31,830  $70,954  $60,294 Distributable cash flow (1)26,353  25,090  54,428  47,618 Balance Sheet Data (at end of period)       Cash and cash equivalents    $10,531  $17,562 Property, plant and equipment, net    409,370  425,947 Total assets    564,871  588,956 Total liabilities    484,619  466,903 Division equity    —  104,971 Partners' capital    80,252  17,082 Total liabilities, division equity and partners' capital      564,871  588,956 

(1)   We define EBITDA as earnings before interest and debt expense, provision for income taxes and depreciation and amortization. We define Distributable Cash Flow as EBITDA plus the change in deferred revenues, less interest accruals, income taxes paid, maintenance capital expenditures and distributions declared on our TexNew Mex units. The GAAP performance measure most directly comparable to EBITDA is net income. The GAAP liquidity measure most directly comparable to EBITDA and distributable cash flow is net cash provided by operating activities. These non-GAAP financial measures should not be considered alternatives to GAAP net income or net cash provided by operating activities.

EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

  • EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
  • EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt;
  • EBITDA does not reflect changes in, or cash requirements for, our working capital needs; and
  • EBITDA, as we calculate it, may differ from the EBITDA calculations of our affiliates or other companies in our industry, thereby limiting its usefulness as a comparative measure.

EBITDA and Distributable Cash Flow are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:

  • our operating performance and liquidity as compared to those of other companies in the midstream energy industry, without regard to financial methods, historical cost basis or capital structure;
  • the ability of our assets to generate sufficient cash to make distributions to our unitholders;
  • our ability to incur and service debt and fund capital expenditures; and
  • the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Distributable Cash Flow is a standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield. Yield is based on the amount of cash distributions a partnership can pay to a unitholder. Although distributable cash flow is a liquidity measure, it is also presented in this reconciliation compared to net income as supplemental information.

We believe that the presentation of these non-GAAP measures provides useful information to investors in assessing our financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to net income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income attributable to limited partners. These non-GAAP measures may vary from those of other companies. As a result, EBITDA and Distributable Cash Flow as presented herein may not be comparable to similarly titled measures of other companies.

The calculation of EBITDA and Distributable Cash Flow includes the results of operations for the St. Paul Park Logistics Assets subsequent to the St. Paul Park Logistics Transaction for the three and six months ended June 30, 2017. The results of operations and operating cash flows for the St. Paul Park Logistics Assets are excluded from the EBITDA and Distributable Cash Flow calculations for the comparable periods in the prior year because a retrospective adjustment of these performance measures is not a representative measure of performance results or liquidity. The EBITDA and Distributable Cash Flow calculations for the comparable periods in the prior year have not been retrospectively adjusted to include the combined financial results of the St. Paul Park Logistics Assets prior to September 15, 2016.

The following tables reconcile net income attributable to limited partners and net cash provided by operating activities to EBITDA and Distributable Cash Flow for the three and six months ended June 30, 2017 and 2016, respectively.

 Three Months Ended Six Months Ended June 30, June 30, 2017 2016   2017 2016 (Unaudited) (In thousands)Net income attributable to limited partners                    $18,728  $17,874  $38,614  $31,881 Interest and debt expense6,576  6,414  13,184  13,466 Provision (benefit) for income taxes(250) 217  (360) 478 Depreciation and amortization9,784  7,325  19,516  14,469 EBITDA34,838  31,830  70,954  60,294         Change in deferred revenues102  1,446  466  3,678 Interest accruals(6,149) (6,072) (12,281) (12,781)Income taxes paid—  (64) (89) (94)Maintenance capital expenditures(2,438) (2,050) (4,622) (3,479)Distributable cash flow$26,353  $25,090  $54,428  $47,618 


  Three Months Ended   Six Months Ended  June 30, June 30,  2017 2016 2017 2016  (Unaudited)  (In thousands)Net cash provided by operating activities $28,311  $28,951  $71,657  $47,964 Changes in operating assets and liabilities (147) (8,964) (12,566) (12,114)Interest and debt expense 6,576  6,414  13,184  13,466 Unit-based compensation expense (3,097) (788) (3,732) (1,312)Amortization of loan fees (497) (343) (989) (685)Deferred income taxes 1,010  —  522  — Gain on disposal of assets, net 2,936  802  3,227  901 Provision (benefit) for income taxes (250) 217  (360) 478 Reserve for doubtful accounts (4) (125) 11  (126)EBITDA attributable to General Partner (1)         —  5,666  —  11,722 EBITDA 34,838  31,830  70,954  60,294          Change in deferred revenues 102  1,446  466  3,678 Interest accruals (6,149) (6,072) (12,281) (12,781)Income taxes paid —  (64) (89) (94)Maintenance capital expenditures (2,438) (2,050) (4,622) (3,479)Distributable cash flow $26,353  $25,090  $54,428  $47,618 

(1)   The calculation of EBITDA attributable to General Partner is as follows:

  Three Months Ended   Six Months Ended  June 30,  2016  (Unaudited)  (In thousands)Net loss attributable to General Partner $(7,894) $(16,144)Depreciation and amortization 2,228  4,422 EBITDA attributable to General Partner                 $(5,666) $(11,722)

Logistics Segment

 Three Months Ended Six Months Ended June 30, June 30, 2017 2016   2017 2016 (Unaudited) (In thousands, except key operating statistics)Statement of Operations Data:       Fee based revenues:       Affiliate$53,567  $43,053  $103,204  $83,969 Third-party703  677  1,322  1,367 Total revenues54,270  43,730  104,526  85,336 Operating costs and expenses:       Operating and maintenance expenses27,102  23,734  52,930  50,491 General and administrative expenses829  590  1,636  1,371 Gain on disposal of assets, net(53) (5) (43) (5)Depreciation and amortization8,781  8,347  17,362  16,502 Total operating costs and expenses            36,659  32,666  71,885  68,359 Operating income$17,611  $11,064  $32,641  $16,977 Key Operating Statistics:       Pipeline and gathering (bpd):       Mainline movements (1):       Permian/Delaware Basin system62,268  55,953  57,728  52,719 Four Corners system50,780  58,047  49,139  55,257 TexNew Mex system5,831  10,375  5,121  11,460 Gathering (truck offloading):       Permian/Delaware Basin system13,203  17,823  13,900  19,178 Four Corners system7,094  11,133  6,857  11,947 Pipeline gathering and injection system:       Permian/Delaware Basin system13,607  11,302  12,794  9,594 Four Corners system26,832  27,225  25,458  25,831 TexNew Mex system5,988  343  5,664  171 Tank storage capacity (bbls) (2)959,087  845,514  959,087  836,858 Terminalling, transportation and storage:       Shipments into and out of storage (bpd)
(includes asphalt)589,653  393,037  587,078  390,647 Terminal storage capacity (bbls) (2)11,376,599  7,385,543  11,376,666  7,385,543 

(1)   Some barrels of crude oil in route to Western's Gallup refinery and Permian/Delaware Basin are transported on more than one of our mainlines.  Mainline movements for the Four Corners and Delaware Basin systems include each barrel transported on each mainline.

(2)   Storage shell capacities represent weighted-average capacities for the periods indicated.

Wholesale Segment

 Three Months Ended   Six Months Ended June 30, June 30, 2017 2016 2017 2016 (Unaudited) (In thousands, except key operating stats)Statement of Operations Data:       Fee based revenues (1):       Affiliate$14,216  $10,912  $30,056  $21,924 Sales based revenues (1):       Affiliate139,770  126,525  264,837  224,054 Third-party419,253  397,435  832,782  715,327 Total revenues573,239  534,872  1,127,675  961,305 Operating costs and expenses:       Cost of products sold:       Affiliate137,150  123,870  259,849  219,019 Third-party403,180  380,386  797,780  680,827 Operating and maintenance expenses20,167  19,257  39,186  37,158 Selling, general and administrative expenses1,442  2,153  3,736  4,058 Gain on disposal of assets, net(2,883) (797) (3,184) (896)Depreciation and amortization1,003  1,206  2,154  2,389 Total operating costs and expenses560,059  526,075  1,099,521  942,555 Operating income$13,180  $8,797  $28,154  $18,750 Key Operating Statistics:       Fuel gallons sold (in thousands)318,046  311,486  620,096  626,429 Fuel gallons sold to retail (included in fuel gallons    
sold above) (in thousands)85,046  83,721  164,159  163,562 Fuel margin per gallon (2)$0.037  $0.025  $0.040  $0.027 Lubricant gallons sold (in thousands)1,019  1,846  2,340  4,047 Lubricant margin per gallon (3)$0.93  $0.89  $1.02  $0.78 Asphalt trucking volume (bpd)6,953  4,876  6,084  3,875 Crude oil trucking volume (bpd)51,352  42,092  50,130  38,801 Average crude oil revenue per barrel$2.20  $2.17  $2.23  $2.20 

(1)   All wholesale fee based revenues are generated through fees charged to Western's refining segment for truck transportation and delivery of crude oil and asphalt. Affiliate and third-party product sales based revenues result from sales of refined products to Western and third-party customers at a delivered price that includes charges for product transportation.

(2)   Fuel margin per gallon is a measurement calculated by dividing the difference between fuel sales, net of transportation charges, and cost of fuel sales for our wholesale business by the number of gallons sold. Fuel margin per gallon is a measure frequently used in the petroleum products wholesale industry to measure operating results related to fuel sales.

(3)   Lubricant margin per gallon is a measurement calculated by dividing the difference between lubricant sales, net of transportation charges, and lubricant cost of products sold by the number of gallons sold. Lubricant margin is a measure frequently used in the petroleum products wholesale industry to measure operating results related to lubricant sales.

 

CONTACT: Investor and Analyst Contact: Michelle Clemente (602) 286-1533 Media Contact: Gary W. Hanson (602) 286-1777
Categories: State

SemGroup Corporation to Participate in Citi’s One-on-One MLP/Midstream Infrastructure Conference

8 August 2017 - 3:28pm

TULSA, Okla., Aug. 08, 2017 (GLOBE NEWSWIRE) -- SemGroup® Corporation (NYSE:SEMG) is scheduled to attend the 2017 Citi One-on-One MLP/Midstream Infrastructure Conference in Las Vegas on Wednesday, August 16 and Thursday, August 17.

SemGroup President and Chief Executive Officer Carlin Conner and Chief Financial Officer Bob Fitzgerald will participate in one-on-one meetings with members of the investment community. The presentation materials will be accessible the day of the event in the investor relations section of the SemGroup website at www.semgroupcorp.com.

About SemGroup
Based in Tulsa, Okla., SemGroup® Corporation (NYSE:SEMG) is a publicly traded midstream service company providing the energy industry the means to move products from the wellhead to the wholesale marketplace. SemGroup provides diversified services for end-users and consumers of crude oil, natural gas, natural gas liquids, refined products, residual fuel oil and asphalt. Services include purchasing, selling, processing, transporting, terminalling and storing energy.

SemGroup uses its Investor Relations website and social media outlets as channels of distribution of material company information. Such information is routinely posted and accessible on our Investor Relations website at www.semgroupcorp.com, our Twitter account and LinkedIn account.

CONTACT: Investor Relations: Alisa Perkins 918-524-8081 investor.relations@semgroupcorp.com Media: Tom Droege 918-524-8560 tdroege@semgroupcorp.com
Categories: State

Enphase Energy CEO Announces Resignation

8 August 2017 - 3:05pm

PETALUMA, Calif., Aug. 08, 2017 (GLOBE NEWSWIRE) -- Enphase Energy, Inc. (NASDAQ:ENPH), a global energy technology company and the world’s leading supplier of solar microinverters, announced today that after more than ten years at the helm of the Company, Paul Nahi is stepping down as President and CEO.

Nahi’s final day with Enphase is today; however, he will continue to assist Enphase as it transitions to a new leader. The Company’s Board of Directors has begun a search for a replacement that includes both internal and external candidates, with the intention to name a successor by August 31, 2017. In the interim, the Board has created an Office of the CEO, consisting of Bert Garcia, CFO, and Badri Kothandaraman, COO, to oversee and provide leadership for the Company’s day-to-day activities.

“On behalf of the Board, we would like to thank Paul for his exceptional leadership, and his many years of service to Enphase and the solar industry,” said Steve Gomo, lead independent director of Enphase Energy’s Board of Directors. “As the Company’s first and only CEO, Paul has led Enphase from pioneering the world’s first microinverter to becoming a leading global provider of energy management solutions. We appreciate his many contributions and wish him continued success.”

“It has been an enormous privilege to lead Enphase since inception and through its growth to become a leading global energy technology company,” said Paul Nahi. “Our invention of the microinverter and the introduction of module level data monitoring has transformed the global solar energy landscape. Having managed Enphase from a concept through global leadership, I feel the time is right for a new CEO to continue its growth, while Enphase increases market share, expands into new geographies and explores new opportunities. As Enphase continues into its second decade, it is poised for a future of sustained profitability, having successfully embraced the challenges of managing operating expenses while accelerating its investments in next-generation technologies. I remain passionate about Enphase’s bright future, and I am confident its best days are yet to come.”

Forward-Looking Statements

This press release may contain forward-looking statements, including statements related to Enphase Energy's: search for a replacement President and CEO, continued growth prospects; increase in market share; expansion into new geographies; and future of sustained profitability. These forward-looking statements are based on the company's current expectations and inherently involve significant risks and uncertainties. Actual results and the timing of events could differ materially from those anticipated in such forward-looking statements as a result of these risks and uncertainties and other risks detailed in the "Risk Factors" and elsewhere in Enphase Energy's latest Securities and Exchange Commission filings and reports. Enphase Energy undertakes no duty or obligation to update any forward-looking statements contained in this release as a result of new information, future events or changes in its expectations.

About Enphase Energy, Inc.

Enphase Energy, a global energy technology company, delivers smart, easy-to-use solutions that connect solar generation, storage and management on one intelligent platform. The Company revolutionized solar with its microinverter technology and produces the world’s only truly integrated solar plus storage solution. Enphase has shipped approximately 15 million microinverters, and more than 661,000 Enphase systems have been deployed in more than 100 countries. For more information, visit www.enphase.com.

Enphase Energy®, the Enphase logo and other trademarks or service names are the trademarks of Enphase Energy, Inc.

CONTACT: Contact Christina Carrabino Enphase Energy, Inc. Investor Relations ir@enphaseenergy.com +1-707-763-4784 x7294
Categories: State

Enphase Energy Reports Financial Results for the Second Quarter of 2017

8 August 2017 - 3:05pm

PETALUMA, Calif., Aug. 08, 2017 (GLOBE NEWSWIRE) -- Enphase Energy, Inc. (NASDAQ:ENPH), a global energy technology company and the world’s leading supplier of solar microinverters, announced today financial results for the second quarter ended June 30, 2017.

Enphase Energy reported total revenue for the second quarter of 2017 of $74.7 million, an increase of 36 percent compared to the first quarter of 2017.  During the second quarter of 2017, Enphase sold approximately 224MW (DC) or 775,000 microinverters, an increase in MW of 39 percent compared to the first quarter of 2017.  GAAP gross margin for the second quarter of 2017 was 18.1 percent and non-GAAP gross margin was 18.4 percent.

GAAP operating expenses for the second quarter of 2017 were $22.8 million, a decrease of 22 percent compared to the first quarter of 2017 and a decrease of 24 percent compared to the second quarter of 2016. Non-GAAP operating expenses were $17.8 million, a decrease of 12 percent compared to the first quarter of 2017 and a decrease of 35 percent compared to the second quarter of 2016.  GAAP net loss for the second quarter of 2017 was $12.1 million, or a net loss of $0.14 per share, compared to a second quarter of 2016 net loss of $16.7 million, or a net loss of $0.36 per share. On a non-GAAP basis, net loss in the second quarter of 2017 was $6.6 million, or a net loss of $0.08 per share, compared to a second quarter of 2016 net loss of $13.9 million, or a net loss of $0.30 per share.

The Company generated $1.0 million of cash in the second quarter of 2017 and exited the quarter with a total cash balance of $31.0 million.

“The ongoing rollout of our sixth-generation IQ Microinverter System continued to gain traction during the second quarter, and we expect to fully transition our U.S. customer base to the IQ platform by the end of the third quarter of 2017,” said Badri Kothandaraman, COO of Enphase Energy.  “In addition, we are excited by the recent U.S. launch of our Enphase Energized™ AC Modules that directly integrate the IQ Microinverter with the module, creating an even simpler, more consolidated solution.”

“The actions we have taken over the past year to improve our operational efficiency resulted in a 35 percent year-over-year decrease in non-GAAP operating expenses,” said Bert Garcia, CFO of Enphase Energy. “We believe the combination of operating expense reduction, supply chain optimization and the transition to our sixth-generation IQ Microinverter System will enable us to achieve non-GAAP operating income profitability by the fourth quarter of 2017.”

Business Outlook

“We expect our revenue for the third quarter of 2017 to be within a range of $72 million to $80 million,” stated Bert Garcia. “We expect GAAP and non-GAAP gross margin for the third quarter to be within a range of 18 percent to 21 percent. Non-GAAP gross margin excludes approximately $200,000 of stock-based compensation expense.  We expect our GAAP operating expense for the third quarter to be within a range of $22.5 million to $24.5 million and non-GAAP operating expense to be within a range of $16.5 million to $18.5 million, excluding an estimated $1.7 million of stock-based compensation expense and approximately $4.3 million of additional restructuring expense.”

Enphase Energy also announced today that Paul Nahi is stepping down as president and CEO. Nahi’s final day with Enphase is today; however, he will continue to assist Enphase as it transitions to a new leader. The Company’s Board of Directors is conducting an internal and external search for a permanent replacement, with the intention to name a successor by August 31, 2017. In the interim, the Board has created an Office of the CEO, consisting of Bert Garcia, CFO, and Badri Kothandaraman, COO, to oversee and provide leadership for the Company’s day-to day activities. 

Use of Non-GAAP Financial Measures

The Company has presented certain non-GAAP financial measures in this release. Generally, a non-GAAP financial measure is a numerical measure of a company’s performance, financial position, or cash flows that either exclude or include amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles in the United States of America, or GAAP. Reconciliation of each non-GAAP financial measure to the most directly comparable GAAP financial measure can be found in the accompanying tables to this press release. Non-GAAP financial measures presented by the Company include non-GAAP gross profit, gross margin, operating expenses, income (loss) from operations, net loss and net loss per share.

These non-GAAP financial measures do not reflect a comprehensive system of accounting, differ from GAAP measures with the same captions and may differ from non-GAAP financial measures with the same or similar captions that are used by other companies. In addition, these non-GAAP measures have limitations in that they do not reflect all of the amounts associated with the Company’s results of operations as determined in accordance with GAAP. As such, these non-GAAP measures should be considered as a supplement to, and not as a substitute for, or superior to, financial measures calculated in accordance with GAAP. The Company uses these non-GAAP financial measures to analyze its operating performance and future prospects, develop internal budgets and financial goals, and to facilitate period-to-period comparisons. Enphase believes that these non-GAAP financial measures reflect an additional way of viewing aspects of its operations that, when viewed with its GAAP results, provide a more complete understanding of factors and trends affecting its business.

As presented in the “Reconciliation of Non-GAAP Financial Measures” tables in the accompanying press release, each of the non-GAAP financial measures excludes one or more of the following items for purposes of calculating non-GAAP financial measures to facilitate an evaluation of the Company’s current operating performance and a comparison to its past operating performance:

Stock-based compensation expense. The Company excludes stock-based compensation expense from its non-GAAP measures primarily because they are non-cash in nature. Moreover, the impact of this expense is significantly affected by the Company’s stock price at the time of an award over which management has limited to no control.

Acquisition-related net charges (credits). These items include: (1) revaluation of contingent consideration and its income tax effects, which represent accounting adjustments to state contingent consideration liabilities at their estimated fair value, and (2) amortization of acquired intangibles, which consists of customer relationships. These items relate to a specific prior acquisition and are not reflective of the Company’s ongoing financial performance.

Restructuring charges. The Company excludes restructuring charges due to the nature of the expenses being unplanned and arising outside the ordinary course of continuing operations. These costs primarily consist of fees paid for restructuring-related management consulting services, cash-based severance costs related to workforce reduction actions, asset write-downs of property and equipment and lease loss reserves, and other contract termination costs resulting from restructuring initiatives.

Amortization of Debt Issuance Costs. The Company excludes amortization of debt issuance costs because the costs do not represent a cash outflow for the Company except in the period the financing was secured and such amortization expense is not reflective of the Company’s ongoing financial performance.

Conference Call Information

Enphase Energy will host a conference call for analysts and investors to discuss its second quarter 2017 results and third quarter 2017 business outlook today at 4:30 p.m. Eastern Time (1:30 p.m. Pacific Time). Open to the public, investors may access the call by dialing 877-644-1284; participant passcode 53238137.  A live webcast of the conference call, together with accompanying presentation slides, will also be accessible from the “Investor Relations” section of the Company's website at investor.enphase.com. Following the webcast, an archived version will be available on the website for 30 days. In addition, an audio replay of the conference call will be available by calling 855-859-2056; participant pass code 53238137 beginning approximately one hour after the call.

Forward-Looking Statements

This press release contains forward-looking statements, including statements related to Enphase Energy’s: rollout of its sixth- and seventh-generation IQ Microinverter System and transition plans; timing of achieving sustainable profitability; and expected future financial performance. These forward-looking statements are based on the Company’s current expectations and inherently involve significant risks and uncertainties. Enphase Energy’s actual results and the timing of events could differ materially from those anticipated in such forward-looking statements as a result of certain risks and uncertainties including those risks described in more detail in the Company’s most recent Annual Report on Form 10-K and other documents on file with the SEC and available on the SEC’s website at www.sec.gov. Enphase Energy undertakes no duty or obligation to update any forward-looking statements contained in this release as a result of new information, future events or changes in its expectations, except as required by law.

A copy of this press release can be found on the investor relations page of Enphase Energy's website at investor.enphase.com.

About Enphase Energy, Inc.

Enphase Energy, a global energy technology company, delivers smart, easy-to-use solutions that connect solar generation, storage and management on one intelligent platform. The Company revolutionized solar with its microinverter technology and produces the world’s only truly integrated solar plus storage solution. Enphase has shipped approximately 15 million microinverters, and more than 661,000 Enphase systems have been deployed in more than 100 countries. For more information, visit www.enphase.com.

Enphase Energy®, the Enphase logo and other trademarks or service names are the trademarks of Enphase Energy, Inc.

 ENPHASE ENERGY, INC.CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands, except per share data)(Unaudited)  Three Months Ended
June 30,
 Six Months Ended
June 30,
 2017 2016 2017 2016Net revenues$74,704  $79,185  $129,455  $143,306 Cost of revenues61,157  65,049  108,861  117,410 Gross profit13,547  14,136  20,594  25,896 Operating expenses:       Research and development7,947  13,091  17,552  26,157 Sales and marketing6,274  9,987  12,732  20,202 General and administrative4,964  6,846  10,797  14,413 Restructuring charges3,609  —  10,856  — Total operating expenses22,794  29,924  51,937  60,772 Loss from operations(9,247) (15,788) (31,343) (34,876)Other income (expense), net:       Interest expense(2,080) (212) (4,219) (364)Other income (expense)88  (379) 1,148  302 Total other income (expense), net(1,992) (591) (3,071) (62)Loss before income taxes(11,239) (16,379) (34,414) (34,938)Provision for income taxes(854) (344) (984) (580)Net loss$(12,093) $(16,723) $(35,398) $(35,518)Net loss per share:       Basic and diluted$(0.14) $(0.36) $(0.44) $(0.77)Shares used in per share calculation:       Basic and diluted84,434  46,620  80,542  46,415 


ENPHASE ENERGY, INC.CONDENSED CONSOLIDATED BALANCE SHEETS(In thousands)(Unaudited)  June 30,
 2017
 December 31,
 2016
ASSETS   Current assets:   Cash and cash equivalents$30,953  $17,764 Accounts receivable56,403  61,019 Inventory20,839  31,960 Prepaid expenses and other13,307  7,121 Total current assets121,502  117,864 Property and equipment, net29,351  31,440 Goodwill3,664  3,664 Intangibles, net668  945 Other assets8,493  9,663 Total assets$163,678  $163,576 LIABILITIES AND STOCKHOLDERS’ EQUITY   Current liabilities:   Accounts payable$15,425  $31,696 Accrued liabilities33,827  31,533 Deferred revenues8,142  6,411 Borrowings under revolving credit facility—  10,100 Current portion of term loan5,951  3,032 Total current liabilities63,345  82,772 Long-term liabilities:   Deferred revenues, noncurrent35,782  33,893 Warranty obligations, non-current23,581  22,818 Other liabilities1,969  2,025 Term loans, noncurrent41,385  20,768 Total liabilities166,062  162,276 Stockholders’ equity:   Preferred stock—  — Common stock1  1 Additional paid-in capital283,717  252,126 Accumulated deficit(285,933) (250,535)Accumulated other comprehensive income (loss)(169) (292)Total stockholders’ equity(2,384) 1,300 Total liabilities and stockholders’ equity$163,678  $163,576 


ENPHASE ENERGY, INC.CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands)(Unaudited)  Six Months Ended
June 30,
 2017 2016Cash flows from operating activities:   Net loss$(35,398) $(35,518)Adjustments to reconcile net loss to net cash used in operating activities:   Depreciation and amortization4,583  5,388 Provision for doubtful accounts707  1,331 Asset impairment and restructuring1,765  28 Amortization of debt issuance costs1,063  56 Stock-based compensation3,550  5,707 Changes in operating assets and liabilities:   Accounts receivable3,910  (4,205)Inventory11,121  1,505 Prepaid expenses and other assets(5,338) (3,697)Accounts payable, accrued and other liabilities(13,908) 14,857 Deferred revenues3,620  6,557 Net cash used in operating activities(24,325) (7,991)Cash flows from investing activities:   Purchases of property and equipment(3,515) (7,510)Purchases of intangible assets—  (678)Net cash used in investing activities(3,515) (8,188)Cash flows from financing activities:   Proceeds from issuance of common stock, net of issuance costs26,425  — Proceeds from term loan, net24,240  — Proceeds from borrowings under revolving credit facility—  10,000 Payments under revolving credit facility(10,100) (14,550)Payments of deferred financing costs—  (130)Contingent consideration payment related to prior acquisition—  (29)Proceeds from issuance of common stock under employee stock plans170  809 Net cash provided by (used in) financing activities40,735  (3,900)Effect of exchange rate changes on cash294  (130)Net increase (decrease) in cash and cash equivalents13,189  (20,209)Cash and cash equivalents—Beginning of period17,764  28,452 Cash and cash equivalents—End of period$30,953  $8,243 


ENPHASE ENERGY, INC.RECONCILIATION OF NON-GAAP FINANCIAL MEASURES(In thousands, except per share data)(Unaudited)   Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017 2016 2017 2016Gross profit (GAAP) $13,547  $14,136  $20,594  $25,896 Stock-based compensation 211  305  449  612 Gross profit (Non-GAAP) $13,758  $14,441  $21,043  $26,508          Gross margin (GAAP) 18.1% 17.9% 15.9% 18.1%Stock-based compensation 0.3% 0.3% 0.4% 0.4%Gross margin (Non-GAAP) 18.4% 18.2% 16.3% 18.5%         Operating expenses (GAAP) $22,794  $29,924  $51,937  $60,772 Stock-based compensation(1) (1,410) (2,403) (3,101) (5,095)Amortization of acquisition-related intangibles —  (45) —  (90)Restructuring charges (3,609) —  (10,856) — Operating expenses (Non-GAAP) $17,775  $27,476  $37,980  $55,587          (1) Includes stock-based compensation as follows:        Research and development $636  $980  $1,387  $2,106 Sales and marketing 285  588  663  1,200 General and administrative 489  835  1,051  1,789 Total $1,410  $2,403  $3,101  $5,095          Loss from operations (GAAP) $(9,247) $(15,788) $(31,343) $(34,876)Stock-based compensation 1,621  2,708  3,550  5,707 Amortization of acquisition-related intangibles —  45  —  90 Restructuring charges 3,609  —  10,856  — Loss from operations (Non-GAAP) $(4,017) $(13,035) $(16,937) $(29,079)         Net loss (GAAP) $(12,093) $(16,723) $(35,398) $(35,518)Stock-based compensation 1,621  2,708  3,550  5,707 Amortization of acquisition-related intangibles —  45  —  90 Restructuring, asset impairments and other charges 3,609  —  10,856  — Non-cash interest expense 231  28  743  56 Net loss (Non-GAAP) $(6,632) $(13,942) $(20,249) $(29,665)         Net loss per share (GAAP) $(0.14) $(0.36) $(0.44) $(0.77)Stock-based compensation 0.02  0.06  0.04  0.13 Restructuring, asset impairments and other charges 0.04  —  0.14  — Non-cash interest expense —  —  0.01  — Net loss per share (Non-GAAP) $(0.08) $(0.30) $(0.25) $(0.64)         Shares used in per share calculation (Non-GAAP) 84,434  46,620  80,542  46,415 

 

CONTACT: Contact Christina Carrabino Enphase Energy, Inc. Investor Relations ir@enphaseenergy.com +1-707-763-4784 x7294
Categories: State

Rex Energy Reports Second Quarter 2017 Financial and Operational Results

8 August 2017 - 3:01pm
  • New BP Energy Company marketing arrangement enhances C3+ pricing structure and stabilizes cash flows on a quarter-to-quarter basis
  • New marketing arrangement allows Rex to reduce outstanding letters of credit by $14.1 million, creating additional liquidity
  • Sale of water line in Warrior North adds ~$8.0 million of liquidity
  • 2017 and 2018 natural gas hedged basis differentials now expected to be ($0.35) – ($0.45)
  • Twelve Moraine East wells scheduled to be placed into sales in third quarter 2017

                                                                                                                          
STATE COLLEGE, Pa., Aug. 08, 2017 (GLOBE NEWSWIRE) -- Rex Energy Corporation (Nasdaq:REXX) today announced its second quarter 2017 financial and operational results.

