November 14, 2016 - 4:38 PM EST
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Penn Virginia Corporation Announces Third Quarter 2016 Results

HOUSTON, TX--(Marketwired - November 14, 2016) - Penn Virginia Corporation ("Penn Virginia" or the "Company") (OTC PINK: PVAC) today reported financial and operational results for the three months ended September 30, 2016.

Key Highlights for Third Quarter 2016

  • Penn Virginia successfully completed its restructuring process on September 12, 2016 with 100 percent of the unsecured notes and general unsecured claims converted into newly-issued common stock. The new common stock is currently trading on the OTC Pink marketplace under the symbol "PVAC". The Company expects the new common stock to trade on the OTCQX by the end of November in anticipation of subsequently listing on a national securities exchange.
  • Total production for the quarter ended September 30, 2016 was 979 thousand barrels of oil equivalent (MBOE) or 10,629 BOE per day (BOEPD) with 70% of production comprised of oil.
  • Penn Virginia intends to restart Eagle Ford shale drilling by the end of November initially focused on:
    • Sable 6-H, the third well of a three-well pad located two-and-a-half miles southwest of, and on-strike with, the Company's successful three-well Hawg Hunter pad, and completing all three Sable wells before year-end 2016.
    • Following Sable, management anticipates drilling the three-well Axis pad in the fourth quarter of 2016 with production commencing in the first quarter of 2017.
  • Penn Virginia's 2017 initial plan, which is subject to change with commodity prices, anticipates drilling 16 to 19 net lower Eagle Ford wells with 13 to 16 net wells turned to sales during the year. This is based on 2017 capital expenditures between $95 million to $115 million of which 85% will be directed to development drilling and completion expenditures. Management expects it will fund spending primarily from operating cash flow.
  • Well costs are expected to average $4.8 million to $5.0 million for a typical lower Eagle Ford 2-string slickwater well with a normalized lateral length of 6,000 feet. The Company will employ its new slickwater completion design which has improved well recoveries and economics. Management anticipates new wells will generate an approximate 50% rate of return at $50 WTI oil and $3.00 Henry Hub natural gas pricing.
  • In its preliminary 2017 plan, the Company intends to delineate the potential for lower Eagle Ford down spacing, the performance of its 3-string lower Eagle Ford acreage using its new completion design and the prospectivity of the upper Eagle Ford which is present across its acreage.
  • As of November 1, 2016, Penn Virginia had 81,593 gross (53,045 net) Eagle Ford acres largely held by production. An additional 33,623 gross (28,491 net) Eagle Ford acres may be deemed non-core and are subject to expire by year end 2017. This acreage provides many years of economic inventory at the current pace of drilling with the potential for acceleration and expansion from testing new well designs. The Company also had 15,014 gross (7,141 net) acres in the Granite Wash as of November 1, 2016.
  • Substantial cost reductions have been achieved. Go forward cash general and administrative expense is expected to be reduced by approximately 55% from 2014.
  • The Company entered into a new $200 million revolving credit facility with an initial borrowing base of $128 million. As of November 11, 2016, the Company had $39.0 million drawn on its revolving credit facility and $7.6 million of cash relative to $54.4 million drawn on the revolving credit facility and $14.0 million of cash at quarter end. Current liquidity stands at $96.6 million.

Management Comment
John A. Brooks, Interim Principal Executive Officer and Chief Operating Officer, commented, "Penn Virginia has achieved substantial improvements to its cost structure by virtue of the restructuring that was completed on September 12, 2016. These changes have helped lower our fixed and variable costs. We also continue to improve our drilling and completion techniques and overall ability to develop our high value acreage position. Our strong balance sheet post-restructuring, combined with our significantly improved liquidity and low-cost drilling inventory of oil-rich acreage in Gonzales and Lavaca Counties, provide Penn Virginia with a considerable runway to execute on our high rate-of-return drilling locations at current commodity prices. Our most recent lower Eagle Ford slickwater completion design which targets pumping 2,000 pounds of proppant per foot of lateral, has performed exceedingly well. In fact, the Hawg Hunter three-well pad, where we used this technique most recently, is our highest producing pad to date. These 3 wells' combined 24-hour IPs (Initial Production) totaled 11,532 BOEPD, with a 30-day IP rate of 5,583 BOEPD and 561,000 BOE produced in their first eight-and-a-half months, of which 90% was oil. We intend to apply the same slickwater completion methodology to the two upcoming Sable and Axis pads, and we anticipate continued advancements to our completion design.

