HOUSTON, Nov. 13, 2019 (GLOBE NEWSWIRE) -- Epsilon Energy Ltd. (“Epsilon” or the “Company”) (NASDAQ: EPSN) today reported third quarter 2019 financial and operating results.

Michael Raleigh, CEO, commented, “Following the initial flow-back and testing phase the operator turned in-line to sales four lower Marcellus wells on October 30th. Due to one of the wells being drilled shorter than planned, resulting from drilling issues, these four wells contributed 8800’ rather than the originally planned 9300’ of completed lateral net to Epsilon’s interests. During the first few days of November these wells were contributing approximately 13.5 MMcf/d to the Company’s net working interest production of roughly 34.0 MMcf/d. This represents a 65% production increase over the third quarter exit rate.

In the NW Stack the company participated in one net well. We postponed completion capital allocation given the pricing and differentials for crude oil and natural gas liquids which provide a significant contribution to the economics of the play. We intend to re-visit the pricing environment to determine the appropriate timing of completing wells in this project area.

Our team is now focused on the 2020 capital budgeting process and we look forward to updating the market with respect to 2020 production and capex guidance prior to year end.

Epsilon will be presenting at the IDEAS conference at the Westin Dallas Downtown on Nov 20th at 1:40 pm Central. We have scheduled a conference call to have a Q&A regarding the 3rd quarter results on November 25th, 2019 and will announce the dial-in details in a separate note”

Epsilon’s highlights for the third quarter and material subsequent events following the end of the quarter through the date of this release include:

  • Total Revenues of $5.2 million for the quarter, compared to $7.3 million for the same period of 2018.
  • Net after tax income of $1.5 million for the quarter includes $445 thousand of non-recurring income, compared to $2.5 million for the same period of 2018.
  • EBITDA of $3.9 million for the quarter, compared to $3.8 million for the same period in 2018.
  • Marcellus working interest (WI) gas production averaged 21.9 MMcf/d for the third quarter of 2019.
  • Gathered and delivered 21.1 Bcfe gross (7.4 Bcfe net to Epsilon’s interest) during the quarter through the Auburn Gas Gathering System which represents approximately 69% of the designed throughput capacity.
  • Auburn Gas gathering and compression services included third party gas of 0.7 Bcfe during the quarter or approximately 7.3 MMcf/d.

Financial and Operating Results

  Three months ended
  September 30, 
  2019 2018
Revenues ($000)        
Natural gas revenue $2,934  $4,738 
Volume (MMcf)  1,790   2,028 
Avg. Price ($/Mcf) $1.64  $2.34 
PA Exit Rate (MMcfpd)  16.7   20.1 
Oil and other liquids revenue $66  $218 
Volume (MBO)  2.8   5.3 
Avg. Price ($/Bbl) $23.73  $40.97 
Gathering system revenue $2,220  $2,294 
Total Revenues $5,219  $7,250 

Capital Expenditures

Epsilon’s capital expenditures were $4.8 million for the three months ended September 30, 2019. The capital was directed to the completion of four wells in Pennsylvania, the drilling of one well in Oklahoma, and maintenance of the Auburn Gas Gathering system.

Marcellus Operational Guidance

The table below details Epsilon’s well development status at September 30, 2019:

 September 30, 2019 June 30, 2019
Producing99  23.8  99  22.3 
Shut-in9  1.9  5  2.3 
Waiting on pipeline-  -  -  - 
Waiting on completion-  -  -  - 
Drilling-  -  1  0.2 

Subsequent to quarter end, the Operator flow tested and turned in-line 4 gross (1.07 net) wells.

Third Quarter Results

Epsilon generated revenues of $5.2 million for the three months ended September 30, 2019 compared to $7.3 million for the three months ended September 30, 2018.

Realized natural gas prices averaged $1.64 per Mcf for Marcellus Upstream operations in the third quarter of 2019. Operating expenses for Marcellus Upstream operations in the third quarter were $1.3 million. As a result of our active hedging program realized natural gas prices averaged $2.30 per Mcf for Marcellus produced gas during the third quarter.