Financial Update

Marketing Agreement with BP Energy Company

The company recently entered into a comprehensive marketing arrangement with BP Energy Company, an indirect wholly-owned subsidiary of BP plc (NYSE:BP), pursuant to which BP Energy Company will market the majority of Rex’s liquid C3+ products stream, and provide credit support on behalf of Rex Energy. The arrangement also enhances several of the company’s existing marketing initiatives in the Butler and Warrior North operating areas.

Beginning January 1, 2018, BP Energy Company will purchase the majority of the company’s C3+ products stream for an extended term. The pricing structure compares favorably to actual 2016 and projected 2017 prices. The new pricing structure will help to mitigate the historical fluctuations between summer and winter pricing and stabilize the company’s quarterly cash flows. As part of the new marketing arrangement, Rex Energy has reduced outstanding letters of credit by approximately $14.1 million, immediately increasing liquidity on the company’s $300 million delayed draw term loan facility. Also, as part of the broader marketing initiatives, BP Energy Company will market a portion of Rex Energy’s Warrior North gas at an improved differential to the current Dom South pricing.

“I’m very excited to expand our existing relationship with BP,” said Tom Stabley, Rex Energy’s President and Chief Executive Officer. “The relationship we have developed and grown with BP over the past several years has been a major key to Rex Energy’s success. This is another testament to the confidence placed in the company’s reserves and development capabilities. I look forward to this new, deeper relationship, and to continuing to expand it in the years to come.”

Sale of Salineville Waterline

In July, the company sold its Salineville, OH waterline and related assets to Keystone Clearwater Services (KCS) for a total consideration of approximately $8.0 million. The Salineville waterline provided water for completions in the Warrior North area. In connection with the sale of the waterline, Rex Energy entered into a lease agreement with KCS to secure water services for future completions in the Warrior North area.

Warrior North Area Condensate

Rex Energy has entered into a new term condensate agreement with Marathon Petroleum Corporation pursuant to which the company will receive an improved condensate differential on all of its production in the Warrior North Area beginning September 1, 2017.

Improving Natural Gas Basis Differentials

During the first half of 2017, the company’s realized natural gas prices improved due to tightening differentials in the northeast markets and the full realization of its Gulf Coast transport contracts. The unhedged realized natural gas price for the first half of 2017 was $2.94 and the natural gas basis differential was ($0.24) off of NYMEX.  As a result, the company expects its full-year 2017 natural gas basis differential, including the effects of basis hedging, to improve to ($0.35) – ($0.45) off of NYMEX as compared to the previous estimate of ($0.58) – ($0.68) off of NYMEX.

Second Quarter Financial Results

Operating revenue from continuing operations for the three and six months ended June 30, 2017 was $47.5 million and $99.5 million, respectively, which represents an increase of 52% and 75% over the same periods in 2016. Commodity revenues, including settlements from derivatives, for the three and six months ended June 30, 2017 were $45.4 million and $94.0 million, respectively, a decrease of 7% and an increase of 7% from the same periods in 2016. Commodity revenues from natural gas liquids (NGLs) and condensate, including settlements from derivatives, represented 39% of total commodity revenues for the three months ended June 30, 2017.

Lease operating expense (LOE) from continuing operations was $29.4 million, or $1.82 per Mcfe for the quarter. For the six months ended June 30, 2017, LOE was approximately $58.3 million, or $1.84 per Mcfe. General and administrative (G&A) expenses from continuing operations were $4.3 million for the second quarter of 2017, or $0.27 per Mcfe. For the six months ended June 30, 2017, G&A expenses from continuing operations were $8.8 million, or $0.28 per Mcfe. Cash G&A expenses from continuing operations (a non-GAAP measure) for the three months ended June 30, 2017 were $3.8 million, or $0.23 per Mcfe, a 16% increase on a per unit basis as compared to the same period in 2016. For the six months ended June 30, 2017, cash G&A expenses from continuing operations (a non-GAAP measure) were $8.3 million, or $0.26 per Mcfe, consistent on a per unit basis when compared to the same period in 2016.

Net loss attributable to common shareholders for the three months ended June 30, 2017 was $10.2 million, or $1.03 per basic share. Net loss attributable to common shareholders for the six months ended June 30, 2017 was $8.1 million, or $0.83 per basic share. Adjusted net loss, a non-GAAP measure, for the three months ended June 30, 2017 was $9.2 million, or $0.93 per share. Adjusted net loss for the six months ended June 30, 2017 was $14.7 million, or $1.50 per share.

EBITDAX from continuing operations, a non-GAAP measure, was $12.4 million for the second quarter of 2017 and $28.0 million for the six months ended June 30, 2017.

Reconciliations of adjusted net loss to GAAP net loss, EBITDAX to GAAP net loss and G&A to cash G&A for the three and six months ended June 30, 2017, as well as a discussion of the uses of each measure, are presented in the appendix of this release.

Production Results and Price Realizations

Second quarter 2017 production volumes from continuing operations were 177.1 MMcfe/d, consisting of 108.7 MMcf/d of natural gas, 4.8 Mbbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 0.8 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 39% of net production for the second quarter of 2017. Second quarter production was constrained during the quarter due to unplanned maintenance downtime in the company’s midstream services. The unplanned maintenance downtime adversely effected production during the second quarter by approximately 3.5 MMcfe/d.

Including the effects of cash-settled derivatives, realized prices for the three months ended June 30, 2017 were $2.78 per Mcf for natural gas, $21.62 per barrel for C3+ NGLs, $9.93 per barrel for ethane and $44.35 per barrel for condensate. Before the effects of hedging, realized prices for the three months ended June 30, 2017 were $2.94 per Mcf for natural gas, $23.03 per barrel for C3+ NGLs, $9.96 per barrel for ethane and $42.35 per barrel for condensate.

Including the effects of cash-settled derivatives, realized prices for the six months ended June 30, 2017 were $2.91 per Mcf for natural gas, $23.37 per barrel for C3+ NGLs, $9.84 per barrel for ethane and $45.26 per barrel for condensate. Before the effects of hedging, realized prices for the six months ended June 30, 2017 were $3.05 per Mcf for natural gas, $26.86 per barrel for C3+ NGLs, $9.74 per barrel for ethane and $44.25 per barrel for condensate.

Second Quarter 2017 Capital Investments

For the second quarter of 2017, net operational capital investments were approximately $29.1 million. The company expects to be reimbursed by joint development partners for approximately $13.4 million of previously incurred costs that were not billed until the third quarter of 2017. Capital investments in the second quarter of 2017 funded the drilling of six gross (4.8 net) wells, fracture stimulation of six gross (3.1 net) wells and other projects related to drilling and completing wells in the Appalachian Basin. Net operated capital expenditures for the full-year 2017 are still expected to be within the range of the company’s previously issued guidance of $115.0 million - $130.0 million.

Operational Update

Moraine East Area

In the Moraine East Area, the company drilled two gross (two net) wells, completed six gross (3.1 net) wells and placed into sales four gross (1.4 net) wells in the second quarter of 2017. In addition, the company had nine gross (4.9) net wells awaiting completion at the end of the second quarter.

The company has begun initial sales from its six-well Shields pad. The six wells were drilled to an average lateral length of approximately 8,800 feet and completed in an average of 49 stages. In addition, the company has completed two of the Shields wells with engineered spacing designs as compared to its standard spacing design. The company expects to provide an update on the performance of the pad in the coming weeks.

The company recently finished completing the four wells on the Mackrell pad, which were drilled to an average lateral length of 7,630 feet. The wells are expected to be placed into sales in early September 2017 as scheduled. Lastly, the company recently finished drilling the two-wells on the Frye pad, which were drilled to an average lateral length of approximately 6,300 feet. The two-well Frye pad is currently being completed and is expected to be placed into sales in the third quarter of 2017.

The twelve wells discussed above are all on the eastern side of the Moraine East Area and will be the final delineation of the field.  The company now expects to place additional compression for the Moraine East Area into service in early January 2018, a delay compared to previous estimates of early fourth quarter service, which, in turn, will defer peak production from the area until January 2018.

Legacy Butler Operated Area

In the Legacy Butler Operated Area, the company has begun completing the four-well Wilson pad. The four wells were drilled to an average lateral length of approximately 9,300 feet and are expected to be placed into sales in the fourth quarter of 2017.

Warrior North Area

In the Warrior North Area, the company has finished drilling the three-well Jenkins pad. The three wells were drilled to an average lateral length of approximately 6,500 feet and in an average of 13.2 drilling days, the best average the company has achieved in the Warrior North Area. The three wells are expected to be completed at the end of the fourth quarter of 2017.

Third Quarter and Full Year 2017 Guidance

Rex Energy is providing guidance for the third quarter of 2017 and adjusted full-year 2017. Full-year 2017 production guidance has been reduced to 180.0 – 190.0 MMcfe/d due to midstream restrictions and delays in placing the Vaughn and Baird pads into sales in the first half of 2017. The company still expects to achieve its year-end 2017 exit rate production growth rate guidance of 15% - 20% upon the commissioning of its fourth compressor in the Moraine East Area, which is scheduled for January 5, 2018. This will allow the company to remain on target to meet its full-year 2018 production guidance of 255.0 – 265.0 MMcfe/d.  

 3Q2017Full Year 2017Production171.0 – 181.0 MMcfe/d 180.0 – 190.0 MMcfe/d LOE ($/Mcfe)$1.80 - $1.90$1.70 - $1.80Cash G&A ($/Mcfe)$0.22 - $0.27$0.20 - $0.25Operational Capital Expenditures(1) --$115.0 - $125.0 MMcfe/d(1) Land acquisition expense and capitalized interest are not included in the operational capital expenditures budget

Conference Call Information
Management will host a live conference call and webcast on Wednesday, August 9, 2017 at 10:00 a.m. Eastern to review second quarter 2017 financial results and operational highlights. The telephone number to access the conference call is (866) 437-1772.

About Rex Energy Corporation

Headquartered in State College, Pennsylvania, Rex Energy is an independent oil and gas exploration and production company with its core operations in the Appalachian Basin. The company’s strategy is to pursue its higher potential exploration drilling prospects while acquiring oil and natural gas properties complementary to its portfolio.

Forward-Looking Statements

Except for historical information, all statements made in this release, including those relating to the timing and nature of development plans; drilling and completion schedules; anticipated fracture stimulation activities; expected dates for placement of wells into sales; and our financial guidance for third quarter and full year 2017 are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may contain words such as "expected", "expects", "scheduled", "planned", "plans", "anticipates" or similar words, and are based on management's experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):

  • economic conditions in the United States and globally;
  • domestic and global demand for oil, NGLs and natural gas;
  • volatility in oil, NGL, and natural gas pricing;
  • conditions in the domestic and global capital and credit markets and their effect on us;
  • the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity;
  • the success of our business, operational,  financial, and hedging strategies;
  • new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations;
  • the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
  • uncertainties inherent in the estimates of our oil and natural gas reserves;
  • our ability to increase oil and natural gas production and income through exploration and development;
  • drilling and operating risks;
  • the success of our drilling and completion techniques in unconventional reservoirs;
  • the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled;
  • the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;
  • the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;
  • the effects of adverse weather or other natural disasters on our operations;
  • competition in the oil and gas industry in general, and specifically in our areas of operations;
  • changes in our drilling plans and related budgets;
  • the success of prospect development and property acquisition; and
  • uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on the company's risks and uncertainties is available in our filings with the Securities and Exchange Commission and we strongly encourage investors to review those filings.



REX ENERGY CORPORATIONCONSOLIDATED BALANCE SHEETS($ in Thousands, Except Share and Per Share Data)    ASSETSJune 30, 2017
(Unaudited) December 31, 2016Current Assets   Cash and Cash Equivalents$12,855  $3,697 Accounts Receivable23,762  25,448 Taxes Receivable48  211 Short-Term Derivative Instruments7,317  1,873 Inventory, Prepaid Expenses and Other2,002  2,546 Total Current Assets45,984  33,775 Property and Equipment (Successful Efforts Method)   Evaluated Oil and Gas Properties977,665  1,053,461 Unevaluated Oil and Gas Properties205,691  215,794 Other Property and Equipment22,309  21,401 Wells and Facilities in Progress59,807  21,964 Pipelines21,289  18,029 Total Property and Equipment1,286,761  1,330,649 Less: Accumulated Depreciation , Depletion and Amortization(434,483) (475,205)Net Property and Equipment852,278  855,444 Other Assets2,488  2,492 Long-Term Derivative Instruments4,820  2,212 Total Assets$905,570  $893,923 LIABILITIES AND EQUITY   Current Liabilities   Accounts Payable$46,235  $40,712 Current Maturities of Long-Term Debt834  764 Accrued Liabilities32,791  37,207 Short-Term Derivative Instruments6,563  25,025 Total Current Liabilities86,423  103,708 Long-Term Derivative Instruments9,450  7,227 Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs--  113,785 Term Loans, Net136,163  -- Senior Notes, Net648,820  638,161 Other Long-Term Debt3,627  3,409 Other Deposits and Liabilities7,731  8,671 Future Abandonment Cost9,658  8,736 Total Liabilities$901,872  $883,697     Stockholder Equity   Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on June 30, 2017 and December 31, 2016$1  $1 Common Stock, $.001 par value per share, 100,000,000 shares authorized and 9,952,861 shares issued and outstanding on June 30, 2017 and 9,787,146 shares issued and outstanding on December 31, 201610  10 Additional Paid-In Capital651,659  650,669 Accumulated Deficit(647,972) (640,454)Total Stockholders’ Equity3,698  10,226 Total Liabilities and Owners’ Equity$905,570  $893,923 




REX ENERGY CORPORATIONCONSOLIDATED STATEMENTS OF OPERATIONS(Unaudited, in Thousands, Except per Share Data)     For the Three Months Ended June 30, For the Six Months Ended
June 30, 2017  2016  2017  2016 OPERATING REVENUE         Natural Gas, NGL and Condensate Sales$47,457  $31,271  $99,522  $56,944   Other Operating Revenue5  (6) 11  7   TOTAL OPERATING REVENUE47,462  31,265  99,533  56,951 OPERATING EXPENSES         Production and Lease Operating Expense29,374  25,221  58,308  49,672   General and Administrative Expense4,294  4,837  8,828  10,121   Gain on Disposal of Assets(124) (4,307) (1,959) (4,295)  Impairment Expense3,032  25,139  4,577  35,780   Exploration Expense99  803  319  1,738   Depreciation, Depletion, Amortization and Accretion15,501  14,750  30,969  31,262   Other Operating Expense(98) 704  (118) 1,030   TOTAL OPERATING EXPENSES52,078  67,147  100,924  125,308   LOSS FROM OPERATIONS(4,616) (35,882) (1,391) (68,357)OTHER EXPENSE (EXPENSE)         Interest Expense(12,122) (11,439) (21,266) (24,469)  Gain (Loss) on Derivatives, Net10,386  (29,169) 18,766  (25,120)  Other Income20  12  (7) 12   Debt Exchange Expense--  (533) --  (9,014)  Gain on Extinguishment of Debt(3,271) 23,707  (3,022) 23,707   TOTAL OTHER INCOME (EXPENSE)(4,987) (17,422) (5,529) (34,884)LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX(9,603) (53,304) (6,920) (103,241)  Income Tax Benefit--  393  --  (2,321)NET LOSS FROM CONTINUING OPERATIONS(9,603) (52,911) (6,920) (105,562)Loss From Discontinued Operations, Net of Income Taxes--  (1,683) --  (9,173)NET LOSS(9,603) (54,594) (6,920) (114,735)Preferred Stock Dividends(598) (1,723) (1,196) (3,828)Effect of Preferred Stock Conversion--  72,316  --  72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS$(10,201) $15,999  $(8,116) $(46,247)Earnings per common share:         Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders$(1.03) $2.45  $(0.83) $(5.79)  Basic – Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders--  (0.23) --  (1.43)  Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders$(1.0\3) $2.22  $(0.83) $(7.22)  Basic – Weighted Average Shares of Common Stock Outstanding9,881  7,180  9,825  6,404   Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders$(1.03) $2.45  $(0.83) $(5.79)  Diluted – Net Loss From Discontinued Operations Attributable to Rex Energy  Common Shareholders--  (0.23) --  (1.43)  Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders$(1.03) $2.22  $(0.83) $(7.22)  Diluted – Weighted Average Shares of Common Stock Outstanding9,881  7,180  9,825  6,404 




REX ENERGY CORPORATIONCONSOLIDATED OPERATIONAL HIGHLIGHTS       Three Months Ending Six Months Ending  June 30, June 30,  2017  2016 2017  2016Oil, Natural Gas, NGL and Ethane sales (in thousands):              Natural gas sales $29,097  $16,044 $60,442  $31,560  Condensate sales  2,993   3,369  6,414   4,902  Natural gas liquids (C3+) sales  10,119   7,867  23,127   13,843  Ethane sales  5,247   3,991  9,540   6,639  Cash-settled derivatives:              Natural gas  (1,594)  14,857  (2,766)  23,080  Condensate  141   310  146   2,098  Natural gas liquids (C3+)  (616)  2,255  (3,001)  5,211  Ethane  (12)  --  96   144Total oil, gas, NGL and Ethane sales including cash settled derivatives $45,375  $48,693 $93,998  $87,477             Production during the period:              Natural gas (Mcf)  9,889,888   11,327,101  19,801,630   22,631,620  Condensate (Bbls)  70,687   90,565  144,927   153,628  Natural gas liquids (C3+) (Bbls)  439,441   507,990  861,146   997,744  Ethane (Bbls)  526,893   532,928  979,580   971,140  Total (Mcfe)1  16,112,014   18,115,999  31,715,548   35,366,692             Production – average per day:              Natural gas (Mcf)  108,680   124,474  109,401   124,350  Condensate (Bbls)  777   995  801   844  Natural gas liquids (C3+) (Bbls)  4,829   5,582  4,758   5,482  Ethane (Bbls)  5,790   5,856  5,412   5,336  Total (Mcfe)1  177,055   199,077  175,224   194,322             Average price per unit:            Realized natural gas price per Mcf – as reported $2.94  $1.42 $3.05  $1.39Realized impact from cash settled derivatives per Mcf  (0.16)  1.31  (0.14)  1.02Net realized price per Mcf $2.78  $2.73 $2.91  $2.41             Realized condensate price per Bbl – as reported $42.35  $37.20 $44.25  $31.91Realized impact from cash settled derivatives per Bbl2  2.00   3.42  1.01   13.66Net realized price per Bbl $44.35  $40.62 $45.26  $45.57             Realized natural gas liquids (C3+) price per Bbl – as reported $23.03  $15.49 $26.86  $13.87Realized impact from cash settled derivatives per Bbl  (1.41)  4.44  (3.49)  5.23Net realized price per Bbl $21.62  $19.93 $23.37  $19.10             Realized ethane price per Bbl – as reported $9.96  $7.49 $9.74  $6.84Realized impact from cash settled derivatives per Bbl  0.03   --  0.10   0.14Net realized price per Bbl $9.93  $7.49 $9.84  $6.98             LOE/Mcfe $1.82  $1.39 $1.84  $1.40Cash G&A/Mcfe $0.24  $0.20 $0.26  $0.261 Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.2 Includes the effect of derivatives not classified as discontinued operations. When including the effect of Illinois Basin production, derivatives realized increased prices by 1.15/bbl and $6.73/bbl for the three and six month periods ended June 30, 2017 and 2016.  



REX ENERGY CORPORATION COMMODITY DERIVATIVES – HEDGE POSITION AS OF 8/8/2017     2017  2018 Oil Derivatives (Bbls)    Swap Contracts    Volume 25,000  60,000 Price$54.00 $54.00 Collar Contracts    Volume --  18,000 Ceiling$-- $60.00 Floor$-- $53.00 Collar Contracts with Short Puts    Volume 65,000  66,000 Ceiling$61.35 $61.55 Floor$49.23 $51.59 Short Put$39.62 $42.50 Natural Gas Derivatives (Mcf)    Swap Contracts    Volume 6,330,000  15,335,000 Price$3.03 $3.10 Swaption Contracts    Volume 1,000,000  -- Price$3.33 $-- Put Spreads    Volume --  -- Floor$-- $-- Short Put$-- $-- Collar Contracts    Volume 900,000  450,000 Ceiling$3.32 $3.65 Floor$2.72 $3.20 Collar Contracts with Short Puts    Volume 7,170,000  8,775,000 Ceiling$3.87 $3.58 Floor$2.98 $2.89 Short Put$2.29 $2.30 Call Contracts    Volume 3,505,220  16,489,900 Ceiling$4.51 $4.64  Natural Gas Liquids (Bbls)    Swap Contracts    Propane (C3)    Volume 405,000  630,000 Price$23.30 $25.62 Butane (C4)    Volume 100,000  186,000 Price$28.54 $32.94 Isobutane (IC4)    Volume 53,000  102,000 Price$29.55 $33.62 Natural Gasoline (C5+)    Volume 140,000  207,072 Price$48.43 $49.42 Ethane    Volume 375,000  750,000 Price$10.58 $13.02 Natural Gas Basis (Mcf)    Swap Contracts    Dominion Appalachia    Volume 7,471,000  18,980,000 Price$(0.78)$(0.81)Texas Gas Zone 1    Volume 6,120,000  14,600,000 Price$(0.13)$(0.13)NYMEX Heating Oil (Gal)    Swap Contracts    Volume --  -- Price$-- $-- 

APPENDIX  
REX ENERGY CORPORATION
NON-GAAP MEASURES

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, non-recurring gains and losses, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives and gains on asset dispositions, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

  • Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;
  • The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;
  • Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and
  • The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented.

  Three Months Ended
June 30,
 Six Months Ended
June 30,  2017  2016  2017  2016 Net Loss From Continuing Operations $(9,603) $(52,911) $(6,920) $(105,562)  Add Back Non-Recurring Costs1 3,349  (23,174) 3,459  (14,694)  Add Back Depletion, Depreciation, Amortization and Accretion 15,501  14,750  30,969  31,262   Add Back Non-Cash Compensation Expense 511  1,164  571  1,016   Add Back Interest Expense 12,123  11,439  21,271  24,469   Add Back Impairment Expense 3,032  25,139  4,577  35,780   Add Back Exploration Expenses 99  803  319  1,738   Less Gain on Disposal of Assets (124) (4,307) (1,959) (4,295)  Less (Gain) Loss on Financial Derivatives (10,386) 29,169  (18,766) 25,120   Add Back (Less) Cash Settlement of Derivatives (2,082) 17,345  (5,525) 30,340   Less Income Tax Benefit --  (393) --  2,321 EBITDAX From Continuing Operations $12,420  $19,024 $27,996 $27,495 Net Loss From Discontinued Operations $--  $(1,683)$-- $(9,173)  Add Back Depletion, Depreciation, Amortization and Accretion --  2,186  --  5,083   Add Back Non-Cash Compensation Expense --  139  --  259   Add Back Interest Expense --  1  --  3   Add Back Impairment Expense --  --  --  3,543   Add Back Exploration Expense --  85  --  143   Less Gain on Disposal of Assets --  (2) --  (43)  Add Back (Less) Income Tax Expense (Benefit) --  120  --  (502)  Add EBITDAX From Discontinued Operations $--  $846  $--  $(687)EBITDAX (Non-GAAP) $12,420  $19,870  $27,996  $26,808  1 For the three and six months ended June 30, 2017, includes a net $0.1 million of advisory services related to joint venture drilling programs, and $3.3 million in loss on extinguishment of debt. For the six months ended June 30, 2017, includes a net $0.4 million of advisory services related to joint venture drilling programs, and $3.0 million in loss on the extinguishment of debt. For the three months ended June 30, 2016, includes approximately $23.7 million in gains on extinguishment of debt and $0.5 million in debt exchange expenses. For the six months ended June 30, 2016, includes approximately $23.7 million in gain on extinguishment of debt and $9.0 million in debt exchange expenses. 

Adjusted Net Loss

“Adjusted Net Loss” means, for any period, the sum of net income (loss) from continuing operations before income taxes for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Loss is used as a financial measure by Rex Energy's management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Loss is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company's performance.

Rex Energy reports Adjusted Net Loss because it believes that this measure is commonly reported and widely used by investors as an indicator of a company's operating performance. You should carefully consider the specific items included in the company's computation of this measure. You are cautioned that Adjusted Net Income as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.