Mr. Brooks continued, "While watching commodity prices closely, we anticipate resuming our development program running a one to two-rig program in 2017, targeting the drilling of 16 to 19 net lower Eagle Ford wells, with 13 to 16 net wells turned to sales during the year. We expect this activity to be achieved within operating cash flow. We plan to concentrate our activity within our two-string, lower Eagle Ford area of development within Gonzales County and northwestern Lavaca County. We also plan to test our slickwater completion methodology down-dip in our three-string lower Eagle Ford higher pressured acreage as well as the upper Eagle Ford which is prevalent across our acreage. We are paying attention to results and activity by our competitors and remain optimistic about the potential of the area. We recognize the significant advantage our clean balance sheet offers us relative to our peer group and while we have considerable flexibility to advance development, we will be intentional with our acceleration as we further derisk our inventory and/or respond to commodity prices."

Third Quarter 2016 Financial Results
Overview of Results

Following emergence from bankruptcy on September 12, 2016, Penn Virginia adopted fresh start accounting and the full cost method of accounting for oil and gas properties which resulted in the Company becoming a new entity for financial reporting purposes. References to "Successor" relate to the financial position and results of operations of the reorganized Penn Virginia from September 13, 2016 to September 30, 2016. References to "Predecessor" relate to the financial position of Penn Virginia before application of fresh start accounting prior to and including September 12, 2016. As a result of the application of fresh-start accounting and the effects of the implementation of our Plan of Reorganization, financial results for the Successor from and after September 13, 2016 are not comparable to financial results of the Predecessor prior to that date.

Total production in the third quarter of 2016 was 979 MBOE or 10,629 BOEPD with 70% of production comprised of oil, 183 MBOE of which was attributable to the Successor and 796 MBOE of which was attributable to the Predecessor.

Total product revenues for the third quarter were $6.3 million in the Successor period and $27.0 million in the Predecessor period for a total of $33.3 million. Total direct operating expenses (general and administrative expense (excluding equity-classified share-based compensation), lease operating expense, gathering, processing and transportation expense and severance and ad valorem taxes) for the third quarter were $3.2 million in the Successor period and $16.1 million in the Predecessor period for a total of $19.3 million. For 2017, management expects that gathering, processing and transportation expense will be reduced to approximately $2.90 to $3.30 per BOE as a result of the restructuring of the Company's midstream contracts. Additionally, management anticipates lease operating expense from $5.00 to $5.50 per BOE for 2017 and cash general and administrative expense to be approximately $16 million to $19 million.

Operating income in the third quarter was $1.1 million in the Successor period with a loss of $7.7 million in the Predecessor period for a combined operating loss for the third quarter of $6.6 million.

The Company recognized a $1.15 billion gain in Reorganization items, net in the third quarter of the Predecessor period primarily as a result of a gain on the settlement of liabilities subject to compromise and a gain on adjustments related to fresh start accounting, offset in part by expenses related to professional fees and other expenses related to the emergence from bankruptcy.

Capital Resources and Liquidity

Upon emergence from bankruptcy on September 12, 2016, Penn Virginia entered into a new $200 million revolving credit facility and received $50 million of proceeds in connection with the rights offering. It provides for a revolving commitment and has an initial borrowing base of $128 million. As of September 30, 2016 Penn Virginia's revolving credit facility had a balance of $54.4 million reflecting liquidity at the end of the third quarter of $84.1 million including $14.0 million in cash. As of November 11, 2016, the Company's liquidity was $96.6 million, with $39.0 million drawn on its revolving credit facility and $7.6 million of cash.

Upon emergence from bankruptcy, 678,048 shares were reserved for unresolved claims. Since that time, 75,867 shares have been issued and 602,181 shares remain in reserve for issuance on account of unresolved claims or will be distributed to shareholders on a pro rata basis upon final resolution of all outstanding claims. Total shares outstanding as of November 11, 2016 were 14,992,018, inclusive of the aforementioned shares.

The Company's initial capital expenditure plan for the remainder of 2016 and 2017 is expected to be primarily funded with operating cash flow. The Company does have flexibility given its excellent balance sheet to potentially accelerate its drilling activities depending on the outlook for commodity prices.

Eagle Ford Shale Operational Update
Third Quarter 2016 Update

Third quarter production from the Company's Eagle Ford operations was 889 MBOE or 9,659 BOEPD. Approximately 75% of third quarter Eagle Ford production was from crude oil, 15% was from natural gas liquids (NGLs) and 10% was from natural gas. Production from Eagle Ford operations was 91% of total Company production for the third quarter and was derived from 301 operated and 36 outside-operated legacy wells. The Company did not drill or complete a well during the third quarter and the last completed well was brought to sales in February 2016.