The Auburn Gas Gathering system delivered 21.1 Bcfe of natural gas during the quarter as compared to 19.1 Bcfe during the second quarter of 2019. Primary gathering volumes decreased 14.1% quarter over quarter to 13.0 Bcfe. Imported cross-flow volumes increased 95.2% to 8.1 Bcfe.

Epsilon reported net after tax income of $1.5 million attributable to common shareholders or $0.05 per basic and diluted common share outstanding for the three months ended September 30, 2019, compared to net income of $2.5 million, and $0.09 per basic and diluted common share outstanding for the three months ended September 30, 2018. 

For the three months ended September 30, 2019, Epsilon's Adjusted Earnings Before Interest, Taxes, Depreciation, Amortization ("Adjusted EBITDA") was $3.9 million as compared to $3.8 million for the three months ended September 30, 2018.

About Epsilon

Epsilon Energy Ltd. is a North American onshore oil and natural gas development and midstream company with a current focus on the Marcellus Shale of Pennsylvania and the Anadarko Basin in Oklahoma.

Forward-Looking Statements

Certain statements contained in this news release constitute forward looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, ‘may”, “will”, “project”, “should”, ‘believe”, and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated. Forward-looking statements are based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and the forward-looking statements included in this news release should not be unduly relied upon.

The reserves and associated future net revenue information set forth in this news release are estimates only. In general, estimates of oil and natural gas reserves and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as production rates, ultimate reserves recovery, timing and amount of capital expenditures, ability to transport production, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the oil and natural gas reserves attributable to any particular group of properties, as well as the classification of such reserves and estimates of future net revenues associated with such reserves prepared by different engineers (or by the same engineers at different times) may vary. The actual reserves of the Company may be greater or less than those calculated. In addition, the Company's actual production, revenues, development and operating expenditures will vary from estimates thereof and such variations could be material.

Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future. There is no assurance that forecast price and cost assumptions will be attained and variances could be material.

Proved reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation. The estimated future net revenues contained in this news release do not necessarily represent the fair market value of the Company's reserves.

Contact Information:


Michael Raleigh
Chief Executive Officer

Special note for news distribution in the United States
The securities described in the news release have not been registered under the United Stated Securities Act of 1933, as amended, (the “1933 Act”) or state securities laws. Any holder of these securities, by purchasing such securities, agrees for the benefit of Epsilon Energy Ltd. (the “Corporation”) that such securities may not be offered, sold, or otherwise transferred only (A) to the Corporation or its affiliates; (B) outside the United States in accordance with applicable state laws and either (1) Rule 144(as) under the 1933 Act or (2) Rule 144 under the 1933 Act, if applicable.

Interim Unaudited Condensed Consolidated Statements of Operations
(All amounts stated in US$)

  Three months ended September 30,  Nine months ended September 30, 
  2019 2018 2019 2018
Oil, gas, NGLs and condensate revenue $2,999,581  $4,956,539  $13,005,722  $13,559,073 
Gas gathering and compression revenue  2,219,613   2,293,648   6,923,058   7,633,971 
Total revenue  5,219,194   7,250,187   19,928,780   21,193,044 
Operating costs and expenses:            
Lease operating expenses  1,548,902   1,509,634   4,851,090   5,031,242 
Gathering system operating expenses  461,036   325,848   1,012,709   1,041,903 
Development geological and geophysical expenses        83,748    
Depletion, depreciation, amortization, and accretion  1,851,466   1,908,214   5,630,368   5,380,307 
Gain on sale of property  (445,173)     (1,375,000)   
General and administrative expenses:            
Stock based compensation expense  133,720   63,691   401,161   235,649 
Other general and administrative expenses  952,503   1,418,052   3,213,371   2,883,591 
Total operating costs and expenses  4,502,454   5,225,439   13,817,447   14,572,692 
Operating income  716,740   2,024,748   6,111,333   6,620,352 
Other income and (expense):            
Interest income  38,618   1,925   127,906   4,357 
Interest expense  (29,416)  (24,155)  (86,035)  (120,065)
Gain (loss) on derivative contracts  1,270,494   (296,820)  3,494,727   (770,907)
Other income  1   42   456   12,485 
Other income (expense), net  1,279,697   (319,008)  3,537,054   (874,130)
Income before tax expense  1,996,437   1,705,740   9,648,387   5,746,222 
Income tax expense (benefit)  543,139   (811,901)  2,983,555   507,045 
NET INCOME $1,453,298  $2,517,641  $6,664,832  $5,239,177 
Currency translation adjustments  (900)  29,385   10,944   (61,312)
NET COMPREHENSIVE INCOME $1,452,398  $2,547,026  $6,675,776  $5,177,865 
Net income per share, basic $0.05  $0.09  $0.24  $0.19 
Net income per share, diluted $0.05  $0.09  $0.24  $0.19 
Weighted average number of shares outstanding, basic  27,369,106   27,451,936   27,372,283   27,484,529 
Weighted average number of shares outstanding, diluted  27,403,110   27,462,979   27,394,238   27,495,651 