The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net loss for each of the periods presented ($ in thousands):

 For the Three Months Ended For the Six Months Ended June 30, June 30,  2017  2016   2017  2016 Loss From Continuing Operations Before Income Taxes, as reported$(9,603)$(53,304) $(6,920)$(103,241)    (Gain) Loss on Derivatives, Net (10,386) 29,169   (18,766) 25,120     Cash Settlement of Derivatives (2,082) 17,345   (5,525) 30,340   Add Back (Gain) Loss from Financial Derivatives (12,,468) 46,514   (24,291) 55,460   Add Back Non-Recurring Costs1 3,349  (23,174)  3,459  (14,694)  Add Back Impairment Expense 3,032  25,139   4,577  35,780   Add Back Dry Hole Expense 2  2   13  845   Add Back Non-Cash Compensation Expense 511  1,164   571  1,016 Less Gain on Disposal of Assets (124) (4,307)  (1,959) (4,295)  Loss From Continuing Operations Before Income Taxes, adjusted$(15,301)$(7,966) $(24,550)$(29,129)  Less Income Tax Benefit, adjusted2 6,120  3,186   9,820  11,652 Adjusted Net Loss From Continuing Operations$(9,181)$(4,780) $(14,730)$(17,477)          Basic – Adjusted Net Loss Per Share$(0.93)$(0.67) $(1.50)$(2.72)Basic – Weighted Average Shares of Common Stock Outstanding 9,881  7,180   9,825  6,404 1 For the three and nine months ended June 30, 2017, includes a net $0.1 million of advisory services related to joint venture drilling programs, and $3.3 million in loss on extinguishment of debt. For the six months ended June 30, 2017, includes a net $0.4 million of advisory services related to joint venture drilling programs, and $3.0 million in loss on the extinguishment of debt. For the three months ended June 30, 2016, includes approximately $23.7 million in gains on extinguishment of debt and $0.5 million in debt exchange expenses. For the six months ended June 30, 2016, includes approximately $23.7 million in gain on extinguishment of debt and $9.0 million in debt exchange expenses.2 Assumes an effective tax rate of 40%

Cash General and Administrative Expenses

Cash General and Administrative Expenses (Cash G&A) is the difference between GAAP G&A and non-Cash G&A, which is primarily comprised of non-cash compensation expense. Rex Energy has reported Cash G&A because it believes that this measure is commonly reported and widely used by management and investors as an indicator of overhead efficiency without regard to non-cash expenditures, such as stock compensation. Cash G&A is not a calculation based on GAAP financial measures and should not be considered as an alternative to GAAP G&A in measuring the company’s performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Cash G&A as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both Cash G&A and GAAP G&A. The following table presents a reconciliation of Rex Energy’s GAAP G&A to its Cash G&A for each of the periods presented (in thousands):

 Three Months Ended
June 30, Six Months Ended
June 30, 2017 2016 2017 2016GAAP G&A$4,294 $4,837 $8,828 $10,121Non-Cash Compensation Expense514 1,164 574 1,016Cash G&A$3,780 $3,673 $8,254 $9,105

 

CONTACT: For more information contact: Investor Relations (814) 278-7130 InvestorRelations@rexenergycorp.com
Categories: State

Gulfport Energy Corporation Reports Second Quarter 2017 Results

8 August 2017 - 3:01pm

OKLAHOMA CITY, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Gulfport Energy Corporation (NASDAQ:GPOR) (“Gulfport” or the “Company”) today reported financial and operational results for the quarter ended June 30, 2017 and provided an update on its 2017 activities.  Key information for the second quarter of 2017 includes the following:

  • Net production averaged 1,038.4 MMcfe per day, a 22% increase over the first quarter of 2017 and a 56% increase versus the second quarter of 2016.
  • Net income of $105.9 million, or $0.58 per diluted share.
  • Adjusted net income (as defined and reconciled below) of $60.4 million, or $0.33 per diluted share.
  • Adjusted EBITDA (as defined and reconciled below) of $167.3 million.
  • Reduced unit lease operating expense for the second quarter of 2017 by 13% to $0.22 per Mcfe from $0.25 per Mcfe for the first quarter of 2017.
  • Reduced unit general and administrative expense for the second quarter of 2017 by 21% to $0.13 per Mcfe from $0.16 per Mcfe for the first quarter of 2017.
  • Increased 2017 full-year production guidance and now forecast 2017 average daily net production will be in the range of 1,065 MMcfe to 1,100 MMcfe per day.
  • Reiterate budgeted 2017 total capital expenditures of $1.0 billion to $1.1 billion.
  • Recently spud both a Springer and Sycamore location in the SCOOP.
  • Increased hedge position to approximately 629 MMcf per day of natural gas fixed price swaps during 2017 at an average fixed price of $3.19 per Mcf and a large base level of 775 MMcf per day of natural gas fixed price swaps during 2018 at an average fixed price of $3.06 per Mcf.

Second Quarter Financial Results
For the second quarter of 2017, Gulfport reported net income of $105.9 million, or $0.58 per diluted share, on revenues of $324.0 million.  For the second quarter of 2017, EBITDA (as defined and reconciled below for each period presented) was $212.8 million and cash flow from operating activities before changes in operating assets and liabilities (as defined and reconciled below for each period presented) was $145.0 million.  Gulfport’s GAAP net income for the second quarter of 2017 includes the following items: 

  • Aggregate non-cash derivative gain of $59.9 million.
  • Aggregate expense of $1.1 million in connection with the acquisition of oil and natural gas assets from Vitruvian.
  • Aggregate loss of $13.3 million in connection with Gulfport's equity interests in certain equity investments.

Excluding the effect of these items, Gulfport’s financial results for the second quarter of 2017 would have been as follows:

  • Adjusted oil and gas revenues of $264.1 million.
  • Adjusted net income of $60.4 million, or $0.33 per diluted share.
  • Adjusted EBITDA of $167.3 million.

Year-To-Date 2017 Financial Results
For the six-month period ended June 30, 2017, Gulfport reported net income of $260.4 million, or $1.47 per diluted share, on revenues of $657.0 million.  For the six-month period ended June 30, 2017, EBITDA was $457.0 million and cash flow from operating activities before changes in operating assets and liabilities was $266.7 million.  Gulfport's GAAP net income for the six-month period ended June 30, 2017 includes the following items:

  • Aggregate non-cash derivative gain of $166.7 million.
  • Aggregate expense of $2.4 million in connection with the acquisition of oil and natural gas assets from Vitruvian.
  • Aggregate loss of $18.2 million in connection with Gulfport's equity interests in certain equity investments.

Excluding the effect of these items, Gulfport’s financial results for the six-month period ended June 30, 2017 would have been as follows:

  • Adjusted oil and gas revenues of $490.3 million.
  • Adjusted net income of $114.3 million, or $0.65 per diluted share.
  • Adjusted EBITDA of $310.9 million.

Production and Realized Prices
Gulfport’s net daily production for the second quarter of 2017 averaged approximately 1,038.4 MMcfe per day. For the second quarter of 2017, Gulfport’s net daily production mix was comprised of approximately 88% natural gas, 8% natural gas liquids ("NGL") and 4% oil.

Gulfport’s realized prices for the second quarter of 2017 were $3.16 per Mcf of natural gas, $57.86 per barrel of oil and $0.45 per gallon of NGL, resulting in a total equivalent price of $3.43 per Mcfe. Gulfport's realized prices for the second quarter of 2017 include an aggregate non-cash derivative gain of $59.9 million. Before the impact of derivatives, realized prices for the second quarter of 2017, including transportation costs, were $2.48 per Mcf of natural gas, $45.33 per barrel of oil and $0.45 per gallon of NGL, for a total equivalent price of $2.74 per Mcfe.


GULFPORT ENERGY CORPORATIONPRODUCTION SCHEDULE(Unaudited) Three months ended Six Months Ended June 30, June 30,Production Volumes:2017 2016 2017 2016        Natural gas (MMcf)82,903  52,775  149,187  106,082 Oil (MBbls)650  551  1,164  1,153 NGL (MGal)53,808  30,853  103,475  73,380 Gas equivalent (MMcfe)94,490  60,492  170,951  123,485 Gas equivalent (Mcfe per day)1,038,351  664,743  944,481  678,487         Average Realized Prices:       (before the impact of derivatives):               Natural gas (per Mcf)$2.48  $1.44  $2.57  $1.41 Oil (per Bbl)$45.33  $42.00  $46.30  $33.82 NGL (per Gal)$0.45  $0.33  $0.54  $0.27 Gas equivalent (per Mcfe)$2.74  $1.81  $2.88  $1.69         Average Realized Prices:       (including cash-settlement of derivatives and excluding non-cash derivative gain or loss):                        Natural gas (per Mcf)$2.51  $2.53  $2.54  $2.51 Oil (per Bbl)$48.91  $48.49  $48.37  $42.42 NGL (per Gal)$0.45  $0.33  $0.54  $0.27 Gas equivalent (per Mcfe)$2.79  $2.82  $2.87  $2.71         Average Realized Prices:               Natural gas (per Mcf)$3.16  $(1.10) $3.53  $0.69 Oil (per Bbl)$57.86  $37.23  $62.67  $32.65 NGL (per Gal)$0.45  $0.30  $0.56  $0.24 Gas equivalent (per Mcfe)$3.43  $(0.47) $3.84  $1.04         

The table below summarizes Gulfport’s second quarter of 2017 production by asset area:

GULFPORT ENERGY CORPORATIONPRODUCTION BY AREA(Unaudited) Three months ended   Six Months Ended June 30, June 30, 2017 2017Utica Shale   Natural gas (MMcf)72,649  133,801 Oil (MBbls)122  253 NGL (MGal)32,372  71,683 Gas equivalent (MMcfe)78,003  145,562     SCOOP(1)   Natural gas (MMcf)10,233  15,348 Oil (MBbls)244  378 NGL (MGal)21,343  31,665 Gas equivalent (MMcfe)14,744      22,142     Southern Louisiana                     Natural gas (MMcf)13  22 Oil (MBbls)273  507 NGL (MGal)—  — Gas equivalent (MMcfe)1,650  3,066     Other   Natural gas (MMcf)8  16 Oil (MBbls)12  24 NGL (MGal)93  127 Gas equivalent (MMcfe)93  181     (1) SCOOP production included from closing date of February 17, 2017.            


Operational Update
The table below summarizes Gulfport's activity for the six-month period ended June 30, 2017 and the number of net wells expected to be drilled and turned-to-sales for the remainder of 2017:


GULFPORT ENERGY CORPORATIONACTIVITY SUMMARY(Unaudited)           Three Months
ended
   Three Months
ended
          March 31, June 30 Remaining Wells Guidance (1)  2017 2017 2017 2017Net Wells Drilled        Utica - Operated 23.5  25.7  21.3  70.5 Utica - Non-Operated 2.0  2.2  6.3  10.5 Total 25.5  27.9  27.6  81.0          SCOOP - Operated 4.2  2.4  10.4  17.0 SCOOP - Non-Operated 0.5  0.3  0.7  1.5 Total 4.7  2.7  11.1  18.5          Net Wells Turned-to-Sales            Utica - Operated 4.7  26.7  32.6  64.0 Utica - Non-Operated 0.6  4.1  4.8  9.5 Total 5.3  30.8  37.4  73.5          SCOOP - Operated —  1.2  13.8  15.0 SCOOP - Non-Operated 0.2  0.1  1.2  1.5 Total 0.2  1.3  15.0  16.5          (1) Utilizes mid-point of publicly provided 2017 guidance    

Utica Shale
In the Utica Shale, during the second quarter of 2017, Gulfport spud 28 gross (25.7 net) operated wells. The wells drilled during the second quarter of 2017 had an average lateral length of approximately 8,408 feet, an increase of 3% over the first quarter of 2017. Normalizing to an 8,000 foot lateral length, Gulfport's average drilling days during the second quarter of 2017 from spud to rig release totaled approximately 18.0 days. In addition, Gulfport turned-to-sales 29 gross (26.7 net) operated wells with an average lateral length of approximately 7,802 feet. For the six-month period ended June 30, 2017, Gulfport's well costs averaged approximately $1,094 per foot of lateral in the Utica Shale.

The table below summarizes notable recent well results across Gulfport's acreage position:


GULFPORT ENERGY CORPORATIONNOTABLE WELL RESULTS SUMMARY(Unaudited)  WellsPhaseAverage Average Production Rates (MMcfe per day)  County On Pad Window Lateral (ft) 30-Day60-Day90-DayCharlie Pad SE Belmont 6Dry Gas East7,67216.916.916.9Jacobs PadSW Monroe1Dry Gas Central8,41414.716.316.7Schubert Pad  S Jefferson1Dry Gas Central8,03516.316.316.3Valerie PadSE Belmont3Dry Gas East7,07218.118.118.1Ward PadSW Belmont2Dry Gas West8,17418.718.718.7        Note: Data provided is three-stream production data.

During the second quarter of 2017, net production from Gulfport’s Utica acreage averaged approximately 857.2 MMcfe per day, an increase of 14% over the first quarter of 2017 and an increase of 33% over the second quarter of 2016.

During the six-month period ended June 30, 2017, Gulfport acquired approximately 5,500 net acres within its core dry gas operating area. In addition, the Company completed an acquisition of mineral interests, increasing its net revenue interest (NRI) on over 5,000 acres by approximately 8%. Gulfport holds approximately 211,000 net acres under lease today in the Utica Shale.

At present, Gulfport has six operated horizontal drilling rigs active in the play.

SCOOP
In the SCOOP, during the second quarter of 2017, Gulfport spud three gross (2.4 net) operated Woodford wells. The wells drilled during the second quarter of 2017 had an average lateral length of 8,804 feet, an increase of 12% over the first quarter of 2017.  Normalizing to a 7,500 foot lateral length, Gulfport's average drilling days during the second quarter of 2017 from spud to rig release totaled approximately 64.8 days.

During the second quarter of 2017, net production from the acreage averaged approximately 162.0 MMcfe per day.

During the six-month period ended June 30, 2017,  Gulfport acquired approximately 2,600 net acres within its core operating area, bringing the Company's holdings to a total of approximately 49,200 net surface acres under lease today in the SCOOP.

At present, Gulfport temporarily has six operated horizontal drilling rigs active in the play. The Company is in the process of high-grading its rig equipment and expects to return to four horizontal rigs in the coming weeks as contracts expire. Subsequent to the second quarter of 2017, Gulfport spud both a Springer and Sycamore well in the SCOOP.

As previously announced, during the second quarter of 2017 Gulfport turned-to-sales two gross (1.2 net) Woodford wells, the Vinson 2-22X27H and Vinson 3R-22X27H, located in the wet gas window in southern Grady County. Following 60 days of production, the Vinson 2-22X27H has cumulatively produced 769.6 MMcf of natural gas and 2,138 barrels of oil and the Vinson 3R-22X27H has cumulatively produced 927.5 MMcf of natural gas and 2,468 barrels of oil. Based upon the composition analysis, the gas being produced from the Vinson pad is 1,118 BTU gas and yielding 35.7 barrels of NGLs per MMcf of natural gas and results in a natural gas shrink of 11%. On a three-stream basis, the Vinson 2-22X27H produced at an average 60-day peak rate of 14.4 MMcfe per day, which is comprised of approximately 79% natural gas, 19% natural gas liquids and 2% oil. The Vinson 3R-22X27H produced at an average 60-day peak rate of 17.3 MMcfe per day, which is comprised of approximately 79% natural gas, 19% natural gas liquids and 2% oil. In addition to these results, Gulfport recently began flowback on two gross operated Woodford wells and is in various stages of completion on an incremental five gross operated Woodford wells.

Southern Louisiana
At its West Cote Blanche Bay and Hackberry fields, during the second quarter of 2017, Gulfport spud six wells and performed 29 recompletions at the fields. Net production during the second quarter of 2017 totaled approximately 18.1 MMcfe per day.

2017 Capital Budget and Production Guidance Update
For the six-month period ended June 30, 2017, Gulfport’s drilling and completion capital expenditures totaled $536.1 million, midstream capital expenditures totaled $23.0 million and leasehold capital expenditures totaled $55.2 million. Michael Moore, Gulfport's Chief Executive Officer and President commented, "As planned, the second quarter of 2017 marks our most active quarter from both an activity and capital spending standpoint for 2017. We currently forecast a similar to slightly lower drilling and completion spend during the third quarter of 2017, decreasing significantly in the fourth quarter of 2017 and reaffirm our capital budget for 2017 of approximately $1.0 to $1.1 billion."

As previously announced, based on actual results during the six-month period ended June 30, 2017, Gulfport increases its 2017 production guidance and currently forecasts that 2017 average daily net production will be in the range of 1,065 MMcfe to 1,100 MMcfe per day, an increase of 48% to 53% over its 2016 average daily net production of 719.8 MMcfe per day.

In addition, as previously announced, based on actual results during the six-month period ended June 30, 2017 and utilizing current strip pricing at the various regional pricing points at which the Company sells its natural gas, Gulfport now forecasts its realized natural gas price, before the effect of hedges and inclusive of the Company’s firm transportation expense, will average in the range of $0.62 to $0.68 per Mcf below NYMEX settlement prices in 2017. Gulfport reiterated its expected realized NGL price and realized oil price and expects that its 2017 realized NGL price, before the effect of hedges and including transportation expense, will be approximately 45% of WTI and its 2017 realized oil price will be in the range of $3.75 to $4.75 per barrel below WTI.

The table below summarizes the Company’s full year 2017 guidance:


GULFPORT ENERGY CORPORATIONCOMPANY GUIDANCE Year Ending 2017 Low HighForecasted Production         Average Daily Gas Equivalent (MMcfepd)1,065  1,100 % Gas~88%% Natural Gas Liquids~8%% Oil~4%    Forecasted Realizations (before the effects of hedges) (1)             Natural Gas (Differential to NYMEX Settled Price) - $/Mcf$(0.62) $(0.68)NGL (% of WTI)~45%Oil (Differential to NYMEX WTI) $/Bbl$(3.75) $(4.75)    Projected Operating Costs   Lease Operating Expense - $/Mcfe$0.18  $0.23 Production Taxes - $/Mcfe$0.08  $0.09 Midstream Gathering and Processing - $/Mcfe$0.55  $0.62 General and Administrative - $/Mcfe$0.15  $0.17     Depreciation, Depletion and Amortization - $/Mcfe$0.85  $0.90      TotalBudgeted D&C Expenditures - In Millions:   Operated$720  $780 Non-Operated$125  $135 Total Budgeted E&P Capital Expenditures$845  $915     Budgeted Midstream Expenditures - In Millions:$50  $60     Budgeted Leasehold Expenditures - In Millions:$110  $120     Total Capital Expenditures - In Millions:$1,005  $1,095     Net Wells Drilled   Utica - Operated67  74 Utica - Non-Operated10  11 Total77  85     SCOOP - Operated16  18 SCOOP - Non-Operated1  2 Total17  20     Net Wells Turned-to-Sales   Utica - Operated61  67 Utica - Non-Operated9  10 Total70  77     SCOOP - Operated14  16 SCOOP - Non-Operated1  2 Total15  18 

 
2017 Financial Position and Liquidity
As of June 30, 2017, Gulfport had cash on hand of approximately $117.6 million. As of June 30, 2017, $210.0 million was outstanding under Gulfport’s revolving credit facility with outstanding letters of credit totaling $237.5 million.

Derivatives
Gulfport has hedged a portion of its expected production to lock in prices and returns that provide certainty of cash flow to execute on its capital plans. Since May 8, 2017, the Company has added approximately 75 BBtupd of natural gas fixed price swaps for the remainder of 2017, 166 BBtupd of natural gas fixed price swaps for 2018 and 37 BBtupd of natural gas fixed price swaps for 2019.

The table below sets forth the Company's hedging positions as of August 8, 2017.


GULFPORT ENERGY CORPORATIONCOMMODITY DERIVATIVES - HEDGE POSITION(Unaudited) 3Q2017     4Q2017  Natural gas:     Swap contracts (NYMEX)     Volume (BBtupd)708  765   Price ($ per MMBtu)$3.19  $3.19         Swaption contracts (NYMEX)     Volume (BBtupd)65  65   Price ($ per MMBtu)$3.11  $3.11         Basis Swap Contract  (Tetco M2)     Volume (BBtupd)—  —   Differential ($ per MMBtu)$—  $—         Basis Swap Contract  (NGPL MC)                               Volume (BBtupd)50  50   Differential ($ per MMBtu)$(0.26) $(0.26)        Oil:     Swap contracts (LLS)     Volume (Bblpd)1,500  1,500   Price ($ per Bbl)$53.12  $53.12         Swap contracts (WTI)     Volume (Bblpd)4,500  4,500   Price ($ per Bbl)$54.89  $54.89             NGL:     C3 Propane Swap Contracts     Volume (Bblpd)3,000  3,000   Price ($ per Gal)$0.63  $0.63         C5+ Swap Contracts     Volume (Bblpd)250  250   Price ($ per Gal)$1.17  $1.17          2017 2018 2019Natural gas:     Swap contracts (NYMEX)     Volume (BBtupd)629  775  57 Price ($ per MMBtu)$3.19  $3.06  $3.10       Swaption contracts (NYMEX)     Volume (BBtupd)60  103  85 Price ($ per MMBtu)$3.12  $3.25  $3.07       Basis Swap Contract  (Tetco M2)     Volume (BBtupd)12  —  — Differential ($ per MMBtu)$(0.59) —  —       Basis Swap Contract  (NGPL MC)     Volume (BBtupd)38  12  — Differential ($ per MMBtu)$(0.26) $(0.26) $—       Oil:     Swap contracts (LLS)     Volume (Bblpd)1,748  —  — Price ($ per Bbl)$51.97  $—  $—       Swap contracts (WTI)     Volume (Bblpd)3,353  899  — Price ($ per Bbl)$54.98  $55.31  $—       NGL:     C3 Propane Swap Contracts     Volume (Bblpd)2,545  —  — Price ($ per Gal)$0.64  $—  $—       C5+ Swap Contracts     Volume (Bblpd)250  —  — Price ($ per Gal)$1.17  —  — 


Presentation
An updated presentation has been posted to the Company’s website. The presentation can be found at www.gulfportenergy.com under the “Company Information” section on the “Investor Relations” page.  Information on the Company’s website does not constitute a portion of this press release.

Conference Call
Gulfport will hold a conference call on Wednesday, August 9, 2017 at 8:00 a.m. CDT to discuss its second quarter of 2017 financial and operational results and to provide an update on the Company’s recent activities.

Interested parties may listen to the call via Gulfport’s website at www.gulfportenergy.com or by calling toll-free at 866-373-3408 or 412-902-1039 for international callers.  A replay of the call will be available for two weeks at 877-660-6853 or 201-612-7415 for international callers.  The replay passcode is 13622396.  The webcast will also be available for two weeks on the Company’s website and can be accessed on the Company’s “Investor Relations” page.

About Gulfport
Gulfport Energy is an independent natural gas and oil company focused on the exploration and development of natural gas and oil properties in North America and is one of the largest producers of natural gas in the contiguous United States. Headquartered in Oklahoma City, Gulfport holds significant acreage positions in the Utica Shale of Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, Gulfport holds an acreage position along the Louisiana Gulf Coast, a position in the Alberta Oil Sands in Canada through its approximately 25% interest in Grizzly Oil Sands ULC and has an approximately 25% equity interest in Mammoth Energy Services, Inc. (NASDAQ:TUSK). For more information, please visit www.gulfportenergy.com.

Forward Looking Statements
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Gulfport expects or anticipates will or may occur in the future, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of Gulfport's business and operations, plans, market conditions, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by Gulfport in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with Gulfport's expectations and predictions is subject to a number of risks and uncertainties, general economic, market, credit or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by Gulfport; Gulfport’s ability to identify, complete and integrate acquisitions of properties  (including the properties recently acquired from Vitruvian II Woodford, LLC) and businesses; competitive actions by other oil and gas companies; changes in laws or regulations; and other factors, many of which are beyond the control of Gulfport. Information concerning these and other factors can be found in the Company's filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this news release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by Gulfport will be realized, or even if realized, that they will have the expected consequences to or effects on Gulfport, its business or operations. Gulfport has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Non-GAAP Financial Measures
EBITDA is a non-GAAP financial measure equal to net income (loss), the most directly comparable GAAP financial measure, plus interest expense, income tax (benefit) expense, accretion expense, depreciation, depletion and amortization and impairment of oil and gas properties. Adjusted EBITDA is a non-GAAP financial measure equal to EBITDA less non-cash derivative (gain) loss, acquisition expense and (income) loss from equity method investments. Cash flow from operating activities before changes in operating assets and liabilities is a non-GAAP financial measure equal to cash provided by operating activity before changes in operating assets and liabilities. Adjusted net income is a non-GAAP financial measure equal to pre-tax net loss less non-cash derivative (gain) loss, acquisition expense and (income) loss from equity method investments. The Company has presented EBITDA and adjusted EBITDA because it uses these measures as an integral part of its internal reporting to evaluate its performance and the performance of its senior management. These measures are considered important indicators of the operational strength of the Company's business and eliminate the uneven effect of considerable amounts of non-cash depletion, depreciation of tangible assets and amortization of certain intangible assets. A limitation of these measures, however, is that they do not reflect the periodic costs of certain capitalized tangible and intangible assets used in generating revenues in the Company's business. Management evaluates the costs of such tangible and intangible assets and the impact of related impairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, the Company believes that these measures provide useful information to its investors regarding its performance and overall results of operations. EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities are not intended to be performance measures that should be regarded as an alternative to, or more meaningful than, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities are not intended to represent funds available for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. The EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities presented in this press release may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in the Company's various agreements.


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)  Three months ended June 30, Six months ended June 30, 2017 2016 2017 2016 (In thousands, except share data)Revenues:       Natural gas sales$205,367  $75,761  $383,204  $149,855 Oil and condensate sales29,468  23,161  53,879  39,000 Natural gas liquid sales24,247  10,311  55,426  19,604 Net gain (loss) on gas, oil and NGL derivatives64,871  (137,392) 164,448  (79,657) 323,953  (28,159) 656,957  128,802 Costs and expenses:       Lease operating expenses20,721  14,661  40,024  31,318 Production taxes5,139  2,856  9,045  5,967 Midstream gathering and processing58,945  39,349  106,886  77,001 Depreciation, depletion and amortization82,246  55,652  148,237  121,129 Impairment of oil and natural gas properties—  170,621  —  389,612 General and administrative12,257  11,854  24,857  22,474 Accretion expense410  261  692  508 Acquisition expense1,060  —  2,358  —  180,778  295,254  332,099  648,009 INCOME (LOSS) FROM OPERATIONS143,175  (323,413) 324,858  (519,207)OTHER (INCOME) EXPENSE:       Interest expense24,188  16,082  47,667  32,105 Interest income(48) (391) (890) (485)Loss from equity method investments, net13,301  836  18,208  31,573 Other income(202) (7) (518) (9) 37,239  16,520  64,467  63,184 INCOME (LOSS) BEFORE INCOME TAXES105,936  (339,933) 260,391  (582,391)INCOME TAX BENEFIT—  (157) —  (348)NET INCOME (LOSS)$105,936  $(339,776) $260,391  $(582,043)NET INCOME (LOSS) PER COMMON SHARE:       Basic$0.58  $(2.71) $1.47  $(4.91)Diluted$0.58  $(2.71) $1.47  $(4.91)Weighted average common shares outstanding—Basic182,840,213  125,343,723  176,591,166  118,426,654 Weighted average common shares outstanding—Diluted    182,841,730  125,343,723  176,842,239  118,426,654 


GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)       June 30, 2017        December 31, 2016  (In thousands, except share data)Assets   Current assets:   Cash and cash equivalents$117,555  $1,275,875 Restricted cash—  185,000 Accounts receivable—oil and natural gas164,154  136,761 Accounts receivable—related parties185  16 Prepaid expenses and other current assets4,279  3,135 Short-term derivative instruments46,416  3,488 Total current assets332,589  1,604,275 Property and equipment:   Oil and natural gas properties, full-cost accounting, $3,109,143 and
$1,580,305 excluded from amortization in 2017 and 2016, respectively8,500,790  6,071,920 Other property and equipment79,521  68,986 Accumulated depletion, depreciation, amortization and impairment(3,937,656) (3,789,780)Property and equipment, net4,642,655  2,351,126 Other assets:   Equity investments256,265  243,920 Long-term derivative instruments19,761  5,696 Deferred tax asset4,692  4,692 Inventories19,303  4,504 Other assets18,890  8,932 Total other assets318,911  267,744 Total assets$5,294,155  $4,223,145 Liabilities and Stockholders’ Equity   Current liabilities:   Accounts payable and accrued liabilities$495,734  $265,124 Asset retirement obligation—current195  195 Short-term derivative instruments28,106  119,219 Current maturities of long-term debt595  276 Total current liabilities524,630  384,814 Long-term derivative instrument8,198  26,759 Asset retirement obligation—long-term43,934  34,081 Long-term debt, net of current maturities1,802,554  1,593,599 Total liabilities2,379,316  2,039,253 Commitments and contingencies   Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as
redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding—  — Stockholders’ equity:   Common stock - $.01 par value, 200,000,000 authorized, 182,854,921 issued      
and outstanding at June 30, 2017 and 158,829,816 at December 31, 20161,828  1,588 Paid-in capital4,410,871  3,946,442 Accumulated other comprehensive loss(47,171) (53,058)Retained deficit(1,450,689) (1,711,080)Total stockholders’ equity2,914,839  2,183,892 Total liabilities and stockholders’ equity$5,294,155  $4,223,145 


GULFPORT ENERGY CORPORATIONRECONCILIATION OF EBITDA AND CASH FLOW(Unaudited)         Three months ended June 30, Six months ended June 30, 2017 2016 2017 2016 (In thousands) (In thousands)        Net income (loss)$105,936  $(339,776) $260,391  $(582,043)Interest expense24,188  16,082  47,667  32,105 Income tax benefit—  (157) —  (348)Accretion expense410  261  692  508 Depreciation, depletion and amortization            82,246  55,652  148,237  121,129 Impairment of oil and gas properties—  170,621  —  389,612 EBITDA$212,780  $(97,317) $456,987  $(39,037)                                 Three months ended June 30, Six months ended June 30, 2017 2016 2017 2016 (In thousands) (In thousands)        Cash provided by operating activity$144,008  $58,950  $286,653  $142,724 Adjustments:         Changes in operating assets and liabilities1,033  29,506  (19,910) 28,958 Operating Cash Flow$145,041  $88,456  $266,743  $171,682 


GULFPORT ENERGY CORPORATIONRECONCILIATION OF ADJUSTED EBITDA(Unaudited)       Three Months ended Six Months Ended June 30, 2017 June 30, 2017 (In thousands)    EBITDA$212,780  $456,987     Adjustments:   Non-cash derivative gain(59,871) (166,667)Acquisition expense1,060  2,358 Loss from equity method investments                    13,301  18,208         Adjusted EBITDA$167,270  $310,886     


GULFPORT ENERGY CORPORATIONRECONCILIATION OF ADJUSTED NET INCOME(Unaudited)       Three Months ended Six Months Ended  June 30, 2017   June 30, 2017  (In thousands, except share data)     Pre-tax net loss excluding adjustments $105,936  $260,391 Adjustments:    Non-cash derivative gain (59,871) (166,667)Acquisition expense 1,060  2,358 Loss from equity method investments 13,301  18,208 Pre-tax net income excluding adjustments $60,426  $114,290      Adjusted net income $60,426  $114,290      Adjusted net income per common share:         Basic $0.33  $0.65      Diluted $0.33  $0.65      Basic weighted average shares outstanding 182,840,213  176,591,166      Diluted weighted average shares outstanding       182,841,730  176,842,239 

 

CONTACT: Investor & Media Contact: Jessica Wills – Manager, Investor Relations and Research jwills@gulfportenergy.com 405-252-4550
Categories: State

Ontario Energy Association Statement on Hydro-Québec/Ontario 20-Year Deal

8 August 2017 - 9:26am

TORONTO, Aug. 08, 2017 (GLOBE NEWSWIRE) -- The Ontario Energy Association (OEA) has learned that detailed discussions are taking place between the Province of Ontario and Hydro-Québec to have Quebec provide Ontario with 8 terawatt hours of electricity annually beginning in 2018.  A copy of a fully developed draft agreement shows that the arrangement would be take-or-pay (Ontario pays for the full volume of electricity whether it uses it or not) for 6.12 cents per kilowatt hour, rising by 2% each year.