Well Cost Reductions and Improved Well Results

Reflecting improvements to well design, operational efficiencies and lower industry oil field service costs, the Company estimates gross well costs for a 6,000-foot lateral, 24-stage well with two-strings of casing in the lower Eagle Ford shale to be $4.8 to $5.0 million. This is estimated to yield an approximate 50% rate of return at $50 WTI oil price and $3.00 Henry Hub natural gas price. At $40 WTI oil price, these wells still support a rate of return of just over 20%. This estimated gross well cost (including facilities cost) is approximately 10% to 15% lower than this same typical well design one-year prior.

Recent Eagle Ford Well Results

Below are the production results and related operating information with respect to the Company's 2-string lower Eagle Ford wells:

           24-Hour IP Average Gross Daily Production Rates(1)  30-Day Average Gross Daily Production Rates
   Gross / Net Wells Lateral Length  Frac Stages  
 Oil Rate  Equivalent Rate  Oil Percentage  Oil Rate  Equivalent Rate  Oil Percentage
     Feet     lb per foot  BOPD/1000 ft  BOEPD/1000 ft     BOPD/1000 ft  BOEPD/1000 ft   
 2-String Hybrid  149/92.1 4,875  21  1,157  210  230  91%  135  149  91%
 2-String Slickwater(2)  18/12.0 5,178  21  1,938  368  402  91%  189  206  92%
 Hawg Hunter wells(3)  3/0.9 6,912  28  1,727  518  556  93%  251  269  93%
 (1)Wellhead rates only; the natural gas associated with these wells is yielding between 135 and 155 barrels of NGLs per million cubic feet.
 (2)Includes the Hawg Hunter wells in the results.
 (3)Average of the three wells.

Penn Virginia switched to slickwater completions in the third quarter of 2015. Since that time, the Company has completed 18 wells in the lower Eagle Ford, the latest being the three-well Hawg Hunter pad which commenced production in February 2016. As a group, these 18 gross wells had average 24-hour IPs of 2,083 BOEPD per well and an average 30-day IP rate of 1,066 BOEPD per well over an average of 21 frac stages, with 92% of production from crude oil. The Hawg Hunter pad was completed with the Company's most recent completion design, targeting 500,000 pounds of proppant per stage, with an average of 28 stages per well. The 24-hour IP of these 3 wells was 11,532 BOEPD and its 30-day IP rate was 5,583 BOEPD. This is the best performing Eagle Ford pad drilled and completed by the Company to date.

Drilling Program Outlook

For the remainder of 2016, Penn Virginia has launched a one-rig development program and has scheduled to complete the 3-well Sable pad and drill the 3-well Axis pad. In 2017, the Company plans to drill 16 to 19 net wells, with 13 to 16 net wells turned to sales by the end of 2017. Management expects that approximately 85% of the Company's $95 million to $115 million planned 2017 expenditures will be directed to development drilling and completion expenditures under this program. Under this program, management expects production of 3,600 to 3,900 MBOE in 2017 with approximately 70% to 72% of production comprised of oil.

Management expects production will decline in the fourth quarter 2016 until new wells are turned to sales and production growth to commence in first quarter 2017. Management expects production in the fourth quarter 2017 will be approximately 10 to 15 percent higher than third quarter 2016 production levels and for the liquids composition to rise steadily through the year.

Derivatives Update

The Company hedged a substantial portion of its developed oil production in the early part of its reorganization process which has helped to shield its revenues from some of the volatility that has been witnessed in the marketplace. The Company's hedge position will be actively reviewed going forward.

Please see the Derivatives table below for our current derivative positions.

   Oil Volumes (BOPD) Average Swap Price ($/Bbl)
 Q4 2016 5,940 $47.69
 2017 FY 4,408 $48.62
 2018 FY 3,477 $49.12
 2019 FY 2,915 $49.90

Third Quarter 2016 Conference Call

A conference call and webcast, during which management will discuss third quarter 2016 financial and operational results, is scheduled for Tuesday, November 15, 2016 at 11:00 a.m. ET. Prepared remarks will be followed by a question and answer period. Investors and analysts may participate via phone by dialing toll free 1-877-407-9167 (international: 1-201-493-6754) five to 10 minutes before the scheduled start of the conference call, or via webcast with presentation slides by logging on to the Company's website,, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. An on-demand replay of the webcast will be available at the Company's website beginning approximately 24 hours after the webcast. The replay can also be accessed at

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

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. Because such statements include 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: potential adverse effects of the completed Chapter 11 proceedings on our liquidity, results of operations, brand, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from Chapter 11; the ability to operate our business following emergence from Chapter 11; 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 become listed on the OTCQX or a national securities exchange; our ability to execute our business plan in the current depressed commodity price environment; the decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas; 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 resumption of our drilling program; the projected demand for and supply of oil, NGLs and natural gas; our ability to contract for drilling rigs, 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 estimated proved oil and natural gas reserves; drilling and operating risks; 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; environmental obligations, 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 Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our press releases and public periodic 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. All subsequent written and oral forward-looking statements attributable to Penn Virginia or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. 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.