Interim Unaudited Condensed Consolidated Statements of Financial Position
(All amounts stated in US$)

  September 30,  December 31, 
  2019 2018
Current assets      
Cash and cash equivalents $18,746,426  $14,401,257 
Accounts receivable  3,172,723   5,042,134 
Fair value of derivatives  1,446,557    
Prepaid income taxes     205,711 
Other current assets  430,623   244,233 
Total current assets  23,796,329   19,893,335 
Non-current assets      
Property and equipment:      
Oil and gas properties, successful efforts method      
Proved properties  125,443,709   118,851,574 
Unproved properties  21,015,039   19,498,666 
Accumulated depletion, depreciation, and amortization  (87,908,590)  (83,807,401)
Total oil and gas properties, net  58,550,158   54,542,839 
Gathering system  41,278,528   41,040,847 
Accumulated depletion, depreciation, and amortization  (29,581,885)  (28,137,573)
Total gathering system, net  11,696,643   12,903,274 
  Total property and equipment, net  70,246,801   67,446,113 
Other assets:      
Restricted cash  559,053   558,261 
Fair value of derivatives  406,457    
Prepaid drilling costs  1,739    
Total non-current assets  71,214,050   68,004,374 
Total assets $95,010,379  $87,897,709 
Current liabilities      
Accounts payable trade $4,049,590  $2,585,324 
Royalties payable  1,012,315   1,300,539 
Income taxes payable  1,338,225    
Other accrued liabilities  678,454   2,156,304 
JV Partner Cash Advances  8,400    
Fair value of derivatives     297,023 
Total current liabilities  7,086,984   6,339,190 
Non-current liabilities      
Asset retirement obligation  1,720,018   1,625,154 
Deferred income taxes  10,842,394   9,989,278 
Total non-current liabilities  12,562,412   11,614,432 
Total liabilities  19,649,396   17,953,622 
Commitments and contingencies (See Note 8)      
Shareholders' equity      
Common shares, no par value, unlimited shares authorized and 27,380,247 shares and 27,385,133 shares issued and outstanding at September 30, 2019 and December 31, 2018, respectively.  143,416,892   143,705,441 
Treasury shares, 363,530 shares and 26,953 shares issued and outstanding at September 30, 2019 and December 31, 2018, respectively.  (1,465,910)  (94,418)
Additional paid-in capital  6,920,189   6,519,028 
Accumulated deficit  (83,319,062)  (89,983,894)
Accumulated other comprehensive income  9,808,874   9,797,930 
Total shareholders' equity  75,360,983   69,944,087 
Total liabilities and shareholders' equity $95,010,379  $87,897,709 

Interim Unaudited Condensed Consolidated Statements of Cash Flows
(All amounts stated in US$)