“The OEA is disappointed that detailed discussions are happening behind closed doors with Hydro-Québec on new electricity capacity for Ontario,” said Vince Brescia, President & CEO of the Ontario Energy Association. “This procurement process lacks transparency, contradicts the government’s announced direction to move to a ‘technology agnostic capacity auction’ for purchasing future capacity, and seriously undermines the IESO’s Market Renewal initiative.  If this particular deal is pursued, Ontarians will not get the benefit of competition to ensure it is the best of all possible options for the province, and companies who have invested in Ontario and have employees here will not get the opportunity to provide alternatives.  Competitive processes should be used for any new significant system capacity in Ontario,” said Brescia.

About the OEA

The Ontario Energy Association (OEA) is the credible and trusted voice of the energy sector. We earn our reputation by being an integral and influential part of energy policy development and decision making in Ontario. We represent Ontario’s energy leaders that span the full diversity of the energy industry.

CONTACT: For more information: Vince Brescia, President & CEO Ontario Energy Association 416.961.8874 vince@energyontario.ca Leanne Ryan, Marketing & Communications Associate Ontario Energy Association 647.463.5244 leanne@energyontario.ca

Categories: State

Noble Energy Commences Tender Offer for Its 8.25% Senior Notes Due 2019

8 August 2017 - 8:15am

Houston, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Noble Energy, Inc. (NYSE: NBL) (“Noble Energy” or “the Company”) announced today that it has commenced a cash tender offer for any and all of its $1 billion 8.25% senior notes due 2019 (“the 2019 notes”). The tender offer is being made on the terms and subject to the conditions set forth in the offer to purchase dated August 8, 2017 and the related letter of transmittal and notice of guaranteed delivery.

The tender offer will expire at 5:00 p.m., New York City time, on August 14, 2017, unless extended or earlier terminated as described in the offer to purchase (such time and date, as they may be extended, the “Expiration Time”). Holders of the 2019 notes who validly tender (and do not validly withdraw) their notes prior to the Expiration Time, or who deliver to the depositary and information agent a properly completed and duly executed notice of guaranteed delivery in accordance with the instructions described in the offer to purchase, will be eligible to receive in cash the Tender Offer Consideration described below.

Title of SecurityCUSIP / ISINOutstanding
Principal Amount U.S. Treasury
Reference SecurityBloomberg
Reference PageFixed Spread 8.25% Senior
Notes due 2019
655044AD7
US655044AD79$1,000,000,000
1.375% UST
due 07/31/19FIT1+50 bps

The "Tender Offer Consideration" for each $1,000 principal amount of the 2019 notes validly tendered and accepted for purchase pursuant to the tender offer will be determined in the manner described in the offer to purchase by reference to a fixed spread specified for the 2019 notes (the "Fixed Spread") specified in the table above plus the yield based on the bid-side price of the U.S. Treasury Reference Security specified in the table above at 2:00 p.m., New York City time, on August 14, 2017, unless extended or earlier terminated.

Holders will also receive accrued and unpaid interest on the 2019 notes validly tendered and accepted for purchase from the March 1, 2017 interest payment date up to, but not including, the date the Company makes payment for such 2019 notes, which date is anticipated to be August 15, 2017 (the "Settlement Date").

Tendered notes may be withdrawn at any time at or prior to the Expiration Time. The Company reserves the right to terminate, withdraw or amend the tender offer at any time, subject to applicable law.

The tender offer is subject to the satisfaction or waiver of certain conditions, including receipt by the Company of proceeds from a proposed debt financing on terms reasonably satisfactory to the Company that generates net proceeds in an amount that is sufficient to effect the repurchase of the 2019 notes validly tendered and accepted for purchase pursuant to the tender offer. If any 2019 notes remain outstanding after the consummation of the tender offer, the Company expects (but is not obligated) to redeem such notes in accordance with the terms and conditions set forth in the related indenture.

The Company has engaged Citigroup to act as dealer manager in connection with the tender offer, and has appointed Global Bondholder Services Corporation (“GBS”) to serve as the depositary and information agent for the tender offer.

For additional information regarding the terms of the tender offer, please contact Citigroup at 800-558-3745 (toll-free) or 212-723-6106 (collect). Questions regarding the tender offer should be directed to GBS at 212-430-3774 (banks and brokers) or 866-470-3700 (all others).

The complete terms and conditions of the tender offer are described in the offer to purchase and the related letter of transmittal and notice of guaranteed delivery. These documents are available at http://www.gbsc-usa.com/Noble/ and may also be obtained by contacting GBS by telephone.

None of the Company, its board of directors, the dealer manager, GBS or the trustee for the notes, or any of their respective affiliates, is making any recommendation as to whether holders should tender any 2019 notes in response to the tender offer. Holders must make their own decision as to whether to tender any of their 2019 notes and, if so, the principal amount of 2019 notes to tender.

This announcement is not an offer to purchase or a solicitation of an offer to sell any securities and shall not constitute a notice of redemption under the indenture governing the 2019 notes. The tender offer is being made solely by means of the offer to purchase and the related letter of transmittal.

Noble Energy (NYSE: NBL) is an independent oil and natural gas exploration and production company with a diversified high-quality portfolio of both U.S. unconventional and global offshore conventional assets spanning three continents. Founded more than 80 years ago, the company is committed to safely and responsibly delivering our purpose: Energizing the World, Bettering People's Lives®. For more information, visit www.nblenergy.com.

Forward Looking Statements

This news release contains certain “forward-looking statements” within the meaning of federal securities laws. Words such as “anticipates”, “believes”, “expects”, “intends”, “will”, “should”, “may”, and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Energy’s current views about future events and are subject to a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the effects of global, national and regional economic and market conditions, changes in the financial markets and interest rates, the volatility in commodity prices for crude oil and natural gas, the ability to consummate the tender offer or redemption and other risks inherent in Noble Energy’s businesses that are discussed in Noble Energy’s most recent annual report on Form 10-K and in other Noble Energy reports on file with the Securities and Exchange Commission. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update any forward-looking statements should circumstances or management’s estimates or opinions change.

CONTACT: Investor Contacts: Brad Whitmarsh (281) 943-1670 brad.whitmarsh@nblenergy.com Megan Repine (832) 639-7380 megan.repine@nblenergy.com Megan Dolezal (281) 943-1861 megan.dolezal@nblenergy.com Media Contacts: Reba Reid (713) 412-8441 media@nblenergy.com Deena McMullen (281) 943-1732 media@nblenergy.com
Categories: State

Royale Energy Announces Rio Vista Drilling Results

8 August 2017 - 7:16am

SAN DIEGO, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Royale Energy, Inc. (OTCQB:ROYL) (“Royale” or the “Company”) announced the successful completion of its third and fourth wells under joint development agreement in Rio Vista Gas Field, and the spudding of its first well under an agreement in Sansinena Oil Field.

The CRC RVGU 8-3 is a dual completion in the Capay and Martinez formations. Based on an initial 6-hour test with only a portion of the Martinez sand perforated, the well stabilized at 2,000 MCF per day with 1395 psi tubing pressure.

The CRC Rio Vista 8-4 was brought on line, August 4, 2017 and is presently flowing approximately 850 MCF per day from the Capay and McCormack formations. Additional proven reserves, including the upper McCormack and 48’ of Martinez sand are behind pipe and available for future recompletion.

The presence of a productive Capay sand in the 8-4 sets up additional Capay locations across the development acreage. Royale plans to drill an under balanced Capay well, the CRC RVGU 8-5, later this year. 

On July 7, 2017, Royale entered an agreement to jointly develop two wells in Sansinena Field in Los Angeles County. The wells, Sansinena 9A4 and Sansinena 9A7 are scheduled to be drilled in the 3rd Quarter of 2017.  The first well, Sansinena 9A4 will spud in August. Matrix Oil is the operator. 

Don Hosmer, President of Royale Energy said, “We are extremely pleased with our continued success in Rio Vista. Using 3-D seismic, our team continues to find new opportunities in this prolific northern California gas field. We are also excited to spud our first well in Sansinena Field with our partners Matrix Oil. Sansinena is an underdeveloped oil field with over 75 Proven Undeveloped well (PUD) locations with 20 million barrels of proven undeveloped reserves.”

About Royale Energy, Inc.
Founded in 1986, Royale Energy, Inc. (OTCQB:ROYL) is an independent exploration and production company focused on the acquisition, development, and marketing of natural gas and oil. Royale Energy has its primary operations in the Sacramento and San Joaquin basins in California.

Forward-Looking Statements
In addition to historical information contained herein, this news release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, subject to various risks and uncertainties that could cause the company’s actual results to differ materially from those in the “forward-looking” statements. While the company believes its forward-looking statements are based upon reasonable assumptions, there are factors that are difficult to predict and that are influenced by economic and other conditions beyond the company’s control. Investors are directed to consider such risks and other uncertainties discussed in documents filed by the company with the Securities and Exchange Commission.

 

CONTACT: Contact: Royale Energy, Inc. Chanda Idano- Director of Marketing & PR 619-383-6600 chanda@royl.com http://www.royl.com
Categories: State

PDC Energy Announces 2017 Second Quarter Results With 54% Production Increase to 8.0 Million Barrels of Oil Equivalent

8 August 2017 - 7:00am

DENVER, Aug. 08, 2017 (GLOBE NEWSWIRE) -- PDC Energy, Inc. ("PDC" or the "Company") (NASDAQ:PDCE) today reported its 2017 second quarter operating and financial results.

Second Quarter 2017 Highlights

  • Production of 8.0 million barrels of oil equivalent (“MMBoe”), a 54 percent increase year-over-year; daily production of approximately 88,100 barrels of oil equivalent (“Boe”).
     
  • Oil production of 3.2 million barrels (“MMBbls”), a 62 percent increase year-over-year and 29 percent increase compared to the first quarter of 2017.
     
  • Delaware basin production averaged 10,047 Boe per day.
     
  • Wattenberg drilling efficiency increased approximately 15 percent.
     
  • Lease operating expenses (“LOE”) of $2.50 per Boe, a 16 percent decrease compared to the first quarter of 2017.
     
  • Liquidity of approximately $900 million, including $202 million of cash, resulting in a leverage ratio of 1.9 times, as defined by the Company’s credit agreement.

CEO Commentary

President and Chief Executive Officer, Bart Brookman commented, “Our quarterly production results demonstrate improved capital efficiencies and completion enhancements in Wattenberg, as well as the momentum we are building in the Delaware Basin.  In Wattenberg, we further reduced drilling times, which will allow us to drop our rig count to three this October and maintain a similar pace of development.  We have great operational flexibility in both basins to increase or decrease our rig counts depending on market conditions.  Lastly, we are excited by the work of our operating teams in not only delivering strong recent well results in the Delaware Basin, but improving our operating cost structure in the quarter. ”

Operating Update and Results

The Company turned-in-line six wells in the Delaware Basin in the second quarter of 2017 and had average daily production of 10,047 Boe.  Production from the Kenosha well, a Wolfcamp A well in the Eastern acreage block, is strong with an average 30-day peak production rate of approximately 2,300 Boe per day.  The Kenosha, which was turned-in-line in the first quarter of 2017, is the Company’s first extended-reach lateral well in the basin and has been producing more than 2,000 Boe per day for the past 100 days.  In the Central acreage block, PDC drilled and turned-in-line the Greenwich 4H well testing the Wolfcamp A.  Performance from the 7,500 foot lateral is exceeding type curve expectations and had an average 30-day peak production rate of 1,425 Boe per day with approximately 55 percent oil.  The Company’s two wells in the Western acreage block were turned-in-line in the second quarter, but have taken longer to clean up and generally have underperformed internal expectations.  The Company currently plans to operate three drilling rigs for the remainder of the year, with much of the anticipated activity focused on additional extended-reach lateral wells in the Eastern area.  Concentrating on cost management and operational efficiencies in the current aggressive service cost market remains a key priority. 

In Wattenberg, PDC spud 44 wells and had 32 turn-in-lines in the second quarter with average daily production of 75,621 Boe.  Throughout the first half of the year, the Company continued to realize increased drilling efficiencies on its standard-, mid- and extended-reach lateral wells resulting in more than 15 percent average improvements in spud-to-spud drill times.  Due to these improvements, the Company has elected to return to a three rig program in the fourth quarter of 2017, helping to manage the overall capital program.  Because of the increased efficiencies and adjusted timing of completions, the Company now expects to spud approximately 155 wells and turn-in-line approximately 133 wells for the full-year in the Wattenberg Field, compared to an estimated 139 spuds and 139 turn-in-lines previously.

Oil and Gas Production, Sales and Operating Cost Data

The following table provides production by area, and weighted-average sales price for the three and six months ended June 30, 2017 and 2016, excluding net settlements on derivatives:

 Three Months Ended
 June 30, Six Months Ended
June 30, 2017 2016 Percent 2017 2016 Percent            Crude oil (MBbls)           Wattenberg Field2,798  1,894  47.7% 4,940  3,712  33.1%Delaware Basin364  —   * 639  —   *Utica Shale75  99  (24.4)% 166  188  (12.1)%Total3,237  1,993  62.4% 5,745  3,900  47.3%            Weighted-Average Sales Price$45.97  $40.37  13.9% $47.31  $34.46  37.3%            Natural gas (MMcf)           Wattenberg Field15,192  12,098  25.6% 28,906  22,268  29.8%Delaware Basin2,025  —   * 3,271  —   *Utica Shale566  575  (1.6)% 1,190  1,083  9.9%Total17,783  12,673  40.3% 33,367  23,351  42.9%            Weighted-Average Sales Price$2.16  $1.37  57.7% $2.26  $1.38  63.8%            NGLs (MBbls)           Wattenberg Field1,551  1,047  48.1% 2,909  1,888  54.1%Delaware Basin212  —   * 343  —   *Utica Shale51  45  11.9% 105  87  19.8%Total1,814  1,092  66.1% 3,357  1,975  70.0%            Weighted-Average Sales Price$14.59  $11.93  22.3% $16.75  $9.89  69.4%            Crude oil equivalent (MBoe)           Wattenberg Field6,882  4,957  38.8% 12,667  9,311  36.0%Delaware Basin914  —   * 1,527  —   *Utica Shale219  240  (8.5)% 469  456  2.8%Total8,015  5,197  54.2% 14,663  9,767  50.1%            Weighted-Average Sales Price  $26.65  $21.33  24.9% $27.50  $19.07  44.2%


The following table provides the components of production costs for the three and six months ended June 30, 2017 and 2016 in terms of total dollars and on a per Boe basis:


 Three Months Ended
June 30, Six Months Ended
 June 30, 2017 2016 2017 2016        Lease operating expenses$20.0  $13.7  $39.8  $29.0 Production taxes15.0  6.0  27.4  10.1 Transportation, gathering and processing expenses  6.5  4.5  12.4  8.5 Total$41.6  $24.2  $79.6  $47.6 


 Three Months Ended
June 30, Six Months Ended
 June 30, 2017 2016 2017 2016        Lease operating expenses per Boe$2.50  $2.63  $2.72  $2.97 Production taxes per Boe1.88  1.16  1.87  1.04 Transportation, gathering and processing expenses per  
Boe0.81  0.86  0.84  0.87 Total per Boe$5.19  $4.65  $5.43  $4.88 


Financial Results

Net income for the second quarter of 2017 was $41.3 million, or $0.62 per diluted share, compared to net loss of $95.5 million, or $2.04 per diluted share, for the comparable period of 2016.  The year-over-year difference was primarily attributable to a $102.8 million increase in crude oil, natural gas and NGLs sales in 2017, as well as the impact of the change in the fair value of derivatives during the quarters.  Adjusted net income, a non-GAAP measure defined below, was $12.5 million, or $0.19 per diluted share in the second quarter of 2017 compared to adjusted net loss of $5.0 million, or $0.11 per diluted share for the comparable period of 2016.

Net cash from operating activities was $123.7 million in the second quarter of 2017, compared to $96.6 million in the second quarter of 2016.  The increase in 2017 cash flows was a result of increases to both production volumes and realized sales prices compared to the prior year.  Adjusted cash flows from operations, a non-GAAP financial measure defined below, were $142.9 million for the second quarter of 2017, compared to $112.6 million in the comparable period of 2016.

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased 93 percent to $213.6 million in the second quarter of 2017, compared to $110.8 million in the second quarter of 2016.  The sales price per Boe, excluding net settlements on derivatives, improved to $26.65 in the second quarter of 2017 compared to $21.33 in the second quarter of 2016.  Including commodity price risk management gain and other income, crude oil, natural gas and NGLs revenues were $275.2 million in the second quarter of 2017 compared to $20.1 million in the second quarter of 2016.

Net commodity price risk management activities for the second quarter of 2017 resulted in a gain of $57.9 million compared to a loss of $92.8 million in the comparable period of 2016.  The second quarter 2017 gain was comprised of $45.9 million in net change in fair value of unsettled derivatives and $12.0 million of net settlement gains.  Net settlements in the second quarter of 2016 were $53.3 million with a decrease in fair value of unsettled derivatives of $146.1 million.

Production costs, which include LOE, production taxes, and transportation, gathering and processing expenses (“TGP”), for the second quarter of 2017 were $41.5 million, or $5.19 per Boe.  In the second quarter of 2016, production costs were $24.2 million, or $4.65 per Boe.  LOE in the second quarter of 2017 decreased five percent to $2.50 per Boe compared to $2.63 per Boe in the similar 2016 period primarily due to increased production volumes offsetting higher LOE costs associated with operations in the Delaware Basin.

Depreciation, depletion and amortization expense ("DD&A") related to crude oil and natural gas properties was $124.4 million, or $15.51 per Boe in the second quarter of 2017, compared to $106.1 million, or $20.41 per Boe in the second quarter of 2016.  The decrease in weighted-average DD&A rate between periods was due to the increases in proven reserves attributable to our operations outpacing production growth, even with a robust capital program.

The Company’s capital investment in the development of oil and natural gas properties and other capital expenditures, before the change in accounts payable, was $218.3 million during the second quarter of 2017 compared to $107.5 million for the same 2016 period.  The increase in capital investment was primarily attributable to investments made in Delaware Basin drilling, completions and midstream infrastructure in the second quarter of 2017.

2017 Capital Investment Outlook and Financial Guidance

Senior Vice President and Chief Financial Officer, David Honeyfield, commented, “As we manage the capital investment program, we are also adjusting the timing of completions, resulting in full-year estimated production towards the bottom of our 32 to 33 MMBoe range.  This production outlook takes into account our updated turn-in-line schedule, anticipated midstream constraints in Wattenberg, and our updated production forecast from our Delaware assets.  In terms of capital investment, we are committed to prioritizing the strength of our balance sheet while delivering highly economic rates-of-return on our capital program.  After adjusting for the timing of drilling and certain completions and increased well costs in the Delaware, we expect full-year capital to be approximately $800 million.  This should set us up to exit 2017 with more than $100 million of cash on the balance sheet together with the undrawn $700 million commitment level on our current bank revolving credit facility."

The following table provides additional 2017 financial guidance:


 LowHighOperating ExpensesLease operating expense ($/Boe)$2.65 $3.00 Transportation, gathering and processing expenses ($/Boe)$0.70 $0.90 Production taxes (% of Crude Oil, Natural Gas & NGL sales)6%8%General and administrative expense ($/Boe)$3.25 $3.60 Depreciation, depletion and amortization ($/Boe)$15.00 $16.50 Exploration, geologic and geophysical expense (millions)$5.0 $10.0 Estimated Price Realizations (% of NYMEX) (excludes TGP)Oil92%94%Gas70%72%NGLs27%31%


Non-GAAP Financial Measures

PDC uses "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and when providing public guidance on possible future results.  Beginning in 2017, the Company has included non-cash stock-based compensation and exploration, geologic and geophysical expenses to its adjusted EBITDAX calculation.  All prior periods have been reconciled to match accordingly.  PDC believes that each of these measures is useful in providing transparency with respect to certain aspects of its operations.  Each of these measures is calculated by adjusting for the items set forth in the relevant table below from the most closely comparable U.S. GAAP measure. See Management's Discussion and Analysis of Financial Condition and Results of Operation - Reconciliation of Non-U.S. GAAP Financial Measures in PDC's Annual Report on Form 10-K for the year ended December 31, 2016, and other subsequent filings with the SEC, for additional disclosure concerning these non-U.S. GAAP measures.  These are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income, cash flows from operations, investing or financing activities or other U.S. GAAP financial measures, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP.  The non-U.S. GAAP financial measures that PDC uses may not be comparable to similarly titled measures reported by other companies.  Also, in the future, PDC may disclose different non-U.S. GAAP financial measures in order to help its investors more meaningfully evaluate and compare its future results of operations to its previously reported results of operations.  PDC strongly encourages users of financial information to review the Company's financial statements and publicly filed reports in their entirety and not to rely on any single financial measure.

The following tables provide reconciliations of adjusted cash flows from operations, adjusted net income (loss) and adjusted EBITDAX to their most comparable U.S. GAAP measures (in millions, except per share data).  Adjusted net income and adjusted EBITDAX in the three and six months ended June 30, 2017, includes the $40.2 million of proceeds from the sale of the Company’s MK Promissory Note:

Adjusted Cash Flows from Operations Three Months Ended
June 30, Six Months Ended
June 30, 2017 2016 2017 2016Adjusted cash flows from operations:       Net cash from operating activities$123.7  $96.6  $263.2  $197.8 Changes in assets and liabilities19.2  16.0  (6.6) 5.8 Adjusted cash flows from operations$142.9  $112.6  $256.6  $203.6  Adjusted Net Income (Loss) Three Months Ended
June 30, Six Months Ended
June 30, 2017 2016 2017 2016Adjusted net income (loss):       Net income (loss)$41.3  $(95.5) $87.4  $(167.0)(Gain) loss on commodity derivative instruments(57.9) 92.8  (138.6) 81.7 Net settlements on commodity derivative instruments12.0  53.3  12.5  120.2 Tax effect of above adjustments17.2  (55.6) 47.2  (76.8)Adjusted net income (loss)$12.5  $(5.0) $8.5  $(41.9)Weighted-average diluted shares outstanding66.0  46.7  66.1  44.2 Adjusted diluted earnings per share$0.19  $(0.11) $0.13  $(0.95)


Adjusted EBITDAX Three Months Ended
June 30, Six Months Ended
June 30, 2017 2016 2017 2016Net income (loss) to adjusted EBITDAX:       Net income (loss)$41.3  $(95.5) $87.4  $(167.0)(Gain) loss on commodity derivative instruments(57.9) 92.8  (138.6) 81.7 Net settlements on commodity derivative instruments12.0  53.3  12.5  120.2 Non-cash stock-based compensation5.4  6.4  9.8  11.1 Interest expense, net18.9  10.5  38.1  20.8 Income tax expense (benefit)24.5  (58.3) 50.9  (100.2)Impairment of properties and equipment27.6  4.2  29.8  5.2 Exploration, geologic, and geophysical expense1.0  0.2  2.0  0.4 Depreciation, depletion, and amortization126.0  107.0  235.3  204.4 Accretion of asset retirement obligations1.7  1.8  3.4  3.6 Adjusted EBITDAX$200.4  $122.4  $330.6  $180.2         Cash from operating activities to adjusted EBITDAX:       Net cash from operating activities$123.7  $96.6  $263.2  $197.8 Interest expense, net18.9  10.5  38.1  20.8 Amortization of debt discount and issuance costs(3.2) (1.3) (6.4) (3.1)Gain (loss) on sale of properties and equipment0.5  (0.3) 0.7  (0.2)Exploration, geologic, and geophysical expense1.0  0.2  2.0  0.4 Other(1)40.3  0.7  39.6  (41.3)Changes in assets and liabilities19.2  16.0  (6.6) 5.8 Adjusted EBITDAX$200.4  $122.4  $330.6  $180.2 

(1) Other includes the impact of provisions for the uncollectible notes receivable in the three and six months ended June 30, 2017, and the six months ended June 30, 2016. 