(in thousands, except per share data)

   Successor   Predecessor   Successor   Predecessor  
   September 13   July 1   Three Months   September 13   January 1   Nine Months  
   through   through   Ended   through   through   Ended  
   September 30,   September 12,   September 30,   September 30,   September 12,   September 30,  
   2016   2016   2015   2016   2016   2015  
 Crude oil  $5,508   $23,392   $51,124   $5,508   $81,377   $180,964  
 Natural gas liquids (NGLs)   333    1,680    3,254    333    6,064    13,841  
 Natural gas   475    1,889    6,312    475    6,208    22,143  
  Total product revenues   6,316    26,961    60,690    6,316    93,649    216,948  
 Gain (loss) on sales of property and equipment, net   -    504    50,828    -    1,261    50,803  
 Other   33    (804 )  466    33    (600 )  2,376  
 Total revenues   6,349    26,661    111,984    6,349    94,310    270,127  
Operating expenses                               
 Lease operating   756    4,209    11,304    756    15,626    33,780  
 Gathering, processing and transportation   576    4,767    5,654    576    13,235    19,535  
 Production and ad valorem taxes   375    574    3,483    375    3,490    13,139  
 General and administrative   1,476    6,601    8,153    1,476    37,434    29,496  
   Total direct operating expenses   3,183    16,151    28,594    3,183    69,785    95,950  
 Share-based compensation - equity classified awards   -    5,580    1,263    -    1,511    3,369  
 Exploration   -    4,641    1,673    -    10,288    11,922  
 Depreciation, depletion and amortization   2,029    8,024    76,850    2,029    33,582    253,056  
 Impairments   -    -    -    -    -    1,084  
  Total operating expenses   5,212    34,396    108,380    5,212    115,166    365,381  
Operating income (loss)   1,137    (7,735 )  3,604    1,137    (20,856 )  (95,254 )
Other income (expense)                               
 Interest expense   (218 )  (1,363 )  (22,985 )  (218 )  (58,018 )  (68,021 )
 Derivatives   (4,369 )  8,934    44,701    (4,369 )  (8,333 )  52,073  
 Other   9    (2,154 )  -    9    (3,184 )  -  
 Reorganization items, net   -    1,152,373    (44 )  -    1,144,993    (586 )
Income (loss) before income taxes   (3,441 )  1,150,055    25,276    (3,441 )  1,054,602    (111,788 )
 Income tax benefit   -    -    624    -    -    394  
Net income (loss)   (3,441 )  1,150,055    25,900    (3,441 )  1,054,602    (111,394 )
 Preferred stock dividends   -    -    (5,935 )  -    (5,972 )  (18,069 )
Net income (loss) attributable to common shareholders  $(3,441 ) $1,150,055   $19,965   $(3,441 ) $1,048,630   $(129,463 )
Net income (loss) per share:                               
 Basic  $(0.23 ) $12.88   $0.27   $(0.23 ) $11.91   $(1.79 )
 Diluted  $(0.23 ) $10.32   $0.25   $(0.23 ) $8.50   $(1.79 )
Weighted average shares outstanding, basic   14,992    89,292    72,651    14,992    88,013    72,438  
Weighted average shares outstanding, diluted   14,992    111,458    103,452    14,992    124,087    72,438  
   Successor   Predecessor   Successor   Predecessor  
   September 13   July 1   Three Months   September 13   January 1   Nine Months  
   through   through   Ended   through   through   Ended  
   September 30,   September 12,   September 30,   September 30,   September 12,   September 30,  
   2016   2016   2015   2016   2016   2015  
 Crude oil (MBbls)   127    547    1,205    127    2,311    3,822  
 NGLs (MBbls)   27    133    332    27    533    1,112  
 Natural gas (MMcf)   174    695    2,358    174    3,012    8,165  
Total crude oil, NGL and natural gas production (MBOE)   183    796    1,930    183    3,346    6,295  
 Crude oil ($ per Bbl)  $43.35   $42.75   $42.42   $43.35   $35.21   $47.35  
 NGLs ($ per Bbl)  $12.56   $12.66   $9.81   $12.56   $11.37   $12.45  
 Natural gas ($ per Mcf)  $2.73   $2.72   $2.68   $2.73   $2.06   $2.71  
Prices - Adjusted for derivative settlements                               
 Crude oil ($ per Bbl)  $43.35   $44.68   $69.19   $43.35   $55.98   $74.54  
 NGLs ($ per Bbl)  $12.56   $12.66   $9.81   $12.56   $11.37   $12.45  
 Natural gas ($ per Mcf)  $2.73   $2.72   $2.68   $2.73   $2.06   $2.79  
(in thousands)  
   As of  
   September 30,  December 31,  
   2015  2015  
 Current assets  $50,095  $164,980  
 Net property and equipment   251,200   344,395  
 Other assets   5,571   8,350  
  Total assets  $306,866  $517,725  
Liabilities and shareholders' equity (deficit)          
 Current liabilities  $49,320  $103,525  
 Revolving credit facility   54,350   170,000  
 Senior notes due 2019   -   300,000  
 Senior notes due 2020   -   775,000  
 Debt issuance costs   -   (20,617 )
 Other liabilities and deferred income taxes   15,742   104,938  
 Total shareholders' equity (deficit)   187,454   (915,121 )
  Total liabilities and shareholders' equity (deficit)  $306,866  $517,725  