  Nine months ended September 30, 
  2019 2018
Cash flows from operating activities:      
Net income $6,664,832  $5,239,177 
Adjustments to reconcile net income to net cash provided by operating activities:      
Depletion, depreciation, amortization, and accretion  5,630,368   5,380,307 
Gain on sale of leases  (1,375,000)   
(Gain) loss on derivative contracts  (3,494,727)  770,907 
Cash received from settlements of derivative contracts  1,344,690   (96,568)
Stock-based compensation expense  401,161   235,649 
Deferred income tax expense (benefit)  853,116   (695,534)
Changes in assets and liabilities:      
Accounts receivable  1,869,411   (146,316)
Prepaid income taxes and other current assets  19,321   (287,941)
Accounts payable, royalties payable and other accrued liabilities  (1,422,238)  (757,090)
Income taxes payable  1,338,225    
Other long-term liabilities     (1,347,386)
Net cash provided by operating activities  11,829,159   8,295,205 
Cash flows from investing activities:      
Acquisition of unproved oil and gas properties  (596,500)  (260,000)
Additions to unproved oil and gas properties  (919,873)  (680,223)
(Additions to) refunds of proved oil and gas properties  (5,452,166)  260,840 
Additions to gathering system properties  (238,823)  (125,751)
Prepaid drilling costs  (1,739)   
Proceeds from sale of leases  1,375,000    
Changes in restricted cash  (792)  (1,061)
Net cash used in investing activities  (5,834,893)  (806,195)
Cash flows from financing activities:      
Buyback of common shares  (1,714,291)  (356,984)
Exercise of stock options  54,250    
Repayment of revolving line of credit     (2,500,000)
Net cash used in financing activities  (1,660,041)  (2,856,984)
Effect of currency rates on cash and cash equivalents  10,944   (61,312)
Increase in cash and cash equivalents  4,345,169   4,570,714 
Cash and cash equivalents, beginning of year  14,401,257   9,998,853 
Cash and cash equivalents, end of period $18,746,426  $14,569,567 
Supplemental cash flow disclosures:      
Income taxes paid $733,200  $3,840,493 
Interest paid $89,817  $120,065 
Non-cash investing activities:      
Change in proved properties accrued in accounts payable and accrued liabilities $1,129,972  $ 
Change in gathering system accrued in accounts payable and accrued liabilities $(1,142) $1,575 
Asset retirement obligation asset additions and adjustments $9,997  $46 

Adjusted EBITDA Reconciliation
(All amounts stated in US $000)

(in thousands of dollars) Three months ended September 30,  Nine months ended September 30, 
  2019 2018 2019 2018
Net income  $1,453  $2,518  $6,665  $5,239 
Add Back:             
Net interest (income) expense  (9)  22   (42)  116 
Income tax provision  543   (812)  2,984   507 
Depreciation, depletion, amortization, and accretion  1,851   1,908   5,630   5,380 
Stock based compensation expense  134   64   401   236 
Net change in unrealized (gain) loss on commodity contracts  (113)  81   (2,150)  675 
Adjusted EBITDA $3,859  $3,781  $13,488  $12,152 

Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2) taxes, (3) depreciation, depletion, amortization and accretion expense, (4) impairments of oil and gas properties, (5) non-cash stock compensation expense, (6) unrealized gain on derivatives, and (7) other income. Adjusted EBITDA is not a measure of financial performance as determined under IFRS and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with IFRS or as a measure of profitability or liquidity.

Additionally, Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Epsilon has included Adjusted EBITDA as a supplemental disclosure because its management believes that EBITDA provides useful information regarding its ability to service debt and to fund capital expenditures. It further provides investors a helpful measure for comparing operating performance on a "normalized" or recurring basis with the performance of other companies, without giving effect to certain non-cash expenses and other items. This provides management, investors and analysts with comparative information for evaluating the Company in relation to other oil and gas companies providing corresponding non-IFRS financial measures or that have different financing and capital structures or tax rates. These non-IFRS financial measures should be considered in addition to, but not as a substitute for, measures for financial performance prepared in accordance with IFRS. The table above sets forth a reconciliation of Adjusted EBITDA to net income, which is the most directly comparable measure of financial performance calculated under IFRS and should be reviewed carefully.