PDC ENERGY, INC.Consolidated Statements of Operations(unaudited, in thousands, except per share data)  Three Months Ended
June 30, Six Months Ended
June 30, 2017 2016 2017 2016        Revenues       Crude oil, natural gas, and NGLs sales$213,602  $110,841  $403,294  $186,208 Commodity price risk management gain (loss), net of settlements57,932  (92,801) 138,636  (81,745)Other income3,624  2,057  6,935  6,465 Total revenues275,158  20,097  548,865  110,928 Costs, expenses and other       Lease operating expenses20,028  13,675  39,817  29,005 Production taxes15,042  6,043  27,441  10,114 Transportation, gathering and processing expenses6,488  4,465  12,390  8,506 General and administrative expense29,531  23,579  55,846  46,358 Exploration, geologic, and geophysical expense1,033  237  1,987  447 Depreciation, depletion and amortization126,013  107,014  235,329  204,402 Impairment of properties and equipment27,566  4,170  29,759  5,171 Accretion of asset retirement obligations1,666  1,811  3,434  3,623 (Gain) loss on sale of properties and equipment(532) 260  (692) 176 Provision for uncollectible notes receivable(40,203) —  (40,203) 44,738 Other expenses3,890  2,125  7,418  4,703 Total costs, expenses and other190,522  163,379  372,526  357,243 Income (loss) from operations84,636  (143,282) 176,339  (246,315)Interest expense(19,617) (10,672) (39,084) (22,566)Interest income768  177  1,008  1,735 Income (loss) before income taxes65,787  (153,777) 138,263  (267,146)Income tax (expense) benefit(24,537) 58,327  (50,867) 100,166 Net income (loss)$41,250  $(95,450) $87,396  $(166,980)        Earnings per share:       Basic$0.63  $(2.04) $1.33  $(3.78)Diluted$0.62  $(2.04) $1.32  $(3.78)        Weighted-average common shares outstanding:       Basic65,859  46,742  65,804  44,175 Diluted66,019  46,742  66,066  44,175 



PDC ENERGY, INC.Consolidated Balance Sheets(unaudited, in thousands, except share and per share data)   June 30, 2017 December 31, 2016Assets    Current assets:    Cash and cash equivalents $202,291  $244,100 Accounts receivable, net 135,203  143,392 Fair value of derivatives 52,105  8,791 Prepaid expenses and other current assets 6,619  3,542 Total current assets 396,218  399,825 Properties and equipment, net 4,165,572  4,008,266 Fair value of derivatives 16,397  2,386 Goodwill 56,331  62,041 Other assets 22,410  13,324 Total Assets $4,656,928  $4,485,842      Liabilities and Stockholders' Equity    Liabilities    Current liabilities:    Accounts payable $152,492  $66,322 Production tax liability 35,296  24,767 Fair value of derivatives 10,138  53,595 Funds held for distribution 86,846  71,339 Accrued interest payable 15,955  15,930 Other accrued expenses 29,939  38,625 Total current liabilities 330,666  270,578 Long-term debt 1,049,004  1,043,954 Deferred income taxes 452,028  400,867 Asset retirement obligations 77,867  82,612 Fair value of derivatives 2,311  27,595 Other liabilities 30,610  37,482 Total liabilities 1,942,486  1,863,088      Commitments and contingent liabilities         Stockholders' equity    Common shares - par value $0.01 per share, 150,000,000 authorized,
65,927,104 and 65,704,568 issued as of June 30, 2017 and
December 31, 2016, respectively 659  657 Additional paid-in capital 2,495,940  2,489,557 Retained earnings 221,604  134,208 Treasury shares - at cost, 64,024 and 28,763 as of June 30, 2017 and
December 31, 2016, respectively (3,761) (1,668)Total stockholders' equity 2,714,442  2,622,754 Total Liabilities and Stockholders' Equity (Deficit) $4,656,928  $4,485,842 



PDC ENERGY, INC.Consolidated Statements of Cash Flows(unaudited, in thousands)   Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017 2016 2017 2016Cash flows from operating activities:        Net income (loss) 41,250  (95,450) $87,396  $(166,980)Adjustments to net income (loss) to reconcile to net cash from
operating activities:        Net change in fair value of unsettled commodity derivatives (45,917) 146,055  (126,070) 201,825 Depreciation, depletion and amortization 126,013  107,014  235,329  204,402 Impairment of properties and equipment 27,566  4,170  29,759  5,171 Provision for uncollectible notes receivable (40,203) —  (40,203) 44,738 Accretion of asset retirement obligation 1,666  1,811  3,434  3,623 Non-cash stock-based compensation 5,372  6,444  9,826  11,126 (Gain) loss on sale of properties and equipment (532) 260  (692) 176 Amortization of debt discount and issuance costs 3,215  1,323  6,399  3,077 Deferred income taxes 24,487  (58,947) 50,767  (102,319)Other (52) (85) 670  (1,287)Changes in assets and liabilities (19,168) (15,947) 6,582  (5,754)     Net cash from operating activities 123,697  96,648  263,197  197,798 Cash flows from investing activities:        Capital expenditures for development of crude oil and natural gas
properties (204,580) (112,368) (334,406) (234,677)Capital expenditures for other properties and equipment (1,478) (580) (2,299) (1,030)Acquisition of crude oil and natural gas properties, including
settlement adjustments (809) —  5,372  — Proceeds from sale of properties and equipment, net 556  4,813  1,293  4,903 Sale of promissory note 40,203  —  40,203  — Restricted cash (9,250) —  (9,250) — Sale of short-term investments 49,890  —  49,890  — Purchases of short-term investments —  —  (49,890) —      Net cash from investing activities (125,468) (108,135) (299,087) (230,804)Cash flows from financing activities:        Proceeds from issuance of equity, net of issuance cost —  (3) —  296,575 Proceeds from revolving credit facility —  —  —  85,000 Repayment of revolving credit facility —  —  —  (122,000)Redemption of convertible notes —  (115,000) —  (115,000)Purchase of treasury shares (3,257) (2,853) (5,274) (4,055)Other (305) (103) (645) 735 Net cash from financing activities (3,562) (117,959) (5,919) 141,255 Net change in cash and cash equivalents (5,333) (129,446) (41,809) 108,249 Cash and cash equivalents, beginning of period 207,624  238,545  244,100  850 Cash and cash equivalents, end of period $202,291  $109,099  $202,291  $109,099 


2017 Second Quarter Teleconference and Webcast

The Company invites you to join Bart Brookman, President and Chief Executive Officer; David Honeyfield, Senior Vice President Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and Scott Reasoner, Chief Operating Officer, for a conference call on Tuesday, August 8, 2017 to discuss its 2017 second quarter results.  The related slide presentation will be available on PDC’s website at www.pdce.com.

Conference Call and Webcast:
Date/Time: Tuesday, August 8, 2017, 11:00 a.m. ET
Webcast available at: www.pdce.com
Domestic (toll free): 877-312-5520
International: 253-237-1142
Conference ID: 53186183

Replay Numbers:
Domestic (toll free): 855-859-2056
International: 404-537-3406
Conference ID: 53186183

The replay of the call will be available for six months on PDC's website at www.pdce.com.

Upcoming Investor Presentations

PDC is scheduled to present at the following conferences: Enercom's The Oil and Gas Conference in Denver on Monday, August 14, 2017; Barclay’s CEO Energy-Power Conference in New York on Wednesday, September 6, 2017; The Johnson Rice Energy Conference in New Orleans on Tuesday, September 26, 2017 and IPAA OGIS-Chicago on Tuesday, October 3, 2017.  Webcast information will be posted to the Company’s website, www.pdce.com, prior to the start of each conference, along with any presentation materials.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and the Delaware Basin in Reeves and Culberson Counties, Texas. The Company also has operations in the Utica Shale in Southeastern Ohio, which it plans to divest. PDC’s operations are focused in the horizontal Niobrara and Codell plays in the Wattenberg Field and in the Wolfcamp zones in the Delaware Basin.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements".  Words such as expects, anticipates, intends, plans, believes, seeks, estimates, outlook, targets, and similar expressions or variations of such words are intended to identify forward-looking statements herein.  Forward-looking statements may include, among other things, statements regarding future: reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments.

The above statements are not the exclusive means of identifying forward-looking statements herein.  Although forward-looking statements contained in this press release reflect the Company’s good faith judgment, such statements can only be based on facts and factors currently known to it.  Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future.  Throughout this press release or accompanying materials, the Company may use the terms “projection” or similar terms or expressions, or indicate that it has “modeled” certain future scenarios.  PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its business or the industry in periods beyond the current fiscal year.  Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.  Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

  • changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for the products it produces;
  • volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
  • reductions in the borrowing base under its revolving credit facility;
  • impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
  • declines in the value of its crude oil, natural gas, and NGLs properties resulting in further impairments;
  • changes in estimates of proved reserves;
  • inaccuracy of reserve estimates and expected production rates;
  • potential for production decline rates from its wells being greater than expected;
  • timing and extent of its success in discovering, acquiring, developing, and producing reserves;
  • availability of sufficient pipeline, gathering, and other transportation facilities and related infrastructure to process and transport its production and the impact of these facilities and regional capacity on the prices received for production;
  • timing and receipt of necessary regulatory permits;
  • risks incidental to the drilling and operation of crude oil and natural gas wells;
  • losses from its gas marketing business exceeding its expectations;
  • difficulties in integrating its operations as a result of any significant acquisitions, including its recent acquisitions in the Delaware Basin;
  • increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;
  • potential losses in acreage due to expiration or otherwise;
  • increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets;
  • future cash flows, liquidity, and financial condition;
  • competition within the oil and gas industry;
  • availability and cost of capital;
  • success in marketing crude oil, natural gas, and NGLs;
  • effect of crude oil and natural gas derivatives activities;
  • impact of environmental events, governmental and other third-party responses to such events, and its ability to insure adequately against such events;
  • cost of pending or future litigation, including recent environmental litigation;
  • effect that acquisitions it may pursue has on its capital investments;
  • its ability to retain or attract senior management and key technical employees; and
  • success of strategic plans, expectations, and objectives for its future operations.

Further, PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in its Quarterly Report on Form 10-Q, its Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and other filings with the SEC for further information on risks and uncertainties that could affect the Company’s business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein.

PDC cautions you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. The Company undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

CONTACT: Contacts:             Michael Edwards Senior Director Investor Relations 303-860-5820 michael.edwards@pdce.com Kyle Sourk Manager Investor Relations 303-318-6150 kyle.sourk@pdce.com
Categories: State

Latvijas Gāze, JSC: Dates of publishing of financial accounts

8 August 2017 - 6:55am

Updated Financial Calendar (changed date for 6 Months of 2017)

2017 / 6 months / 14.08.2017
2017 / 9 months / 28.11.2017

REMINDER

JSC Latvijas Gāze is organizing a webinar scheduled on August 14, 2017 at 15:00 (EEST). Please note that attendees have to register for the webinar in advance: http://ej.uz/webinar_LG

         Vinsents Makaris
         Head of Investor Relations
         Phone: + (371) 67 369 144
         E-mail: IR@lg.lv

Categories: State

Vertex Energy, Inc. Announces Second Quarter and Year-to-Date 2017 Financial Results

8 August 2017 - 6:00am

Revenue increased 51% year-over-year, while Gross Profit margin was 14.7 percent

Conference call to be held today at 9:00 A.M. EDT

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Vertex Energy, Inc. (NASDAQ:VTNR), a refiner and marketer of high-quality specialty hydrocarbon products, announced today its financial results for the second quarter and year-to-date, the three and six months ended June 30, 2017.

FINANCIAL HIGHLIGHTS FOR SECOND QUARTER OF 2017

  • Revenue increased to $36.9 million, compared to $24.4 million
  • Gross profit was up 3% to $5.4 million, while gross profit margin was 14.7%
  • Overall volume was up 19%
  • Net loss of $2.7 million, or a loss of $0.08 per share, an improvement over a net loss of $0.21 per share a year ago

FINANCIAL HIGHLIGHTS FOR FIRST SIX MONTHS OF 2017

  • Revenue increased to $71.7 million, compared to $38.6 million
  • Gross profit was up 89% to $9.5 million, while gross profit margin was 13.2%
  • Overall volume was up 30%
  • Net loss of $6.7 million, or a loss of $0.21 per share, an improvement over a net loss of $0.29 per share a year ago

DIVISION FINANCIAL HIGHLIGHTS FOR SECOND QUARTER AND FIRST SIX MONTHS OF 2017
Black Oil division, which includes our Thermal Chemical Extraction Process (TCEP) and Marrero and Heartland business units, is a collector, aggregator, logistics manager, and re-refiner of used motor oil, posted:

For Second Quarter of 2017:

  • Revenue was $27.4 million, an increase of 38% from a year ago
  • Gross profit increased 3% to $4.4 million
  • Volume increased 14% and per barrel margins were down 10% compared to year ago

For First Six Months of 2017:

  • Revenue was $52.2 million, an increase of 74% from a year ago
  • Gross profit increased 129% to $7.4 million
  • Volume increased 29% and per barrel margins were up 77% from a year ago

Refining and Marketing, which produces three distinct products from distressed hydrocarbon streams, posted:

For Second Quarter of 2017:

  • Revenue was $5.2 million, an increase of 77% from a year ago
  • Gross profit decreased 39% to $462,000
  • Volume increased 54% and per barrel margins was down 60% from the same period a year ago

For First Six Months of 2017:

  • Revenue was $10.6 million, up 91% from a year ago
  • Gross profit declined 6% to $1.2 million
  • Volume rose 32% and per barrel margins were down 28% from a year ago

Vertex Recovery, which is responsible for the proper recovery and management of hydrocarbon streams, the marketing of Group III base oils and the proper dismantling and recovery of metals from industrial and marine facilities, posted: 

For Second Quarter of 2017:

  • Revenue was $4.3 million, an improvement of 160% from a year ago
  • Gross profit was up 141% to $548,000
  • Volume increased 9% and per barrel margins was up 120% from the same period ago

For First Six Month of 2017:

  • Revenue was $8.9 million, an increase of 193% from a year ago
  • Gross profit rose 76% to $936,000
  • Volume jumped 31% and per barrel margins were up 35% from the same period a year ago

Benjamin P. Cowart, Chairman and CEO of Vertex Energy, stated, "We are encouraged by the continued improvements of the Company's operations. One of our goals for 2017 has been to increase our throughput at our facilities. In addition, our progress was demonstrated in our operating performance. Production volumes at each of our facilities were significantly above our internal goals driven by continued improvements at each of our facilities."

Mr. Cowart added, "Capital investments in our facilities and our focus on increasing volume continue to have a positive impact on our business operations. Although we experienced spread compression in our Marrero operations during the second quarter, we are pleased by the increase in our collected volume and the performance at our Heartland facility.”

Mr. Cowart concluded, "Our team has worked very hard to stabilize and improve our financial performance this year. We are confident in our business model and the stability of our business operations for the long-term."

SECOND QUARTER 2017 FINANCIAL RESULTS CONFERENCE CALL

Management will host a conference call today at 9 A.M. EDT. Those who wish to participate in the conference call may telephone 1-877-869-3847 from the U.S. and International callers may telephone 201-689-8261, approximately 15 minutes before the call. A webcast will also be available under the Investor Relations section at: www.vertexenergy.com.

A digital replay will be available by telephone approximately two hours after the completion of the call until December 1, 2017, and may be accessed by dialing 877-660-6853 from the U.S. or 201-612-7415 for international callers using conference ID # 13666651.

ABOUT VERTEX ENERGY, INC.

Vertex Energy, Inc. (VTNR) is a specialty refiner and marketer of high-quality hydrocarbon products. Our business divisions include aggregation and transportation of refinery feedstocks such as used motor oil and other petroleum and chemical co-products to produce and commercialize a broad range of high purity intermediate and finished products such as fuel oils, marine grade distillates and high purity base oils used for lubrication. Vertex operates on a regional model with strategic hubs located in key geographic areas in the United States. With its headquarters in Houston, Texas, Vertex Energy's processing operations are located in Houston and Port Arthur (TX), Marrero (LA), and Columbus (OH). For more information on Vertex Energy please contact Porter, LeVay & Rose, Inc.'s investor relations representative Marlon Nurse, D.M. at 212-564-4700 or visit our website at www.vertexenergy.com.

Forward-Looking Statements
This press release may contain forward-looking statements, including information about management’s view of Vertex Energy’s future expectations, plans and prospects, within the safe harbor provisions under The Private Securities Litigation Reform Act of 1995 (the “Act”). In particular, when used in the preceding discussion, the words “believes,” “hopes,” “expects,” “intends,” “plans,” “anticipates,” or “may,” and similar conditional expressions are intended to identify forward-looking statements within the meaning of the Act, and are subject to the safe harbor created by the Act. Any statements made in this news release other than those of historical fact, about an action, event or development, are forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors, which may cause the results of Vertex Energy, its divisions and concepts to be materially different than those expressed or implied in such statements. These risk factors and others are included from time to time in documents Vertex Energy files with the Securities and Exchange Commission, including but not limited to, its Form 10-Ks, Form 10-Qs and Form 8-Ks. Other unknown or unpredictable factors also could have material adverse effects on Vertex Energy’s future results. The forward-looking statements included in this press release are made only as of the date hereof. Vertex Energy cannot guarantee future results, levels of activity, performance or achievements. Accordingly, you should not place undue reliance on these forward-looking statements. Finally, Vertex Energy undertakes no obligation to update these statements after the date of this release, except as required by law, and also takes no obligation to update or correct information prepared by third parties that are not paid for by Vertex Energy.

Vertex Energy, Inc.Reconciliation of Net Income (Loss) attributable to Vertex Energy, Inc., to Earnings
Before Interest, Taxes, Depreciation and Amortization (EBITDA) and Adjusted EBITDA*
     For the Three Months
Ended June 30, 2017

 For the Six Months
Ended June 30, 2017
Net (loss) income attributable to Vertex Energy, Inc.    $(1,867,506) $(5,063,914)     Interest income  $(2,277) $(4,229)Interest expense                                $618,448  $1,954,935 Depreciation and amortization$1,645,030  $3,245,090 Tax (expense) benefit  $-    $- EBITDA*      393,695      131,882 

Add (deduct):
Stock-based compensation  $148,736  $297,473 Adjusted EBITDA*      592,431      429,355           

* EBITDA and adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance.

EBITDA represents net income before interest, taxes, depreciation and amortization. Adjusted EBITDA is defined as EBITDA before unrealized losses (gains) on derivative contracts and stock-based compensation expense. EBITDA and adjusted EBITDA are presented because we believe they provide additional useful information to investors due to the various noncash items during the period. EBITDA and adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation, or as substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:

  • EBITDA and adjusted EBITDA do not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments;
  • EBITDA and adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs;
  • EBITDA and adjusted EBITDA do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments;
  • Although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and adjusted EBITDA do not reflect any cash requirements for such replacements; and
  • Other companies in this industry may calculate EBITDA and adjusted EBITDA differently than Vertex Energy does, limiting its usefulness as a comparative measure.




VERTEX ENERGY, INC.CONSOLIDATED BALANCE SHEETS(UNAUDITED)    June 30,
 2017
 December 31,
 2016
ASSETS     Current assets     Cash and cash equivalents  $458,374  $1,701,435 Escrow - current restricted cash  1,508,447  1,504,723 Accounts receivable, net  9,621,028  10,952,219 Inventory  4,604,679  4,357,958 Prepaid expenses  785,319  2,669,117 Total current assets  16,977,847  21,185,452       Noncurrent assets     Fixed assets, at cost  64,096,722  62,316,808 Less accumulated depreciation  (14,330,153) (12,286,874)Fixed assets, net  49,766,569    50,029,934 Goodwill and other intangible assets, net  15,462,495  15,252,332 Other assets  389,050  518,250 TOTAL ASSETS  $82,595,961  $86,985,968       LIABILITIES, TEMPORARY EQUITY, AND EQUITY     Current liabilities     Accounts payable and accrued expenses  $7,825,113  $9,440,696 Dividends payable  418,571  504,474 Capital leases  33,953  133,153 Current portion of long-term debt, net of unamortized finance costs  1,002,159  9,649,282 Revolving note  2,835,749  2,726,039  Total current liabilities  12,115,545  22,453,644 Long-term liabilities     Long-term debt, net of unamortized finance costs  13,029,635  1,848,111 Contingent Consideration  284,410  — Derivative liability  3,060,551  4,365,992 Total liabilities  28,490,141  28,667,747               COMMITMENTS AND CONTINGENCIES (Note 3)  —  —       TEMPORARY EQUITY     Series B Preferred Stock, $0.001 par value per share;
   10,000,000 shares designated, 3,327,028 and 3,229,409 shares issued and
   outstanding at June 30, 2017 and December 31, 2016, respectively with a
   liquidation preference of $10,313,787 and $10,011,168 at June 30, 2017
   and December 31, 2016, respectively.  6,449,076  5,676,467       Series B-1 Preferred Stock, $0.001 par value per share;
   17,000,000 shares designated, 12,579,522 and 12,282,638 shares issued
   and outstanding at June 30, 2017 and December 31, 2016, respectively
   with a liquidation preference of $19,624,054 and $19,160,915 at June 30,
   2017 and December 31, 2016, respectively.  14,801,147  13,927,788       EQUITY     50,000,000 of total Preferred shares authorized:           Series A Convertible Preferred Stock, $0.001 par value;
   5,000,000 shares designated, 456,608 and 492,716 shares issued and
   outstanding at June 30, 2017 and December 31, 2016, respectively with
   a liquidation preference of $680,346 and $734,147 at June 30, 2017 and
   December 31, 2016, respectively.  457  493       Series C Convertible Preferred Stock, $0.001 par value;
   44,000 shares designated, 31,568 and 31,568 shares issued and
   outstanding at June 30, 2017 and December 31, 2016, respectively with
   a liquidation preference of $3,156,800 and $3,156,800 at June 30, 2017
   and December 31, 2016, respectively.  32  32       Common stock, $0.001 par value per share;
   750,000,000 shares authorized; 32,655,135 and 33,151,391 shares issued
   and outstanding at June 30, 2017 and December 31, 2016, respectively,
   with zero and 1,108,928 shares held in escrow at June 30, 2017 and
   December 31, 2016, respectively.  32,655  33,151 Additional paid-in capital  67,393,536  66,534,971 Accumulated deficit  (34,735,115) (27,958,578)Total Vertex Energy, Inc. stockholders' equity  32,691,565  38,610,069 Non-controlling interest  164,032  103,897 Total Equity  $32,855,597  $38,713,966 TOTAL LIABILITIES, TEMPORARY EQUITY, AND EQUITY  $82,595,961  $86,985,968 


VERTEX ENERGY, INC.CONSOLIDATED STATEMENTS OF OPERATIONS(UNAUDITED)  Three Months Ended June 30, Six Months Ended June 30, 2017   2016   2017   2016Revenues$36,912,779  $24,428,444  $71,683,393  $38,561,048 Cost of revenues (exclusive of depreciation
shown separately below)31,486,599  19,168,398  62,188,153  33,539,526 Gross profit (loss)5,426,180  5,260,046  9,495,240  5,021,522         Operating expenses:       Selling, general and administrative expenses5,359,897  4,714,558  10,589,734  10,210,545 Depreciation and amortization1,645,030  1,553,655  3,245,090  3,196,615 Total operating expenses7,004,927  6,268,213  13,834,824  13,407,160 Loss from operations(1,578,747) (1,008,167) (4,339,584) (8,385,638)Other income (expense):       Interest income2,277  2,486  4,229  2,963 Gain (loss) on sale of assets(26,399) —  (39,499) 9,701,833 Gain (loss) on change in value of derivative liability  384,769  1,645,288  1,305,441  (341,032)Gain (loss) on futures contracts20,570  (317,675) 20,570  (261,759)Interest expense(618,448) (406,019) (1,954,935) (2,321,511)Total other income (expense)(237,231) 924,080  (664,194) 6,780,494 Loss before income tax(1,815,978) (84,087) (5,003,778) (1,605,144)Income tax benefit (expense)—  —  —  117,646 Net loss(1,815,978) (84,087) (5,003,778) (1,487,498)Net income (loss) attributable to non-controlling
interest51,528  (41,427) 60,136  (41,427)Net loss attributable to Vertex Energy, Inc.$(1,867,506) $(42,660) $(5,063,914) $(1,446,071)        Accretion of discount on Series B and B-1
   Preferred Stock(410,097) (471,877) (843,298) (858,535)Accrual of dividends on Series B and B-1
   Preferred Stock(418,571) (5,817,327) (836,208) (6,191,033)Net loss available to common shareholders$(2,696,174) $(6,331,864) $(6,743,420) $(8,495,639)Loss per common share       Basic$(0.08) $(0.21) $(0.21) $(0.29)Diluted$(0.08) $(0.21) $(0.21) $(0.29)Shares used in computing earnings per share       Basic32,350,218  29,765,702  32,650,347  29,535,212 Diluted32,350,218  29,765,702  32,650,347  29,535,212 



VERTEX ENERGY, INC.CONSOLIDATED STATEMENTS OF CASH FLOWSSIX MONTHS ENDED JUNE 30, 2017 AND 2016 (UNAUDITED)     Six Months Ended    June 30,
 2017
   June 30,
 2016
Cash flows from operating activities      Net loss   $(5,003,778) $(1,487,498)Adjustments to reconcile net loss to cash used in operating activities      Stock based compensation expense     297,473  256,164 Depreciation and amortization   3,245,090  3,196,615 Rent paid by common stock   —  244,000 (Gain) loss on sale of assets   39,499  (9,701,833)(Increase) decrease in fair value of derivative liability   (1,305,441) 341,032 Amortization of debt discount and deferred costs   428,159  1,305,707 Changes in operating assets and liabilities      Accounts receivable   1,331,191  (1,047,149)Inventory   (208,027) (224,462)Prepaid expenses   1,883,798  230,614 Accounts payable and accrued expenses   (1,615,582) (4,664,798)Deferred revenue   —  (91,746)Other assets   129,200  (1,303)Net cash used in operating activities   (778,418) (11,644,657)Cash flows from investing activities      Acquisition of Acadiana   (710,350) — Acquisition of Nickco   (1,096,730) — Purchase of fixed assets   (990,096) (2,310,582)Proceeds from sales of Bango assets   —  29,788,114 Costs related to sale of Bango assets   —  (10,792,446)Restricted cash   (3,724) (1,501,792)Proceeds from sale of  fixed assets   223,296  20,900 Net cash provided by (used in) investing activities   (2,577,604) 15,204,194 Cash flows from financing activities      Purchase/Buy back Series B Preferred Stock   —  (11,189,849)Proceeds from issuance of Series B-1 Preferred Stock   —  19,349,756 Issue costs for Series B-1 Preferred Stock   —  (607,890)Payment of debt issuance costs   (1,718,088) — Line of credit (payments) proceeds, net   109,710  444,698 Proceeds from sale of Series C Preferred Stock   —  4,000,000 Proceeds from note payable   14,763,297  5,405,091 Payments on note payable   (11,041,958) (17,753,076)Net cash used in financing activities   2,112,961  (351,270)Net change in cash and cash equivalents   (1,243,061) 3,208,267 Cash and cash equivalents at beginning of the period   1,701,435  765,364 Cash and cash equivalents at end of period   $458,374  $3,973,631 


SUPPLEMENTAL INFORMATION      Cash paid for interest $     746,893    $ 1,006,379 Cash received for income tax benefit $—  $117,646 NON-CASH INVESTING AND FINANCING TRANSACTIONS                                              Conversion of Series A Preferred Stock into common stock 36  120 Conversion of Series B-1 Preferred Stock into common stock $119,440  $— Accretion of discount on Series B and B-1 Preferred Stock $843,298  $858,535 Dividends-in-Kind  accrued on Series B and B-1 Preferred Stock $836,207  $6,191,033 Conversion feature for Series B and B-1 Preferred Stock $—  $2,371,106 Contingent consideration on Nickco acquisition $284,410  $— Common restricted shares for Nickco acquisition $408,000  $— Return of common shares for sale escrow $1,109  $— 

 

CONTACT: Investor Relations Contact: Marlon Nurse, D.M. Senior Vice President 212-564-4700
Categories: State

Denbury Reports Second Quarter 2017 Results; Reduces 2017 Capital Budget; Increases 2017 Production Guidance

8 August 2017 - 5:30am

PLANO, Texas, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”) today announced net income of $14 million, or $0.04 per diluted share, for the second quarter of 2017.  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 second quarter of 2017 differs from the quarter’s GAAP net income due to the exclusion of a $22 million ($14 million after tax) gain from noncash fair value adjustments on commodity derivatives(1) (a non-GAAP measure), 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:

  Quarter Ended($ in millions, except per-share and unit data)  June 30, 2017   March 31, 2017   June 30, 2016 Net income (loss) $14  $22  $(381)Adjusted net income (loss)(1) (non-GAAP measure) 1  (7) 29 Net income (loss) per diluted share 0.04  0.05  (1.03)Adjusted net income (loss) per diluted share(1)(2) (non-GAAP measure) 0.00  (0.02) 0.08 Cash flows from operations 53  24  61 Adjusted cash flows from operations(1) (non-GAAP measure) 65  62  93        Revenues $257  $272  $253 Receipt (payment) on settlements of commodity derivatives (12) (27) 52 Revenues and commodity derivative settlements combined $245  $245  $305        Average realized oil price per barrel (excluding derivative settlements) $47.16  $50.31  $43.38 Average realized oil price per barrel (including derivative settlements) 44.92  45.17  52.61        Total continuing production (BOE/d)(3) 59,774  59,933  62,976 

(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 weighted average diluted shares outstanding of 391.8 million, 389.4 million, and 372.4 million for the three months ended June 30, 2017, March 31, 2017 and June 30, 2016, respectively.
(3) Total continuing production excludes production from the Williston Basin sold during the third quarter of 2016 and other minor property divestitures.