(in thousands)

   Successor   Predecessor   Successor   Predecessor  
   September 13   July 1   Three Months   September 13   January 1   Nine Months  
   through   through   Ended   through   through   Ended  
   September 30,   September 12,   September 30,   September 30,   September 12,   September 30,  
   2016   2016   2015   2016   2016   2015  
Cash flows from operating activities                              
 Net income (loss)  $(3,441 ) $1,150,055   $25,900   (3,441 ) $1,054,602   $(111,394 )
 Adjustments to reconcile net income (loss) to net cash provided by operating activities:                             
   Non-cash reorganization items   -    (1,178,302 )      -    (1,178,302 )  -  
   Depreciation, depletion and amortization   2,029    8,024    76,850   2,029    33,582    253,056  
   Impairments   -    -    -   -    -    1,084  
   Accretion of firm transportation obligation   -    -    260   -    317    705  
   Derivative contracts:                              
    Net losses (gains)   4,369    (8,934 )  (44,701 ) 4,369    8,333    (52,073 )
    Cash settlements, net   -    1,056    32,258   -    48,008    104,590  
   Deferred income tax expense (benefit)   -    -    36   -    -    266  
   (Gain) loss on sales of assets, net   -    (504 )  (50,828 ) -    (1,261 )  (50,803 )
   Non-cash exploration expense   -    4,325    898   -    6,038    4,903  
   Non-cash interest expense   38    -    1,224   38    22,189    3,504  
   Share-based compensation (equity-classified)   -    5,433    1,263   -    1,511    3,369  
   Other, net   -    -    (20 ) -    (13 )  (17 )
 Changes in operating assets and liabilities   585    3,321    20,820   585    35,243    5,051  
  Net cash provided by (used in) operating activities   3,580    (15,526 )  63,960   3,580    30,247    162,241  
Cash flows from investing activities                              
 Capital expenditures - property and equipment   -    (784 )  (60,883 ) -    (15,359 )  (324,876 )
 Proceeds from sales of assets, net   -    98    73,891   -    224    73,670  
 Other, net   -    -    -   -    1,186    -  
  Net cash provided by (used in) investing activities   -    (686 )  13,008   -    (13,949 )  (251,206 )
Cash flows from financing activities                              
 Proceeds from revolving credit facility borrowings   -    75,350    6,000   -    75,350    203,000  
 Repayment of revolving credit facility borrowings   (21,000 )  (113,653 )  (78,000 ) (21,000 )  (119,121 )  (98,000 )
 Debt issuance costs paid   -    (3,011 )  -   -    (3,011 )  (744 )
 Proceeds from rights offering, net of issuance costs   -    49,943    -   -    49,943    -  
 Dividends paid on preferred and common stock   -    -    (6,067 ) -    -    (18,201 )
  Net cash (used in) provided by financing activities   (21,000 )  8,629    (78,067 ) (21,000 )  3,161    86,055  
Net increase (decrease) in cash and cash equivalents   (17,420 )  (7,583 )  (1,099 ) (17,420 )  19,459    (2,910 )
Cash and cash equivalents - beginning of period   31,414    38,997    4,441   31,414    11,955    6,252  
Cash and cash equivalents - end of period  $13,994   $31,414   $3,342   13,994   $31,414   $3,342  

Steve Hartman
Chief Financial Officer
Ph: (713) 722-6529
Fax: (713) 722-6620
E-Mail: [email protected]

Source: Marketwired (Canada) (November 14, 2016 - 4:38 PM EST)

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