MANAGEMENT COMMENT

Chris Kendall, Denbury’s President and CEO, commented, “I am excited to have the opportunity to lead Denbury, and I believe we are moving this unique company in the right direction.  Our second quarter results demonstrate this, with production on target, cash costs reduced from the first quarter, the successful startup of our Hastings redevelopment project, and closing the Salt Creek acquisition.  The effectiveness of our capital projects and field optimization over the first half of the year enabled us to reduce capital from $300 million to $250 million while still projecting to meet or exceed the midpoint of our original 2017 production guidance, excluding the Salt Creek acquisition.  Considering the addition of Salt Creek, we are raising our full-year guidance to 60,000 to 62,000 barrels of oil equivalent per day.

“We will continue to pursue every reasonable option that improves our profitability and sustainability at the current oil price levels.  While we have made improvements in our cost structure over the past few years, I still see significant opportunities for more cost reductions, and we are currently working toward implementing those measures.

“In the second half of 2017, we expect to complete development of Phase 5 at Bell Creek and expansion of the recycle facility at Oyster Bayou.  We will continue to progress the Grieve and West Yellow Creek developments, as well as our exploitation program.  The investments being deferred are still great projects in the current price environment, but we can easily slide them into 2018.

“I believe that Denbury holds significant value not recognized by the market, ranging from our vast CO2 supply and distribution network, exploitation opportunities in existing fields across the portfolio, potential tertiary development of our giant Cedar Creek Anticline assets in Montana and North Dakota, and even our nonproducing surface land ownership in the Houston area.  A key focus for the Company is bringing this unrecognized value to light.

“Looking forward, I believe Denbury can deliver significant appreciation in value through operational enhancements, our unique portfolio of low-decline oil production, our talented and dedicated team, and continued progress in unlocking additional value from our broad asset base.”

REVIEW OF OPERATING AND FINANCIAL RESULTS

Denbury’s production averaged 59,774 barrels of oil equivalent (“BOE”) per day (“BOE/d”) during the second quarter of 2017, with 97% of production being oil, and with tertiary properties accounting for 61% of overall production.  On a sequential-quarter basis, production was flat with the first quarter of 2017 level.  The Company expects production from the recently completed Salt Creek Field acquisition should add slightly more than 2,000 BOE/d to the Company’s production for the second half of 2017.  Further production information is provided on page 11 of this press release.

Denbury’s average realized oil price per barrel (“Bbl”), excluding derivative settlements, was $47.16 in the second quarter of 2017, compared to $50.31 in the first quarter of 2017, and $43.38 in the prior-year second quarter.  Including derivative settlements, Denbury’s average realized oil price per Bbl was $44.92 in the second quarter of 2017, compared to $45.17 in the first quarter of 2017, and $52.61 in the prior-year second quarter.  The Company’s realized oil price in the second quarter of 2017 was $1.16 per Bbl below NYMEX prices, compared to $1.64 per Bbl below NYMEX in the first quarter of 2017, and $2.18 per Bbl below NYMEX in the second quarter of 2016.

Payments on settlements of commodity derivative contracts were $12 million in the second quarter of 2017, compared to payments of $27 million in the first quarter of 2017, and receipts of $52 million in the second quarter of 2016.  These settlements resulted in a decrease in average net realized prices of $2.16 per BOE in the second quarter of 2017, compared to a decrease of $5.00 per BOE in the first quarter of 2017, and an increase of $8.86 per BOE in the second quarter of 2016.

The Company’s total lease operating expenses in the second quarter of 2017 were $111 million, a decrease of $3 million, or 2%, on an absolute-dollar basis when compared to those in the first quarter of 2017, and an increase of $11 million, or 11%, when compared to the second quarter of 2016.  The increase when compared to the second quarter of 2016 was due primarily to higher power and fuel costs as well as increased workover and other repair activity at certain fields, as workover activity was significantly curtailed during 2016 due to the lower oil price environment.  Lease operating expenses were impacted to a smaller degree by incremental operating costs related to the newly operating Delhi NGL plant.  During the second quarter of 2017, the Company’s CO2 use averaged 608 million cubic feet per day, an increase of 33% when compared to the second quarter of 2016 and an increase of 6% when compared to that in the first quarter of 2017, primarily due to the Hastings redevelopment project.

General and administrative expenses were $26 million in the second quarter of 2017, decreasing $2 million from the first quarter of 2017 and increasing $3 million from the prior-year second quarter, with most of the changes related to compensation items that are variable or performance related.

Interest expense, net of capitalized interest, decreased to $24 million in the second quarter of 2017, compared to $36 million in the second quarter of 2016.  As a result of the Company’s debt exchange transactions completed in May 2016, interest expense in the second quarter of 2017 excludes approximately $13 million of interest on the Company’s 9% Senior Secured Second Lien Notes due 2021, compared to $7 million in the second quarter of 2016, which was recorded as debt for financial reporting purposes and is therefore not reflected as interest expense.  A reconciliation of interest expense is included on page 13 of this press release.

Depletion, depreciation, and amortization (“DD&A”) decreased to $51 million in the second quarter of 2017, compared to $67 million in the second quarter of 2016.  This decrease was primarily driven by a reduction in depletable costs resulting from the full cost pool ceiling test write-downs recognized during 2016.  On a sequential-quarter basis, the Company’s DD&A was relatively unchanged from the first quarter of 2017.

Denbury’s effective tax rate for the second quarter of 2017 was 42% – higher than the Company’s statutory rate of 38% – primarily due to the impact of alternative minimum tax credit usage during the quarter, which also contributed to the $6 million current income tax benefit in the second quarter of 2017.

PROVED RESERVES ADDITIONS

During the second quarter of 2017, the Company added approximately 19 million barrels (“MMBbls”) of proved oil reserves from properties acquired during the first half of 2017.  These reserve additions include approximately 17 MMBbls associated with the Company’s 23% non-operated working interest in Salt Creek Field in Wyoming, and approximately 2 MMBbls associated with the Company’s 48% non-operated working interest in West Yellow Creek Field in Mississippi.  On a combined basis, the proved reserves recorded at these fields replace approximately a year’s worth of the Company’s crude oil production.

BANK CREDIT FACILITY

The Company had a total of $490 million of borrowings outstanding under its $1.05 billion senior secured bank credit facility (the “Facility”) as of June 30, 2017, compared to $301 million outstanding as of December 31, 2016.  The $189 million increase in borrowings is partly due to the Company’s capital expenditure levels, including $89 million of oil and natural gas property acquisitions in the first six months of 2017, with the remaining portion due to $50 million of cash outflows for working capital changes, and repayments of other non-bank debt of $39 million.  After consideration of $62 million of outstanding letters of credit, this leaves the Company with significant borrowing capacity as of June 30, 2017.  Assuming oil prices remain in the upper $40’s per Bbl for the remainder of 2017, and based on currently-projected cash flows and capital spending levels, the Company anticipates that its bank debt at the end of 2017 should be in the range of $425 to $475 million, which would provide more than $500 million of available liquidity under the Company’s bank line.

2017 CAPITAL BUDGET AND ESTIMATED PRODUCTION

In response to lower than anticipated oil prices in the first half of 2017 and to better align the Company’s estimated 2017 cash flow and capital expenditures, the Company today announced that it is reducing its estimated 2017 capital budget, excluding acquisitions and capitalized interest, from $300 million to approximately $250 million.  The capital budget consists of approximately $195 million of tertiary, non-tertiary, and CO2 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 $125 million (50%) has been incurred through the second quarter of 2017.  Despite this reduction in the capital budget, and as a result of the Company’s successful execution of its capital projects in the first half of this year, the Company currently anticipates its 2017 production being on target to meet or exceed the midpoint of its original guidance of 58,000 to 62,000 BOE/d and the 2016 exit rate of roughly 60,000 BOE/d, excluding acquired properties.  With the recent acquisition of Salt Creek Field, the Company has revised its full-year 2017 production guidance to an expected range of 60,000 to 62,000 BOE/d.

CONFERENCE CALL INFORMATION

Denbury management will host a conference call to review and discuss second quarter 2017 financial and operating results, as well as financial and operating guidance for 2017, today, Tuesday, August 8, 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 361973.

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 CO2 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 2017 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 six month periods ended June 30, 2017 and 2016 and the three month period ended March 31, 2017.  All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.

DENBURY RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

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:

  Three Months Ended Six Months Ended  June 30, March 31, June 30,In thousands, except per-share data 2017 2016 2017 2017 2016Revenues and other income          Oil sales $248,317  $244,572  $263,974  $512,291  $429,388 Natural gas sales 2,563  2,096  2,204  4,767  5,083 CO2 sales and transportation fees 6,555  6,622  5,388  11,943  12,894 Interest income and other income 3,749  1,858  3,888  7,637  2,627 Total revenues and other income 261,184  255,148  275,454  536,638  449,992 Expenses          Lease operating expenses 111,318  100,019  113,840  225,158  202,466 Marketing and plant operating expenses 13,877  12,999  14,065  27,942  26,193 CO2 discovery and operating expenses 513  1,071  593  1,106  1,678 Taxes other than income 20,175  19,504  22,440  42,615  39,596 General and administrative expenses 25,789  22,545  28,241  54,030  56,446 Interest, net of amounts capitalized of $8,147, $6,289, $4,654, $12,801 and $12,069, respectively 24,061  36,058  27,178  51,239  78,229 Depletion, depreciation, and amortization 51,152  66,541  51,195  102,347  143,907 Commodity derivatives expense (income) (10,373) 98,209  (24,602) (34,975) 121,035 Gain on debt extinguishment —  (12,278) —  —  (107,269)Write-down of oil and natural gas properties —  479,400  —  —  735,400 Other expenses —  34,688  —  —  36,232 Total expenses 236,512  858,756  232,950  469,462  1,333,913 Income (loss) before income taxes 24,672  (603,608) 42,504  67,176  (883,921)Income tax provision (benefit)          Current income taxes (5,965) —  (13,935) (19,900) (5)Deferred income taxes 16,238  (222,940) 34,909  51,147  (318,055)Net income (loss) $14,399  $(380,668) $21,530  $35,929  $(565,861)           Net income (loss) per common share          Basic $0.04  $(1.03) $0.06  $0.09  $(1.58)Diluted $0.04  $(1.03) $0.05  $0.09  $(1.58)           Weighted average common shares outstanding          Basic 389,904  370,566  389,397  389,652  358,901 Diluted 391,827  370,566  392,997  392,414  358,901 


DENBURY RESOURCES INC.

SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

Reconciliation of net income (loss) (GAAP measure) to adjusted net income (loss) (non-GAAP measure)

Adjusted net income (loss) is a non-GAAP measure provided as a supplement to present an alternative net income (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 income (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.

  Three Months Ended  June 30, March 31,  2017 2016 2017In thousands, except per-share data Amount Per Diluted Share Amount Per Diluted Share Amount Per Diluted ShareNet income (loss) (GAAP measure) $14,399  $0.04  $(380,668) $(1.03) $21,530  $0.05 Adjustments to reconcile to adjusted net income (loss) (non-GAAP measure)              Noncash fair value adjustments on commodity derivatives (1) (22,140) (0.06) 150,235  0.40  (51,542) (0.13)Write-down of oil and natural gas properties (2) —  —  479,400  1.29  —  — Gain on debt extinguishment (3) —  —  (12,278) (0.03) —  — Legal settlements included in other expenses (4) —  —  30,250  0.08  —  — Write-off of debt issuance costs included in interest expense (5) —  —  4,509  0.01  —  — Severance-related payments included in general and administrative expenses (6) —  —  —  —  —  — Transaction costs and other (7) —  —  4,531  0.01  —  — Estimated income taxes on above adjustments to net income (loss) and other discrete tax items (8) 8,609  0.02  (247,178) (0.65) 23,159  0.06 Adjusted net income (loss) (non-GAAP measure) $868  $0.00  $28,801  $0.08  $(6,853) $(0.02)                         


  Six Months Ended  June 30,  2017 2016In thousands, except per-share data Amount Per Diluted Share Amount Per Diluted ShareNet income (loss) (GAAP measure) $35,929  $0.09  $(565,861) $(1.58)Adjustments to reconcile to adjusted net income (loss) (non-GAAP measure)        Noncash fair value adjustments on commodity derivatives (1) (73,682) (0.19) 245,288  0.68 Write-down of oil and natural gas properties (2) —  —  735,400  2.04 Gain on debt extinguishment (3) —  —  (107,269) (0.30)Legal settlements included in other expenses (4) —  —  30,250  0.08 Write-off of debt issuance costs included in interest expense (5) —  —  5,553  0.02 Severance-related payments included in general and administrative expenses (6) —  —  9,315  0.03 Transaction costs and other (7) —  —  5,638  0.02 Estimated income taxes on above adjustments to net income (loss) and other discrete tax items (8) 31,768  0.08  (338,610) (0.94)Adjusted net income (loss) (non-GAAP measure) $(5,985) $(0.02) $19,704  $0.05                  

(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) Full cost pool ceiling test write-downs related to the Company’s oil and natural gas properties.
(3) Gain on extinguishment related to the Company’s debt exchange during the three months ended June 30, 2016 and open-market debt repurchases during the six months ended June 30, 2016.
(4) 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.
(5) Write-off of debt issuance costs associated with the Company’s senior secured bank credit facility, related to the May 2016 redetermination which reduced the Company’s borrowing base, with the six-month period further impacted by reductions in the Company’s lender commitments resulting from the February 2016 amendment.
(6) Severance-related payments associated with the Company’s February-2016 workforce reduction.
(7) Transaction costs related to the Company’s debt exchange during the three months ended June 30, 2016 and a loss on sublease during the six months ended June 30, 2016.
(8) The estimated income tax impacts on adjustments to net income (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 is computed individually based upon the Company’s effective tax rate, as well as the tax impact of a shortfall on the stock-based compensation deduction which totaled <$1 million, <$1 million, and $4 million during the three months ended June 30, 2017, June 30, 2016, and March 31, 2017, respectively, and $4 million and $9 million for the six months ended June 30, 2017 and 2016, respectively.

DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

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.

  Three Months Ended Six Months EndedIn thousands June 30, March 31, June 30, 2017 2016 2017 2017 2016Net income (loss) (GAAP measure) $14,399  $(380,668) $21,530  $35,929  $(565,861)Adjustments to reconcile to adjusted cash flows from operations          Depletion, depreciation, and amortization 51,152  66,541  51,195  102,347  143,907 Deferred income taxes 16,238  (222,940) 34,909  51,147  (318,055)Stock-based compensation 4,835  3,263  4,106  8,941  4,122 Noncash fair value adjustments on commodity derivatives (22,140) 150,235  (51,542) (73,682) 245,288 Gain on debt extinguishment —  (12,278) —  —  (107,269)Write-down of oil and natural gas properties —  479,400  —  —  735,400 Other 781  9,439  1,557  2,338  12,329 Adjusted cash flows from operations (non-GAAP measure) (1) 65,265  92,992  61,755  127,020  149,861 Net change in assets and liabilities relating to operations (12,319) (32,077) (37,493) (49,812) (86,917)Cash flows from operations (GAAP measure) $52,946  $60,915  $24,262  $77,208  $62,944                      

(1) The three and six-month periods ended June 30, 2016 include a $28 million payment to Evolution in connection with the Company’s settlement agreement to resolve all outstanding disputes and claims, and the six-month period ended June 30, 2016 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 and $187 million for the three and six months ended June 30, 2016.

DENBURY RESOURCES INC.
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

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 (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.

  Three Months Ended Six Months Ended  June 30, March 31, June 30,In thousands 2017 2016 2017 2017 2016Receipt (payment) on settlements of commodity derivatives $(11,767) $52,026  $(26,940) $(38,707) $124,253 Noncash fair value adjustments on commodity derivatives (non-GAAP measure) 22,140  (150,235) 51,542  73,682  (245,288)Commodity derivatives income (expense) (GAAP measure) $10,373  $(98,209) $24,602  $34,975  $(121,035)                     


DENBURY RESOURCES INC.

OPERATING HIGHLIGHTS (UNAUDITED)

  Three Months Ended Six Months Ended  June 30, March 31, June 30,  2017 2016 2017 2017 2016Production (daily – net of royalties)          Oil (barrels) 57,867  61,952  58,303  58,084  64,045 Gas (mcf) 11,444  15,328  9,778  10,616  17,299 BOE (6:1) 59,774  64,506  59,933  59,853  66,929 Unit sales price (excluding derivative settlements)          Oil (per barrel) $47.16  $43.38  $50.31  $48.73  $36.84 Gas (per mcf) 2.46  1.50  2.50  2.48  1.61 BOE (6:1) 46.12  42.02  49.35  47.73  35.67 Unit sales price (including derivative settlements)          Oil (per barrel) $44.92  $52.61  $45.17  $45.05  $47.50 Gas (per mcf) 2.46  1.50  2.50  2.48  1.61 BOE (6:1) 43.96  50.88  44.35  44.16  45.87 NYMEX differentials          Gulf Coast region          Oil (per barrel) $(0.78) $(1.22) $(1.42) $(1.09) $(1.78)Gas (per mcf) (0.03) (0.69) 0.09  0.03  (0.46)Rocky Mountain region          Oil (per barrel) $(1.96) $(3.98) $(2.09) $(2.02) $(4.73)Gas (per mcf) (1.42) (0.80) (0.97) (1.19) (0.56)Total company          Oil (per barrel) $(1.16) $(2.18) $(1.64) $(1.39) $(2.81)Gas (per mcf) (0.69) (0.73) (0.57) (0.63) (0.50)


DENBURY RESOURCES INC.

OPERATING HIGHLIGHTS (UNAUDITED)

  Three Months Ended Six Months Ended  June 30, March 31, June 30,Average Daily Volumes (BOE/d) (6:1) 2017 2016 2017 2017 2016Tertiary oil production          Gulf Coast region          Mature properties (1) 7,737  9,415  8,111  7,924  9,540 Delhi 4,965  3,996  4,991  4,978  3,984 Hastings 4,400  4,972  4,288  4,344  5,020 Heidelberg 4,996  5,246  4,730  4,864  5,296 Oyster Bayou 5,217  5,088  5,075  5,146  5,291 Tinsley 6,311  7,335  6,666  6,487  7,617 Total Gulf Coast region 33,626  36,052  33,861  33,743  36,748 Rocky Mountain region          Bell Creek 3,060  3,160  3,209  3,134  3,090 Salt Creek (2) 23  —  —  12  — Total Rocky Mountain region 3,083  3,160  3,209  3,146  3,090 Total tertiary oil production 36,709  39,212  37,070  36,889  39,838 Non-tertiary oil and gas production          Gulf Coast region          Mississippi 1,004  1,017  1,342  1,172  845 Texas 5,002  4,104  4,333  4,669  5,126 Other 460  456  495  477  503 Total Gulf Coast region 6,466  5,577  6,170  6,318  6,474 Rocky Mountain region          Cedar Creek Anticline 15,124  16,325  15,067  15,096  17,052 Other 1,475  1,862  1,626  1,550  1,966 Total Rocky Mountain region 16,599  18,187  16,693  16,646  19,018 Total non-tertiary production 23,065  23,764  22,863  22,964  25,492 Total continuing production 59,774  62,976  59,933  59,853  65,330 Property sales          2016 property divestitures (3) —  1,530  —  —  1,599 Total production 59,774  64,506  59,933  59,853  66,929                 

(1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields.
(2) Includes production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017.
(3) 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.


DENBURY RESOURCES INC.

PER-BOE DATA (UNAUDITED)

  Three Months Ended Six Months Ended  June 30, March 31, June 30,  2017 2016 2017 2017 2016Oil and natural gas revenues $46.12  $42.02  $49.35  $47.73  $35.67 Receipt (payment) on settlements of commodity derivatives (2.16) 8.86  (5.00) (3.57) 10.20 Lease operating expenses (20.46) (17.04) (21.11) (20.78) (16.62)Production and ad valorem taxes (3.36) (2.90) (3.86) (3.61) (2.81)Marketing expenses, net of third-party purchases, and plant operating expenses (1.83) (1.85) (1.87) (1.85) (1.84)Production netback 18.31  29.09  17.51  17.92  24.60 CO2 sales, net of operating and exploration expenses 1.12  0.95  0.89  1.00  0.92 General and administrative expenses (4.74) (3.84) (5.24) (4.99) (4.63)Interest expense, net (4.42) (6.14) (5.04) (4.73) (6.42)Other 1.72  (4.22) 3.33  2.53  (2.16)Changes in assets and liabilities relating to operations (2.26) (5.46) (6.95) (4.60) (7.14)Cash flows from operations 9.73  10.38  4.50  7.13  5.17 DD&A (9.40) (11.34) (9.49) (9.45) (11.81)Write-down of oil and natural gas properties —  (81.67) —  —  (60.37)Deferred income taxes (2.99) 37.98  (6.47) (4.72) 26.11 Gain on debt extinguishment —  2.09  —  —  8.81 Noncash fair value adjustments on commodity derivatives 4.07  (25.59) 9.56  6.80  (20.14)Other noncash items 1.24  3.30  5.89  3.56  5.78 Net income (loss) $2.65  $(64.85) $3.99  $3.32  $(46.45)                     


CAPITAL EXPENDITURE SUMMARY (UNAUDITED) (1)

  Three Months Ended Six Months Ended  June 30, March 31, June 30,In thousands 2017 2016 2017 2017 2016Capital expenditures by project          Tertiary oil fields $43,561  $31,934  $21,207  $64,768  $63,898 Non-tertiary fields 14,332  4,903  18,440  32,772  10,776 Capitalized internal costs (2) 13,071  11,314  13,646  26,717  25,787 Oil and natural gas capital expenditures 70,964  48,151  53,293  124,257  100,461 CO2 pipelines, sources and other 518  144  10  528  152 Capital expenditures, before acquisitions and capitalized interest 71,482  48,295  53,303  124,785  100,613 Acquisitions of oil and natural gas properties 73,001  680  16,098  89,099  904 Capital expenditures, before capitalized interest 144,483  48,975  69,401  213,884  101,517 Capitalized interest 8,147  6,289  4,654  12,801  12,069 Capital expenditures, total $152,630  $55,264  $74,055  $226,685  $113,586                      

(1) Capital expenditure amounts include accrued capital.
(2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.


DENBURY RESOURCES INC.

INTEREST AND FINANCING EXPENSES (UNAUDITED)

  Three Months Ended Six Months Ended  June 30, March 31, June 30,In thousands 2017 2016 2017 2017 2016Cash interest (1) $43,352  $43,148  $42,500  $85,852  $87,793 Interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes (1) (12,588) (7,036) (12,569) (25,157) (7,036)Noncash interest expense (2) 1,444  6,235  1,901  3,345  9,541 Less: capitalized interest (8,147) (6,289) (4,654) (12,801) (12,069)Interest expense, net $24,061  $36,058  $27,178  $51,239  $78,229                      

(1) Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company’s 9% Senior Secured Second Lien Notes due 2021, most of which is accounted for as debt and therefore not reflected as interest for financial reporting purposes.
(2) Noncash interest expense includes $5 million and $6 million during the three and six month periods ending June 30, 2016, respectively, consisting of the write-off of debt issuance costs associated with the Company’s senior secured bank credit facility related to the May 2016 redetermination which reduced the Company’s borrowing base, with the six-month period further impacted by reductions in the Company’s lender commitments resulting from the February 2016 amendment.

SELECTED BALANCE SHEET AND CASH FLOW DATA (UNAUDITED)

  June 30, December 31,In thousands 2017 2016Cash and cash equivalents $3,508  $1,606 Total assets 4,425,341  4,274,578      Borrowings under senior secured bank credit facility $490,000  $301,000 Borrowings under senior secured second lien notes (principal only) (1) 614,919  614,919 Borrowings under senior subordinated notes (principal only) 1,612,603  1,612,603 Financing and capital leases 236,555  251,389 Total debt (principal only) $2,954,077  $2,779,911      Total stockholders’ equity $514,199  $468,448 

(1) Excludes $204 million and $229 million, respectively, of future interest payable on the notes as of June 30, 2017 and December 31, 2016, accounted for as debt for financial reporting purposes.

  Six Months Ended  June 30,In thousands 2017 2016Cash provided by (used in)    Operating activities $77,208  $62,944 Investing activities (221,150) (127,520)Financing activities 145,844  64,309 CONTACT: DENBURY CONTACTS: Mark C. Allen, Senior Vice President and Chief Financial Officer, 972.673.2000 John Mayer, Investor Relations, 972.673.2383
Categories: State

Carrizo Oil & Gas Announces Second Quarter Results

8 August 2017 - 5:30am

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Carrizo Oil & Gas, Inc. (Nasdaq:CRZO) today announced the Company’s financial results for the second quarter of 2017 and provided an operational update, which includes the following highlights:

  • Crude oil production of 33,629 Bbls/d, 40% above the second quarter of 2016
     
  • Total production of 51,019 Boe/d, 23% above the second quarter of 2016
     
  • Net income of $56.3 million, or $0.85 per diluted share, and Net Cash Provided by Operating Activities of $102.7 million
     
  • Adjusted Net Income of $20.0 million, or $0.30 per diluted share, and Adjusted EBITDA of $111.9 million
     
  • Previously-announced acquisition of Delaware Basin properties remains on track to close by mid-August

Carrizo reported second quarter of 2017 net income of $56.3 million, or $0.86 and $0.85 per basic and diluted share, respectively, compared to a net loss of $262.1 million, or $4.46 per basic and diluted share in the second quarter of 2016. The net income for the second quarter of 2017 and net loss for the second quarter of 2016 include certain items typically excluded from published estimates by the investment community. Adjusted net income, which excludes the impact of these items as described in the non-GAAP reconciliation tables included below, for the second quarter of 2017 was $20.0 million, or $0.30 per diluted share compared to $17.1 million, or $0.29 per diluted share in the second quarter of 2016.

For the second quarter of 2017, Adjusted EBITDA was $111.9 million, an increase of 15% from the prior-year quarter due to higher production volumes and commodity prices, partially offset by lower cash receipts for derivative settlements. Adjusted EBITDA and the reconciliation to net income (loss) are presented in the non-GAAP reconciliation tables included below.

Production volumes during the second quarter of 2017 were 4,643 MBoe, or 51,019 Boe/d, an increase of 23% versus the second quarter of 2016. The year-over-year production growth was driven by drilling activity in the Eagle Ford Shale and Delaware Basin, the addition of production from the Sanchez property acquisition in late 2016, and an increase in Marcellus Shale production given improved netbacks. Crude oil production during the second quarter of 2017 averaged 33,629 Bbls/d, an increase of 40% versus the second quarter of 2016; natural gas and NGL production was 74,451 Mcf/d and 4,982 Bbls/d, respectively, during the second quarter of 2017. Second quarter of 2017 production exceeded the high end of Company guidance.

Drilling and completion capital expenditures for the second quarter of 2017 were $148.4 million. More than 85% of the second quarter drilling and completion spending was in the Eagle Ford Shale, with the balance weighted towards the Delaware Basin and Niobrara Formation. Land and seismic expenditures during the quarter were $34.4 million, and were primarily focused in the Permian Basin and Eagle Ford Shale.

The Company's planned acquisition of Delaware Basin properties from ExL Petroleum Management, LLC (“ExL”) remains on track to close by mid-August. While Carrizo continues to be pleased with the performance of the wells on the properties, ExL has encountered some operational delays, and Carrizo now expects fewer wells to be online at closing as compared to its previous guidance. Additionally, as the Company has continued to conduct its due diligence on the land and associated drilling requirements, it has confirmed that the leasehold obligations post closing are not burdensome. As a result, Carrizo has elected to adjust its near-term development plan on the acreage. The Company now plans to release and replace the existing rigs on the acreage earlier than previously planned. While Carrizo believes this will reduce costs and enhance the returns of its development program on the acreage, the adjusted timing is also expected to result in fewer wells being drilled and completed between closing and year-end. As a result of the updated development plan, Carrizo now expects six fewer gross operated wells on these assets to be on production by year-end 2017 relative to its previous guidance.

Primarily as a result of the updated drilling and completion plan on the ExL properties, the Company is reducing its 2017 drilling and completion capital expenditure guidance to $590-$610 million from $620-$640 million previously. The Company is no longer providing guidance for land and seismic capital expenditures given the limited visibility and highly discretionary nature of this spending.

Based on the changes to the planned drilling and completion schedule, Carrizo is decreasing its 2017 oil production guidance to 34,600-34,800 Bbls/d from 35,700-36,000 Bbls/d previously. Using the midpoint of this range, the Company’s 2017 oil production growth guidance equates to 35%. For natural gas and NGLs, Carrizo is adjusting its 2017 guidance to 81-83 MMcf/d and 5,900-6,000 Bbls/d, respectively, from 80-84 MMcf/d and 5,900-6,100 Bbls/d, respectively. For the third quarter of 2017, Carrizo expects oil production to be 35,400-35,800 Bbls/d, and natural gas and NGL production to be 73-77 MMcf/d and 5,900-6,100 Bbls/d, respectively. A full summary of Carrizo’s guidance is provided in the attached tables.

S.P. “Chip” Johnson, IV, Carrizo’s President and CEO, commented on the results, “The second quarter was an eventful one for Carrizo as we announced the largest acquisition in our history, approximately 16,500 net acres in the core of the Delaware Basin. Once the acquisition closes later this month, we will hold positions of scale in the core of two of the highest-return plays in North America, the Eagle Ford Shale and Delaware Basin.

“With the scale we now expect to have in these two plays, our plan is to focus our activity on these regions. As a result, we currently have active divestiture processes for our assets in the Marcellus, Utica, and Niobrara. We believe the resulting streamlined portfolio should lead to improved long-term returns from our development program as well as at the corporate level.

“Given the volatile nature of commodity prices as well as the expected closing of the ExL acquisition, we have materially increased our crude oil hedge position. Since the end of June, we have increased our 2018 crude oil hedge position to 18 MBbls/d from 6 MBbls/d previously, and have also added 6 MBbls/d in 2019. With the downside protection the hedges provide, we believe we can organically de-lever our balance sheet in 2018 even if prices were to weaken from current levels. We also believe we are positioned to run a free cash flow positive program in 2019 and beyond at current strip prices.

“The second quarter was another strong quarter for the Company operationally. Crude oil production increased 17% versus the prior quarter. This was led by the Eagle Ford, which was up 20% sequentially. As a result, crude oil production during the quarter materially outperformed the initial guidance that was provided back in May.”

Operational Update

In the Eagle Ford Shale, Carrizo drilled 23 gross (21.2 net) operated wells during the second quarter and completed 26 gross (21.6 net) wells. Crude oil production from the play was more than 30,600 Bbls/d for the quarter, up 20% versus the prior quarter. At the end of the quarter, Carrizo had 28 gross (26.6 net) operated Eagle Ford wells in progress or waiting on completion, equating to net crude oil production potential of approximately 10,000 Bbls/d. The Company is currently operating three rigs in the Eagle Ford, but plans to move one of its rigs to the Delaware Basin later this quarter. Carrizo expects to drill approximately 93 gross (80 net) operated wells and complete 93 gross (84 net) operated wells in the play during 2017.

Carrizo is continuing to test multiple completion optimization techniques aimed at further enhancing the returns of its development program. The Company remains pleased with the performance of its wells with 200 ft. frac stage spacing, and has expanded its pilot testing of even tighter frac stage spacing. Carrizo currently has approximately 30 wells online that were completed with 180 ft. stage spacing or tighter. The Company has also begun to test slickwater completions with an increased proppant concentration, and has recently completed 13 wells with approximately 2,000 lbs/ft. of proppant. This compares to its standard completion that utilizes approximately 1,600 lbs/ft. of proppant. Additionally, the Company has begun to test the potential for refracs on understimulated wells, such as some of those acquired in the Company's recent purchase from Sanchez Energy Corporation. The Company has pumped its first refrac on these properties, and completion is currently underway. Carrizo plans to provide an update on these pilots once it has sufficient production history.

Carrizo continues to test multiple initiatives aimed at determining the optimal development spacing on its acreage position. Recently, the Company has brought online three additional stagger-stack pilots testing new areas on the western side of its acreage position. The pilots are testing effective lateral spacing of 220-250 ft., and bring the total number of stagger-stack pilots online to 14.

In the Delaware Basin, Carrizo completed two operated wells during the second quarter. Crude oil production from the play was more than 900 Bbls/d for the quarter, down from approximately 1,100 Bbls/d in the prior quarter. While Carrizo is not presently operating a rig in the Delaware Basin, there are currently five operated rigs running on the properties to be acquired from ExL. Based on its updated interpretation of the drilling requirements on the acreage, Carrizo now expects to adjust the activity level to three rigs sooner than previously planned following the closing of the transaction. As a result, Carrizo expects to drill approximately 10 gross (8 net) operated wells and complete 16 gross (13 net) operated wells in the Delaware Basin during 2017. These estimates include 9 gross wells drilled and 13 gross wells completed on the properties to be acquired from ExL following the closing of the transaction.

Carrizo continues to be pleased with the well performance on the ExL properties. Since the beginning of the second quarter, three Wolfcamp A wells and three Wolfcamp B wells have been completed and brought online. Currently, there are 14 gross producing horizontal wells on the acreage with 8 additional wells currently drilling or waiting on completion. See below for the peak 30-day rates from the recent wells:

  • Fowler State Unit 1720 #1 (Wolfcamp A) - 1,591 Boe/d (50% oil, 68% liquids) from an approximate 6,900 ft. lateral
  • Zeman 40 Unit #1 (Wolfcamp B) - 1,766 Boe/d (61% oil, 75% liquids) from an approximate 7,900 ft. lateral
  • Saul 3571 heel (Wolfcamp B) - 1,217 Boe/d (56% oil, 71% liquids) from an approximate 4,000 ft. lateral

Additionally, the Davis 2728 Unit #1 well (Wolfcamp B) was brought online in late June, but has yet to achieve a peak 30-day rate. To date, the well has achieved a peak 15-day rate of 1,315 Boe/d (59% oil, 74% liquids) from an approximate 9,500 ft. lateral. The remaining two wells were brought online in late July and are still cleaning up.

In the Niobrara Formation, Carrizo did not drill or complete any operated wells during the second quarter. Crude oil production from the play was approximately 1,900 Bbls/d for the quarter, down from approximately 2,000 Bbls/d in the prior quarter due to the lack of new wells coming online. Carrizo is not currently budgeting any operated activity in the Niobrara during 2017, but expects to continue participating in non-operated activity within its focus area.

In the Utica and Marcellus, Carrizo did not drill or complete any operated wells during the second quarter. Crude oil production from the Utica was approximately 200 Bbls/d during the quarter, up from approximately 180 Bbls/d in the prior quarter. In the Marcellus, the Company’s production was 44.3 MMcf/d, down from 47.6 MMcf/d in the prior quarter as the Company elected to decrease its production in response to a relatively weaker local market price environment. Carrizo expects to continue to vary its Marcellus production during 2017 based on local market pricing. Carrizo has currently allocated a minimal amount of maintenance capital to the Utica and Marcellus during 2017.

Hedging Activity

Carrizo currently has hedges in place for more than 25% of estimated crude oil production for the remainder of 2017 (based on the midpoint of guidance). For the balance of the year, the Company has swaps covering approximately 10,500 Bbls/d of crude oil at an average fixed price of approximately $53.77/Bbl. For 2018, Carrizo currently has three-way collars covering 18,000 Bbls/d of crude oil with an average floor price of $49.08/Bbl, ceiling price of $60.48/Bbl, and sub-floor price of $39.17/Bbl. The Company has also begun to build its 2019 hedge position. For 2019, Carrizo currently has three-way collars covering 6,000 Bbls/d of crude oil with an average floor price of $47.80/Bbl, ceiling price of $61.45/Bbl, and sub-floor price of $40.00/Bbl.

Carrizo also has hedges in place for more than 20% of estimated natural gas production for the remainder of 2017. For the balance of the year, the Company has swaps covering 20,000 MMBtu/d of natural gas at an average fixed price of $3.30/MMBtu. (Please refer to the attached tables for details of the Company’s derivative contracts.)

Conference Call Details

The Company will hold a conference call to discuss 2017 second quarter financial results on Tuesday, August 8, 2017 at 10:00 AM Central Daylight Time. To participate in the call, please dial (888) 223-4515 (U.S. & Canada) or +1 (303) 223-4383 (Intl.) ten minutes before the call is scheduled to begin. A replay of the call will be available through Tuesday, August 15, 2017 at 12:00 PM Central Daylight Time at (800) 633-8284 (U.S. & Canada) or +1 (402) 977-9140 (Intl.). The reservation number for the replay is 21856090 for U.S., Canadian, and International callers.

A simultaneous webcast of the call may be accessed over the internet by visiting our website at http://www.carrizo.com, clicking on “Upcoming Events”, and then clicking on the “2017 Second Quarter Earnings Call” link. To listen, please go to the website in time to register and install any necessary software. The webcast will be archived for replay on the Carrizo website for 7 days.

Carrizo Oil & Gas, Inc. is a Houston-based energy company actively engaged in the exploration, development, and production of oil and gas from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Niobrara Formation in Colorado, the Utica Shale in Ohio, and the Marcellus Shale in Pennsylvania.

Statements in this release that are not historical facts, including but not limited to those related to capital requirements, free cash flow positive program, the ExL acquisition (including timing and effects thereof), monetization process matters and results, capital expenditure, guidance, rig program,  production, average well returns, the estimated production results and financial performance, effects of transactions, targeted ratios and other metrics, timing, levels of and potential production, downspacing, crude oil production potential and growth, oil and gas prices, drilling and completion activities, drilling inventory, including timing thereof, resource potential, well costs, break-even prices, production mix, development plans, growth, hedging activity, the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, results of the Company’s strategies and other statements that are not historical facts are forward-looking statements that are based on current expectations. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that these expectations will prove correct. Important factors that could cause actual results to differ materially from those in the forward-looking statements include assumptions regarding well costs, estimated recoveries, pricing and other factors affecting average well returns, results of wells and testing, failure of actual production to meet expectations, performance of rig operators, spacing test results, availability of gathering systems, costs of oilfield services, actions by governmental authorities, joint venture partners, industry partners, lenders and other third parties, actions by purchasers or sellers of properties, satisfaction of closing conditions and failure of the acquisition to close, failure of financing transactions to close, purchase price adjustment, integration and other risks and effects of acquisitions, market and other conditions, risks regarding financing, capital needs, availability of well connects, capital needs and uses, commodity price changes, effects of the global economy on exploration activity, results of and dependence on exploratory drilling activities, operating risks, right-of-way and other land issues, availability of capital and equipment, weather, and other risks described in the Company’s Form 10-K for the year ended December 31, 2016 and its other filings with the U.S. Securities and Exchange Commission. There can be no assurance any transaction described in this press release will occur on the terms or timing described, or at all.

(Financial Highlights to Follow)


CARRIZO OIL & GAS, INC.CONSOLIDATED BALANCE SHEETS(In thousands, except share and per share amounts)(Unaudited)       June 30,
2017 December 31, 2016Assets    Current assets    Cash and cash equivalents $2,228  $4,194 Accounts receivable, net  72,401   64,208 Derivative assets  15,283   1,237 Other current assets  5,486   3,349 Total current assets  95,398   72,988 Property and equipment    Oil and gas properties, full cost method    Proved properties, net  1,475,131   1,294,667 Unproved properties, not being amortized  288,997   240,961 Other property and equipment, net  9,031   10,132   Total property and equipment, net  1,773,159   1,545,760 Deposit for pending acquisition of oil and gas properties  75,000   — Other assets  20,262   7,579 Total Assets $1,963,819  $1,626,327      Liabilities and Shareholders’ Equity    Current liabilities    Accounts payable $68,215  $55,631 Revenues and royalties payable  45,860   38,107 Accrued capital expenditures  80,435   36,594 Accrued interest  22,076   22,016 Accrued lease operating expense  14,732   12,377 Derivative liabilities  2,012   22,601 Other current liabilities  25,730   24,633   Total current liabilities  259,060   211,959 Long-term debt  1,521,986   1,325,418 Asset retirement obligations  22,731   20,848 Derivative liabilities  13,652   27,528 Other liabilities  14,559   17,116 Total liabilities  1,831,988   1,602,869 Commitments and contingencies    Shareholders’ equity    Common stock, $0.01 par value, 180,000,000 shares authorized; 65,835,820 issued and outstanding as of June 30, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016  658   651 Additional paid-in capital  1,677,930   1,665,891 Accumulated deficit  (1,546,757)  (1,643,084)Total shareholders’ equity  131,831   23,458 Total Liabilities and Shareholders’ Equity $1,963,819  $1,626,327 


CARRIZO OIL & GAS, INC.CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands, except per share amounts)(Unaudited)          Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017  2016  2017  2016Revenues       Crude oil$142,806  $91,608  $270,898  $159,604 Natural gas liquids 7,786   6,063   15,211   9,503 Natural gas 15,891   9,653   31,729   19,479 Total revenues 166,483   107,324   317,838   188,586         Costs and Expenses       Lease operating 36,048   23,114   65,893   46,789 Production taxes 7,143   4,623   13,351   8,054 Ad valorem taxes 1,073   454   4,040   2,524 Depreciation, depletion and amortization 59,072   51,966   113,454   111,543 General and administrative, net 11,596   19,624   33,299   40,927 (Gain) loss on derivatives, net (26,065)  52,235   (51,381)  41,682 Interest expense, net 21,106   19,010   41,677   37,723 Impairment of proved oil and gas properties —   197,070   —   471,483 Other (income) expense, net 204   1,162   1,178   1,069 Total costs and expenses 110,177   369,258   221,511   761,794         Income (Loss) Before Income Taxes 56,306   (261,934)  96,327   (573,208)Income tax expense —   (192)  —   (313)Net Income (Loss)$56,306  ($262,126) $96,327  ($573,521)        Net Income (Loss) Per Common Share       Basic$0.86  ($4.46) $1.47  ($9.79)Diluted$0.85  ($4.46) $1.46  ($9.79)        Weighted Average Common Shares Outstanding       Basic 65,767   58,806   65,479   58,583 Diluted 65,908   58,806   65,866   58,583 


CARRIZO OIL & GAS, INC.CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY(In thousands, except share amounts)(Unaudited)             Common Stock Additional
Paid-in
Capital
 
Accumulated Deficit
 Total
Shareholders’
Equity
  Shares Amount   Balance as of December 31, 2016 65,132,499  $651  $1,665,891  ($1,643,084) $23,458 Stock-based compensation expense —   —   12,063   —   12,063 Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares 703,321   7   (24)  —   (17)Net income —   —   —   96,327   96,327 Balance as of June 30, 2017 65,835,820  $658  $1,677,930  ($1,546,757) $131,831 


CARRIZO OIL & GAS, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands)(Unaudited)          Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017  2016  2017  2016Cash Flows From Operating Activities       Net income (loss)$56,306  ($262,126) $96,327  ($573,521)Adjustments to reconcile net income (loss) to net cash provided by operating activities       Depreciation, depletion and amortization 59,072   51,966   113,454   111,543 Impairment of proved oil and gas properties —   197,070   —   471,483 (Gain) loss on derivatives, net (26,065)  52,235   (51,381)  41,682 Cash received (paid) for derivative settlements, net (261)  27,300   1,258   78,463 Stock-based compensation expense, net 1,582   10,892   3,596   22,414 Non-cash interest expense, net 983   904   2,074   2,064 Other, net 1,147   1,226   2,767   2,342 Changes in components of working capital and other assets and liabilities-       Accounts receivable (5,345)  673   (8,094)  (1,392)Accounts payable 7,825   (489)  14,486   (19,200)Accrued liabilities 7,804   (7,109)  5,650   (8,776)Other assets and liabilities, net (301)  (371)  (982)  (1,063)Net cash provided by operating activities 102,747   72,171   179,155   126,039 Cash Flows From Investing Activities       Capital expenditures - oil and gas properties (166,876)  (113,872)  (290,625)  (239,861)Acquisitions of oil and gas properties (9,501)  —   (16,533)  — Deposit for pending acquisition of oil and gas properties (75,000)  —   (75,000)  — Proceeds from sales of oil and gas properties, net 829   12,852   18,201   14,637 Other, net (2,062)  (256)  (2,479)  (873)Net cash used in investing activities (252,610)  (101,276)  (366,436)  (226,097)Cash Flows From Financing Activities       Borrowings under credit agreement 638,593   217,005   919,097   290,652 Repayments of borrowings under credit agreement (479,293)  (186,555)  (723,797)  (229,652)Payments of debt issuance costs (4,318)  (1,100)  (4,368)  (1,150)Payment of commitment fee for pending issuance of preferred stock (5,000)  —   (5,000)  — Other, net (282)  (245)  (617)  (552)Net cash provided by financing activities 149,700   29,105   185,315   59,298 Net Decrease in Cash and Cash Equivalents (163)  —   (1,966)  (40,760)Cash and Cash Equivalents, Beginning of Period 2,391   2,158   4,194   42,918 Cash and Cash Equivalents, End of Period$2,228  $2,158  $2,228  $2,158 


CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)

Reconciliation of Net Income (Loss) (GAAP) to Adjusted Net Income (Non-GAAP)

Adjusted net income is a non-GAAP financial measure which excludes certain items that are included in net income (loss), the most directly comparable GAAP financial measure. Items excluded are those which the Company believes affect the comparability of operating results and are typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring.

Adjusted net income is presented because management believes it provides useful additional information to investors for analysis of the Company’s fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Adjusted net income should not be considered in isolation or as a substitute for net income (loss) or any other measure of a company’s financial performance or profitability presented in accordance with GAAP. A reconciliation of the differences between net income (loss) and adjusted net income is presented below. Because adjusted net income excludes some, but not all, items that affect net income (loss) and may vary among companies, our calculation of adjusted net income may not be comparable to similarly titled measures of other companies.

Reconciliation of Diluted Weighted Average Common Shares Outstanding (GAAP) to Adjusted Diluted Weighted Average Common Shares Outstanding (Non-GAAP)

Adjusted diluted weighted average common shares outstanding (“Adjusted Diluted WASO”) is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding (“Diluted WASO”), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments is included in the computation of Adjusted Diluted WASO for purposes of computing diluted adjusted net income per common share.

  Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017  2016  2017  2016 (In thousands, except per share amounts)Net Income (Loss) (GAAP)$56,306  ($262,126) $96,327  ($573,521)Income tax expense —   (192)  —   (313)Income (Loss) Before Income Taxes 56,306   (261,934)  96,327   (573,208)(Gain) loss on derivatives, net (26,065)  52,235   (51,381)  41,682 Cash received (paid) for derivative settlements, net (261)  27,300   1,258   78,463 Non-cash general and administrative expense, net 1,582   10,825   3,596   22,583 Impairment of proved oil and gas properties —   197,070   —   471,483 Other (income) expense, net 204   1,162   1,178   (109)Adjusted income before income taxes 31,766   26,658   50,978   40,894 Adjusted income tax expense (1) (11,722)  (9,517)  (18,811)  (14,599)Adjusted Net Income (Non-GAAP)$20,044  $17,141  $32,167  $26,295         Net Income (Loss) Per Common Share - Diluted (GAAP)$0.85  ($4.46) $1.46  ($9.79)Effect of change from diluted WASO to adjusted diluted WASO —   (0.06)  —   (0.10)Income tax expense —   —   —   (0.01)Income (Loss) Before Income Taxes 0.85   (4.40)  1.46   (9.68)(Gain) loss on derivatives, net (0.40)  0.88   (0.78)  0.70 Cash received (paid) for derivative settlements, net —   0.46   0.02   1.33 Non-cash general and administrative expense, net 0.03   0.18   0.05   0.38 Impairment of proved oil and gas properties —   3.31   —   7.96 Other (income) expense, net —   0.02   0.02   — Adjusted income before income taxes 0.48   0.45   0.77   0.69 Adjusted income tax expense (1) (0.18)  (0.16)  (0.28)  (0.25)Adjusted Net Income Per Common Share - Diluted (Non-GAAP)$0.30  $0.29  $0.49  $0.44         Diluted WASO (GAAP) 65,908   58,806   65,866   58,583 Effect of potentially dilutive instruments —   663   —   643 Adjusted Diluted WASO (Non-GAAP) 65,908   59,469   65,866   59,226 

__________

(1) Adjusted income tax expense is calculated by applying the Company’s estimated annual effective income tax rates applicable to the adjusted income before income taxes, which were 36.9% and 35.7% for the three months ended June 30, 2017 and 2016, respectively, as well as for the six months ended June 30, 2017 and 2016, respectively.

CARRIZO OIL & GAS, INC.
NON-GAAP FINANCIAL MEASURES
(Unaudited)

Reconciliation of Net Income (Loss) (GAAP) to Adjusted EBITDA (Non-GAAP) to Net Cash Provided by Operating Activities (GAAP)

Adjusted EBITDA is a non-GAAP financial measure which excludes certain items that are included in net income (loss), the most directly comparable GAAP financial measure. Items excluded are interest expense, depreciation, depletion and amortization and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring.

Adjusted EBITDA is presented because management believes it provides useful additional information to investors and analysts, for analysis of the Company’s financial and operating performance on a recurring basis and the Company’s ability to internally generate funds for exploration and development, and to service debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Adjusted EBITDA should not be considered in isolation or as a substitute for net income (loss), net cash provided by operating activities, or any other measure of a company’s profitability or liquidity presented in accordance with GAAP. A reconciliation of net income (loss) to adjusted EBITDA to net cash provided by operating activities is presented below. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss), our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flows (Non-GAAP)

Discretionary cash flows are a non-GAAP financial measure which excludes certain items that are included in net cash provided by operating activities, the most directly comparable GAAP financial measure. Items excluded are changes in the components of working capital and other items that the Company believes affect the comparability of operating cash flows such as items that are non-recurring.

Discretionary cash flows are presented because management believes it provides useful additional information to investors for analysis of the Company’s ability to generate cash to internally fund exploration and development, and to service debt. In addition, management believes that discretionary cash flows is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry.

Discretionary cash flows should not be considered in isolation or as a substitute for net cash provided by operating activities or any other measure of a company’s cash flows or liquidity presented in accordance with GAAP. A reconciliation of net cash provided by operating activities to discretionary cash flows is presented below. Because discretionary cash flows excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of discretionary cash flows may not be comparable to similarly titled measures of other companies.

  Three Months Ended
June 30,
 Six Months Ended
June 30,
  2017  2016  2017  2016 (In thousands)Net Income (Loss) (GAAP)$56,306  ($262,126) $96,327  ($573,521)Income tax expense —   (192)  —   (313)Income (Loss) Before Income Taxes 56,306   (261,934)  96,327   (573,208)Depreciation, depletion and amortization 59,072   51,966   113,454   111,543 Interest expense, net 21,106   19,010   41,677   37,723 (Gain) loss on derivatives, net (26,065)  52,235   (51,381)  41,682 Cash received (paid) for derivative settlements, net (261)  27,300   1,258   78,463 Non-cash general and administrative expense, net 1,582   10,825   3,596   22,583 Impairment of proved oil and gas properties —   197,070   —   471,483 Other (income) expense, net 204   1,162   1,178   (109)Adjusted EBITDA (Non-GAAP)$111,944  $97,634  $206,109  $190,160 Interest expense, net (21,106)  (19,010)  (41,677)  (37,723)Non-cash interest expense, net 983   904   2,074   2,064 Other cash and non-cash adjustments, net 943   665   1,589   1,517 Discretionary Cash Flows (Non-GAAP)$92,764  $80,193  $168,095  $156,018 Changes in components of working capital and other 9,983   (8,022)  11,060   (29,979)Net Cash Provided By Operating Activities (GAAP)$102,747  $72,171  $179,155  $126,039 


CARRIZO OIL & GAS, INC.PRODUCTION VOLUMES AND REALIZED PRICES(Unaudited)        Three Months Ended
June 30,
 Six Months Ended
June 30,
   2017  2016  2017  2016Total production volumes -          Crude oil (MBbls)  3,060   2,179   5,656   4,527   NGLs (MBbls)  453   475   859   889   Natural gas (MMcf)  6,775   6,757   13,803   13,130   Total barrels of oil equivalent (MBoe)  4,643   3,780   8,816   7,604          Daily production volumes by product -          Crude oil (Bbls/d)  33,629   23,942   31,250   24,874   NGLs (Bbls/d)  4,982   5,217   4,746   4,882   Natural gas (Mcf/d)  74,451   74,248   76,260   72,141   Total barrels of oil equivalent (Boe/d)  51,019   41,533   48,706   41,779          Daily production volumes by region (Boe/d) -          Eagle Ford  38,055   30,233   35,332   30,602   Delaware Basin  2,151   489   2,284   315   Niobrara  2,694   2,775   2,729   2,980   Marcellus  7,379   6,511   7,652   6,269   Utica and other  740   1,525   709   1,613   Total barrels of oil equivalent (Boe/d)  51,019   41,533   48,706   41,779          Realized prices -          Crude oil ($ per Bbl) $46.67  $42.04  $47.90  $35.26   Crude oil ($ per Bbl) - including cash received (paid) for derivative settlements, net $46.62  $54.57  $48.34  $52.61   NGLs ($ per Bbl) $17.19  $12.76  $17.71  $10.69   Natural gas ($ per Mcf) $2.35  $1.43  $2.30  $1.48   Natural gas ($ per Mcf) - including cash received (paid) for derivative settlements, net $2.33  $1.43  $2.21  $1.48 


CARRIZO OIL & GAS, INC.COMMODITY DERIVATIVE CONTRACTS - AS OF AUGUST 4, 2017(Unaudited)           Crude Oil Derivative Contracts                 Weighted Average Weighted Average Weighted Average    Volume Sub-Floor Price Floor Price Ceiling PricePeriod Type of Contract (in Bbls/d) ($/Bbl) ($/Bbl) ($/Bbl)Q3 2017 Fixed Price Swaps 12,000   $53.71             Q4 2017 Fixed Price Swaps 9,000   $53.86             FY 2018 Three-Way Collars 18,000 $39.17 $49.08 $60.48  Net Sold Call Options 3,388     $71.33           FY 2019 Three-Way Collars 6,000 $40.00 $47.80 $61.45  Net Sold Call Options 3,875     $73.66           FY 2020 Net Sold Call Options 4,575     $75.98


Natural Gas Derivative Contracts               Weighted Average Weighted Average    Volume Floor Price Ceiling PricePeriod Type of Contract (in MMBtu/d) ($/MMBtu) ($/MMBtu)Q3 - Q4 2017 Fixed Price Swaps 20,000 $3.30    Sold Call Options 33,000   $3.00         FY 2018 Sold Call Options 33,000   $3.25         FY 2019 Sold Call Options 33,000   $3.25         FY 2020 Sold Call Options 33,000   $3.50


CARRIZO OIL & GAS, INC.THIRD QUARTER AND FULL YEAR 2017 GUIDANCE SUMMARY         Third Quarter 2017 Full Year 2017Daily Production Volumes -     Crude oil (Bbls/d) 35,400 - 35,800 34,600 - 34,800 NGLs (Bbls/d) 5,900 - 6,100 5,900 - 6,000 Natural gas (Mcf/d) 73,000 - 77,000 81,000 - 83,000 Total (Boe/d) 53,467 - 54,733 54,000 - 54,633      Unhedged Commodity Price Realizations -     Crude oil (% of NYMEX oil) 95.0% - 97.0% N/A NGLs (% of NYMEX oil) 32.0% - 34.0% N/A Natural gas (% of NYMEX gas) 67.0% - 72.0% N/A      Cash received for derivative settlements, net (in millions) $4.5 - $7.5 N/A      Costs and Expenses -     Lease operating ($/Boe) $7.50 - $8.00 $7.00 - $7.50 Production taxes (% of total revenues) 4.50% - 4.75% 4.40% - 4.60% Ad valorem taxes (in millions) $1.9 - $2.4 $8.0 - $9.0 Cash general and administrative, net (in millions) $11.0 - $11.5 $51.0 - $52.0 DD&A ($/Boe) $12.25 - $13.25 $12.50 - $13.50 Interest expense, net (in millions) $20.0 - $21.0 N/A      Capitalized Items -     Drilling and completion capital expenditures (in millions) N/A $590.0 - $610.0 Capitalized interest (in millions) $9.5 - $10.0 N/A


CONTACT: Source: Carrizo Oil & Gas, Inc Contact: Jeffrey P. Hayden, CFA, VP - Investor Relations (713) 328-1044 Kim Pinyopusarerk, Manager - Investor Relations (713) 358-6430
Categories: State

Tesco Corporation Reports Second Quarter 2017 Results

8 August 2017 - 5:00am
  • Liquidity of $72.5 million and no debt at the end of the second quarter, after funding approximately $5 million of working capital growth during the second quarter
  • Reported U.S. GAAP diluted EPS was a loss of $(0.26) on a net loss of $12.1 million and adjusted EPS was a loss of $(0.25) on an adjusted net loss of $11.6 million, after $0.5 million in charges
  • Adjusted EBITDA loss improved 17% to ($3.9) million in the second quarter
  • Revenue increased by 9% to $40.1 million, driven by stronger Tubular Services in North America

HOUSTON, Aug. 08, 2017 (GLOBE NEWSWIRE) -- Tesco Corporation ("TESCO" or the "Company") (NASDAQ:TESO) today reported second quarter 2017 financial and operating results.

Second Quarter Operating Results

Fernando Assing, TESCO's President and Chief Executive Officer, commented, "Our business continues to improve and the second quarter results reflect the benefit of the stronger U.S. land market and growing CDS sales as customers continue to recognize the benefits of drilling automation. Despite some new product shipping delays to the third quarter, revenue and EBITDA both improved sequentially."

TESCO reported revenue of $40.1 million in the second quarter of 2017, up from $36.7 million, or 9%, in the first quarter of 2017, and up from $33.6 million, or 19%, in the second quarter of 2016. The sequential increase in revenue was primarily from higher land tubular services and CDS sales in the U.S.

TESCO reported a U.S. GAAP net loss of $12.1 million, or $(0.26) per share, in the second quarter of 2017. Adjusted net loss for the quarter was $11.6 million, or $(0.25) per share, excluding special items, consisting primarily of charges related to restructuring costs. This compares to a U.S. GAAP net loss of $13.7 million, or $(0.29) per diluted share, in the first quarter of 2017, and a U.S. GAAP net loss of $18.9 million, or (0.47) per diluted share, in the second quarter of 2016. Adjusted net loss in the first quarter of 2017 was $13.4 million, or $(0.29) per diluted share, and in the second quarter of 2016 was $15.8 million, or $(0.39) per diluted share.

Adjusted EBITDA loss was $3.9 million in the second quarter of 2017 compared to an adjusted EBITDA loss of $4.7 million in the first quarter of 2017 on a 9% revenue increase. For the second quarter of 2017, U.S. GAAP operating loss was $11.5 million and adjusted operating loss was $11.4 million. This compares to the first quarter 2017 U.S. GAAP operating loss of $12.9 million and adjusted operating loss of $12.1 million, which excluded $0.8 million of charges.

Cash and cash equivalents as of June 30, 2017 decreased from the first quarter of 2017 by $10.6 million to $72.5 million primarily due to higher accounts receivable and inventory. Accounts receivable was impacted by approximately $4 million due to payment delays on certain top drive shipments and slower collections than anticipated from several larger customers. These balances should be collected in the third quarter of 2017. In addition, inventory increased by approximately $3 million due to two top drive orders shifting to the third quarter of 2017 and higher aftermarket inventory to support recertification projects shipping in the third quarter of 2017.

Free cash flow was a use of cash of $10.5 million before approximately $0.3 million of restructuring payments.

Products Segment

  • Revenue in the second quarter was $19.5 million, a $0.6 million, or 3%, decrease from the first quarter of 2017 and a $1.1 million, or 5%, decrease from the second quarter of 2016. This decline was primary due to a reduction in new product sales.
    •  Product sales in the second quarter of 2017 included seven top drive units (4 new and 3 used), compared to six units (5 new and 1 used) sold in the first quarter of 2017, and eight units (5 new and 3 used) sold in the second quarter of 2016. We did not sell any new catwalks in the second quarter of 2017 compared to one new catwalk in the first quarter of 2017.
    • There were 113 top drives in our rental fleet at the end of the second quarter with a utilization of 15% compared to 14% for the first quarter.


  • U.S. GAAP operating loss before adjustments in the Products segment for the second quarter of 2017 was $0.4 million, or (2)% of revenue, a 0.5 million, or 56%, improvement from the first quarter of 2017. Second quarter operating loss and operating margin after adjustments were $0.6 million and (3)% respectively, a 1% increase from the first quarter of 2017.

  • At June 30, 2017, the top drive backlog was 5 units with a total potential value of $4.2 million, compared to 5 units at March 31, 2017, with a potential value of $4.1 million. This compares to a backlog of 9 units at June 30, 2016, with a potential value of $8.5 million. The trend towards short delivery times and intra-quarter book-and-ship transactions is expected to continue throughout 2017. Today, our top drive backlog stands at 6 units with a potential value of $5.1 million.

Tubular Services Segment

  • Revenue in the second quarter of 2017 was $20.6 million, a 24% increase from the first quarter of 2017 of $16.6 million and a 58% increase from the second quarter of 2016 of $13.0 million. This sequential increase was driven by higher U.S. land activity and greater CDS sales in the U.S.

  • U.S. GAAP operating loss before adjustments in the Tubular Services segment in the second quarter of 2017 was $4.5 million, a $1.2 million improvement from the first quarter of 2017. Second quarter operating loss and operating margin after adjustments were $4.1 million and (20)%, respectively, compared to $5.1 million and (31)% in the first quarter of 2017. The sequential improvement was driven by the higher CDS sales as certain reactivation costs offset the increased activity benefit in U.S. land.

Other Segments and Expenses

  • Research and Engineering U.S. GAAP costs for the second quarter of 2017 were $0.8 million, compared to $0.8 million in the first quarter of 2017 and $1.4 million in the second quarter of 2016. We continue to invest in the development, commercialization, and enhancement of our proprietary technologies.

  • Corporate and Other U.S. GAAP costs for the second quarter of 2017 were $5.8 million, a $0.3 million, or 5%, increase from the first quarter of 2017 and flat with the second quarter of 2016. This increase was driven by higher-personnel related expenses and seasonal marketing costs.

  • Net foreign exchange loss in the second quarter of 2017 was $0.5 million, compared to net foreign exchange gain of $0.1 million in the first quarter of 2017 and $0.0 million in the second quarter of 2016, primarily from the currencies in Argentina and Russia weakening.

  • The effective tax rate for the second quarter of 2017 was a 3% expense compared to an 8% expense in the first quarter of 2017 and a 1% benefit in the second quarter of 2016.

  • Capital expenditures were $0.8 million in the second quarter of 2017, primarily for tubular services equipment and infrastructure projects, a $0.1 million increase from the first quarter of 2017 and a $0.3 million, or 27%, decrease from the second quarter of 2016.

Outlook

While there is some market speculation that U.S. rig count could decline in the second half of 2017, we have not seen strong evidence yet of any significant activity decline by our customers. We have also seen signs of upcoming activity improvements in certain international markets, both in land and offshore. In the third quarter of 2017, we expect overall revenue to increase sequentially primarily from growth in Tubular Services and new product sales. Cash levels are expected to remain approximately flat over the second quarter ending balance as EBITDA losses are expected to continue to decrease and working capital is reduced from the second quarter levels.

"During the second quarter, we continued to experience growth and improved profitability from several key initiatives, primarily CDS™ Evolution adoption and CDS sales. Customer interest in automated land tubular service offerings continues to increase and is expected to accelerate as our cementing accessories are deployed,” Mr. Assing said.

“As market uncertainty and pricing pressure increases in a lower-for-longer environment, it will be more important to continue to gain market share through technology deployments. As we look ahead to the third and fourth quarters, we see opportunities that have the potential to generate revenue and EBITDA improvements while keeping cash levels near current levels. The approximate $8.4 million invested in working capital and capital expenditures in the first half of 2017 positions us to continue to grow revenue in the second half of 2017 and to get closer to our goal of reaching breakeven EBITDA.”

“Tesco has invested in and remains well positioned in key international markets and sustained international activity and market share gains will be key to offset any potential North America market slow down. We continue to benefit from our strong balance sheet and will continue to pursue additional opportunities to invest our cash to fund growth and incremental profitability to outperform the market" Mr. Assing concluded.

Conference Call

The Company will conduct a conference call to discuss its results for the second quarter 2017 on August 8 at 9:00 a.m. Central Time. To participate in the conference call, dial 1-844-356-6029 inside the U.S. or 1-209-905-5912 outside the U.S. approximately 10 minutes prior to the scheduled start time. The conference call and all questions and answers will be recorded and made available until August 15. To listen to the replay, call 1-855-859-2056 inside the U.S. or 1-404-537-3406 outside the U.S. and enter conference ID 53211689#.

The conference call will be webcast live as well as by replay at the Company's web site, www.tescocorp.com. Listeners may access the call through the "Conference Calls" link in the "Investor Relations" section of the site.

Tesco Corporation is a global leader in the design, manufacture and service of technology based solutions for the upstream energy industry. The Company's strategy is to change the way people drill wells by delivering safer and more efficient solutions that add real value by reducing the costs of drilling for and producing oil and natural gas. TESCO® is a registered trademark in the United States, Canada and the European Union. Casing Drive System™, CDS™, is a trademark in the United States and Canada.

For further information please contact:
Chris Boone (713) 359-7000
Tesco Corporation


Caution Regarding Forward-Looking Information

This news release contains forward-looking statements within the meaning of Canadian and United States securities laws, including the United States Private Securities Litigation Reform Act of 1995. From time to time, our public filings, press releases and other communications (such as conference calls and presentations) will contain forward-looking statements. Forward-looking information is often, but not always identified by the use of words such as "anticipate," "believe," "expect," "plan," "intend," "forecast," "target," "project," "may," "will," "should," "could," "estimate," "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to expectations of our prospects, future revenue, earnings, activities and technical results.

Forward-looking statements and information are based on current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. The forward-looking statements in this news release are made as of the date it was issued and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that outcomes implied by forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements.

These risks and uncertainties include, but are not limited to, the impact of: levels and volatility of oil and gas prices; cyclical nature of the energy industry and credit risks of our customers; fluctuations of our revenue and earnings; operating hazards inherent in our operations; changes in governmental regulations, including those related to the climate and hydraulic fracturing; consolidation or loss of our customers; the highly competitive nature of our business; technological advancements and trends in our industry, and improvements in our competitors’ products; global economic and political environment, and financial markets; terrorist attacks, natural disasters and pandemic diseases; our presence in international markets, including political or economic instability, currency restrictions and trade and economic sanctions; cybersecurity incidents; protecting and enforcing our intellectual property rights; changes in, or our failure to comply with, environmental regulations; failure of our manufactured products and claims under our product warranties; availability of raw materials, component parts and finished products to produce our products, and our ability to deliver the products we manufacture in a timely manner; retention and recruitment of a skilled workforce and key employees; and ability to identify and complete acquisitions. These risks and uncertainties may cause our actual results, levels of activity, performance or achievements to be materially different from those expressed or implied by any forward-looking statements. When relying on our forward-looking statements to make decisions, investors and others should carefully consider the foregoing factors and other uncertainties and potential events.

Copies of our Canadian public filings are available through www.tescocorp.com and on SEDAR at www.sedar.com. Our U.S. public filings are available at www.sec.gov and through www.tescocorp.com.

The risks included here are not exhaustive. Refer to "Part I, Item 1A - Risk Factors" in our most recent Annual Report on Form 10-K for further discussion regarding our exposure to risks. Additionally, new risk factors emerge from time to time and it is not possible for us to predict all such factors, nor to assess the impact such factors might have on our business or the extent to which any factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statements. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements as a prediction of actual results.


TESCO CORPORATIONCondensed Consolidated Statements of Income(in millions, except per share information)  Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (Unaudited)Revenue$40.1  $33.6  $76.9  $69.0 Operating expenses       Cost of sales and services44.8  43.7  87.3  90.5 Selling, general and administrative6.0  7.7  12.4  14.0 Long-lived asset impairments—  —  —  35.5 Research and engineering0.8  1.4  1.6  3.0  51.6  52.8  101.3  143.0 Operating loss(11.5) (19.2) (24.4) (74.0)Interest expense (income), net—  (0.2) —  0.2 Foreign exchange loss0.5  —  0.3  1.2 Other expense (income)(0.2) 0.1  (0.3) — Loss before income taxes(11.8) (19.1) (24.4) (75.4)Income tax provision (benefit)0.3  (0.2) 1.4  0.3 Net loss$(12.1) $(18.9) $(25.8) $(75.7)Loss per share:       Basic$(0.26) $(0.47) $(0.55) $(1.90)Diluted$(0.26) $(0.47) $(0.55) $(1.90)Weighted average number of shares:       Basic46.7  40.4  46.7  39.8 Diluted46.7  40.4  46.7  39.8 



TESCO CORPORATIONCondensed Consolidated Balance Sheets(in millions)  June 30,
 2017
 December 31,
 2016
 (Unaudited)  Assets   Current assets   Cash and cash equivalents$72.5  $91.5 Accounts receivable trade, net43.6  33.3 Inventories, net74.8  76.2 Other current assets19.6  20.0 Total current assets210.5  221.0 Property, plant and equipment, net111.3  120.7 Other assets2.6  2.6 Total assets$324.4  $344.3 Liabilities and Shareholders’ Equity   Current liabilities   Accounts payable$17.2  $13.5 Accrued and other current liabilities16.4  17.1 Income taxes payable2.4  2.1 Total current liabilities36.0  32.7 Deferred income taxes0.3  0.4 Other liabilities1.7  1.6 Shareholders' equity286.4  309.6  Total liabilities and shareholders’ equity$324.4  $344.3 



TESCO CORPORATIONConsolidated Statement of Cash Flows(in millions)   Six Months Ended June 30, 2017 2016 (Unaudited)Operating Activities  Net loss$(25.8) $(75.7)Adjustments to reconcile net loss to cash used in operating activities:   Depreciation and amortization11.8  15.2 Stock compensation expense2.7  2.1 Bad debt expense (recovery)(0.9) 0.6 Deferred income taxes(0.1) (0.3)Amortization of financial items—  0.3 Gain on sale of operating assets(1.2) (0.4)Long-lived asset impairments—  35.5 Changes in the fair value of contingent earn-out obligations—  (0.1)Changes in operating assets and liabilities:   Accounts receivable trade, net(9.2) 24.6 Inventories, net1.4  6.7 Prepaid and other current assets0.3  4.3 Accounts payable and accrued liabilities1.0  (14.8)Income taxes payable(0.1) 0.9 Other non-current assets and liabilities, net(0.3) (0.2)Net cash used in operating activities(20.4) (1.3)Investing Activities   Additions to property, plant, equipment and intangibles(1.5) (1.9)Proceeds on sale of operating assets2.2  2.5 Net cash provided by investing activities0.7  0.6 Financing Activities   Proceeds from stock issuance—  47.0 Stock issuance costs—  (0.3)Changes in restricted cash0.7  — Net cash provided by financing activities0.7  46.7 Change in cash and cash equivalents(19.0) 46.0 Cash and cash equivalents, beginning of period91.5  51.5 Cash and cash equivalents, end of period$72.5  $97.5 Supplemental cash flow information   Cash payments for interest$—  $0.2 Cash payments for income taxes, net of refunds1.3  0.9 Property, plant and equipment accrued in accounts payable0.8  1.3 




TESCO CORPORATIONSegment Results(in millions, except per share information)  Three Months Ended
June 30,
 Three Months Ended
March 31,
 Six Months Ended
June 30,
 2017 2016 2017 2017 2016Segment revenue(Unaudited)Products         Products sales$5.3  $8.4  $5.9  $11.3  $12.6 Rental services5.7  5.9  5.3  10.9  12.5 Aftermarket sales and services8.5  6.3  8.9  17.4  12.1  19.5  20.6  20.1  39.6  37.2 Tubular Services         Land12.2  7.8  10.3  22.6  18.6 Offshore4.5  4.4  4.2  8.7  11.8 CDS, Parts & Accessories3.9  0.8  2.1  6.0  1.4  20.6  13.0  16.6  37.3  31.8           Consolidated revenue$40.1  $33.6  $36.7  $76.9  $69.0           Segment operating loss:         Products$(0.4) $(2.7) $(0.9) $(1.3) $(41.9)Tubular Services(4.5) (9.3) (5.7) (10.2) (15.3)Research and Engineering(0.8) (1.4) (0.8) (1.6) (3.0)Corporate and Other(5.8) (5.8) (5.5) (11.3) (13.8)Consolidated operating loss$(11.5) $(19.2) $(12.9) $(24.4) $(74.0)          U.S. GAAP consolidated net loss$(12.1) $(18.9) $(13.7) $(25.8) $(75.7)U.S. GAAP loss per share (diluted)$(0.26) $(0.47) $(0.29) $(0.55) $(1.90)          Adjusted EBITDA(a) (as defined)$(3.9) $(7.5) $(4.7) $(8.6) $(15.2)

________________________
(a)       See explanation of Non-GAAP measure below.

Non-GAAP Measures

Our management reports our financial statements in accordance with United States Generally Accepted Accounting Principles ("U.S. GAAP") but evaluates our performance based on non-GAAP measures as defined under the SEC's Regulation G. These measures may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Non-GAAP measures should not be considered in isolation or as substitutes for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.

 Our management uses Non-GAAP measures:

  • to assess the performance of the Company’s operations;
  • as a method used to evaluate potential acquisitions;
  • in presentations to our Board of Directors to enable them to have the same consistent measurement basis of operating performance used by management; and
  • in communications with investors, analysts, lenders, and others concerning our financial performance.




TESCO CORPORATIONNon-GAAP Measure - Adjusted EBITDA (1)(in millions)  Three Months Ended
June 30,
 Three Months Ended
March 31,
 Six Months Ended
June 30,
 2017 2016 2017 2017 2016Net loss under U.S. GAAP$(12.1) $(18.9) $(13.7) $(25.8) $(75.7)Income tax expense (benefit)0.4  (0.2) 1.0  1.4  0.3 Depreciation and amortization5.8  7.2  6.0  11.8  15.2 Interest expense—  0.2  0.1  0.1  0.7 Stock compensation expense-non-cash1.5  1.0  1.2  2.7  2.1 Severance & restructuring charges0.5  2.9  0.7  1.2  5.9 Bad debt from certain accounts(0.4) —  —  (0.4) 0.3 Foreign exchange loss (gain)0.4  —  (0.1) 0.3  1.2 Asset sale reserves—  (0.7) —  —  (3.0)Warranty & legal reserves—  0.7  0.1  0.1  0.7 Inventory reserves—  0.2  —  —  1.3 Long-lived asset impairments—  —  —  —  35.5 Credit facility costs—  0.1  —  —  0.3 Adjusted EBITDA$(3.9) $(7.5) $(4.7) $(8.6) $(15.2)

(1) Adjusted EBITDA consists of earnings (net income or loss) attributable to TESCO before interest expense, income tax expense (benefit), depreciation and amortization, severance and restructuring charges, foreign exchange gains or losses, noted income or charges from certain accounts, non-cash stock compensation, non-cash impairments and other non-cash items.

We believe Adjusted EBITDA is useful to an investor in evaluating our operating performance because:

  • it is widely used by investors in our industry to measure a company's operating performance without regard to items such as interest expense, income tax expense (benefit), depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, severance and restructuring charges, financing methods, capital structure and the method by which assets were acquired;
  • it helps investors more meaningfully evaluate and compare the results of our operations from period to period by removing the impact of our capital structure (primarily interest), merger and acquisition transactions (primarily gains/losses on sale of a business), and asset base (primarily depreciation and amortization) and actions that do not affect liquidity (stock compensation expense and non-cash impairments) from our operating results; and
  • it helps investors identify items that are within our operational control. Depreciation and amortization charges, while a component of operating income, are fixed at the time of the asset purchase in accordance with the depreciable lives of the related asset and as such are not a directly controllable period operating charge.




TESCO CORPORATIONReconciliation of GAAP Net Income (Loss) to Adjusted Net Income (Loss) (2) (in millions except earnings per share data)  Three Months Ended
June 30,
 Three Months Ended
March 31,
 Six Months Ended
June 30,
 2017 2016 2017 2017 2016Net loss under U.S. GAAP$(12.1) $(18.9) $(13.7) $(25.8) $(75.7)Severance & restructuring charges0.4  2.6  0.6  1.0  5.6 Bad debt on certain accounts(0.4) —  —  (0.4) 0.3 Certain foreign exchange losses (gains)0.7  0.2  (0.4) 0.3  1.3 Asset sale reserves—  (0.7) —  —  (3.0)Warranty & legal reserves—  0.7  0.1  0.1  0.7 Inventory reserves—  0.2  —  —  1.3 Long-lived asset impairments—  —  —  —  35.5 Credit facility costs—  0.1  —  —  0.3 Certain tax-related charges(0.2) —  —  (0.2) — Adjusted net loss$(11.6) $(15.8) $(13.4) $(25.0) $(33.7)          Diluted loss per share under U.S. GAAP$(0.26) $(0.47) $(0.29) $(0.55) $(1.90)Severance & restructuring charges0.01  0.07  0.01  0.02  0.14 Bad debt on certain accounts(0.01) —  —  (0.01) 0.01 Certain foreign exchange losses (gains)0.01  —  (0.01) 0.01  0.03 Asset sale reserves—  (0.01) —  —  (0.08)Warranty & legal reserves—  0.02  —  —  0.02 Inventory reserves—  —  —  —  0.03 Long-lived asset impairments—  —  —  —  0.89 Credit facility costs—  —  —  —  0.01 Certain tax-related charges—  —  —  —  — Adjusted diluted loss per share$(0.25) $(0.39) $(0.29) $(0.53) $(0.85)

(2) Adjusted net income (loss) is a non-GAAP measure comprised of net income attributable to TESCO excluding the impact of severance and restructuring charges, non-cash impairments, noted income or charges from certain accounts and certain tax-related charges.

We believe adjusted net income (loss) is useful to an investor in evaluating our operating performance because:

  • is a consistent measure of the underlying results of the Company’s business by excluding items that could mask the Company's operating performance;
  • it is widely used by investors in our industry to measure a company's operating performance, especially when comparing those results with previous and subsequent periods or forecasting performance for future periods, primarily because management views the excluding items to be outside of the Company's normal operating results; and
  • it helps investors identify and analyze underlying trends in the business.




TESCO CORPORATIONNon-GAAP Measure - Adjusted Operating Income (Loss)(3)(in millions)  Three Months Ended June 30, 2017 Products Tubular
Services
 Research &
Engineering
 Corporate
& Other
 TotalOperating loss under U.S. GAAP$(0.4) $(4.5) $(0.8) $(5.8) $(11.5)Severance & restructuring charges0.2  0.4  (0.1) —  0.5 Bad debt on certain accounts(0.4) —  —  —  (0.4)Adjusted operating loss$(0.6) $(4.1) $(0.9) $(5.8) $(11.4)


 Three Months Ended June 30, 2016 Products Tubular
Services
 Research &
Engineering
 Corporate
& Other
 TotalOperating loss under U.S. GAAP$(2.7) $(9.3) $(1.4) $(5.8) $(19.2)Severance & restructuring charges0.8  2.0  0.1  —  2.9 Warranty & legal reserves—  0.7  —  —  0.7 Asset sale reserves(0.6) (0.1) —  —  (0.7)Inventory reserves0.1  0.1  —  —  0.2 Credit facility costs—  —  —  0.1  0.1 Adjusted operating loss$(2.4) $(6.6) $(1.3) $(5.7) $(16.0)


 Three Months Ended March 31, 2017 Products Tubular
Services
 Research
& Engineering
 Corporate
& Other
 TotalOperating loss under U.S. GAAP$(0.9) $(5.7) $(0.8) $(5.5) $(12.9)Severance & executive retirement charges0.1  0.6  —  —  0.7Warranty & legal reserves0.1  —  —  —  0.1Adjusted operating loss$(0.7) $(5.1) $(0.8) $(5.5) $(12.1)


 Six Months Ended June 30, 2017 Products Tubular
Services
 Research
& Engineering
 Corporate
& Other
 TotalOperating loss under U.S. GAAP$(1.3) $(10.2) $(1.6) $(11.3) $(24.4)Severance & restructuring charges0.3  1.0  (0.1) —  1.2 Bad debt on certain accounts(0.4) —  —  —  (0.4)Warranty & legal reserves0.1  —  —  —  0.1 Adjusted operating loss$(1.3) $(9.2) $(1.7) $(11.3) $(23.5)


 Six Months Ended June 30, 2016 Products Tubular
Services
 Research &
Engineering
 Corporate
& Other
 TotalOperating loss under U.S. GAAP$(41.9) $(15.3) $(3.0) $(13.8) $(74.0)Severance & restructuring charges1.4  4.3  —  0.2  5.9 Bad debt on certain accounts0.3  —  —  —  0.3 Asset sale reserves(0.8) (2.2) —  —  (3.0)Warranty & legal reserves—  0.7  —  —  0.7 Inventory reserves1.0  0.3  —  —  1.3 Long-lived asset impairments33.6  —  —  1.9  35.5 Credit facility costs—  —  —  0.1  0.1 Adjusted operating loss$(6.4) $(12.2) $(3.0) $(11.6) $(33.2)

(3) Adjusted operating income (loss) is a non-GAAP measure comprised of operating income (loss) attributable to TESCO excluding the impact of severance and restructuring charges, non-cash impairments and noted income or charges from certain accounts. Management uses adjusted operating income (loss) as a measure of the performance of the Company’s operations.

We believe adjusted operating income (loss) is useful to an investor in evaluating our operating performance because:

  • it is a consistent measure of the underlying results of the Company’s business by excluding items that could mask the Company's operating performance;
  • it is widely used by investors in our industry to measure a company's operating performance, especially when comparing those results with previous and subsequent periods or forecasting performance for future periods, primarily because management views the excluding items to be outside of the Company's normal operating results; and
  • it helps investors identify and analyze underlying trends in the business.

 

TESCO CORPORATIONNon-GAAP Measure - Free Cash Flow(4)(in millions)   Three Months Ended
June 30, 2017
 Three Months Ended
March 31, 2017
 Six Months Ended
June 30, 2017
Net cash used in operating activities $(11.5) $(8.9) $(20.4)Capital expenditures (0.8) (0.7) (1.5)Proceeds on asset sales 1.8  0.4  2.2 Free cash flow (10.5) (9.2) (19.7)Severance & restructuring payments (0.3) (1.1) (1.4)Adjusted free cash flow $(10.2) $(8.1) $(18.3)

(4) Free cash flow is a non-GAAP measure comprised of cash flow from operations, capital expenditures and proceeds on asset sales. Adjusted free cash flow excludes the impact of severance and restructuring payments.

We believe free cash flow is useful to an investor in evaluating our operating performance because:

  • it measures the Company's ability to generate cash;
  • it is widely used by investors in our industry to measure a company's cash flow performance; and
  • it helps investors identify and analyze underlying trends in the business.

 

 

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