UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): September 6, 2017
Evolution Petroleum Corporation
(Exact name of registrant as specified in its charter)
001-32942
(Commission File Number)
Nevada | 41-1781991 | |
(State or Other Jurisdiction of Incorporation) | (I.R.S. Employer Identification No.) | |
1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(Address of Principal Executive Offices)
(713) 935-0122
(Registrant’s Telephone Number, Including Area Code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). | |
Emerging growth company o | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o | |
Item 2.02 Results of Operations and Financial Condition.
On September 6, 2017, Evolution Petroleum Corporation (the “Company”) issued a press release reporting on financial and operating results for the Fiscal Year and quarter ended June 30, 2017. A copy of the press release, dated September 6, 2017, is furnished herewith as Exhibit 99.1.
This information is furnished pursuant to Item 2.02 of Form 8-K and shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, unless specifically incorporated by reference in a document filed under the Securities Act of 1933, as amended, or the Exchange Act. By filing this report on Form 8-K and furnishing this information, the Company makes no admission as to the materiality of any information in this report that is required to be disclosed solely by Item 2.02.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
Exhibit No. | Description | |
Evolution Petroleum Corporation Press Release, dated September 6, 2017 | ||
2
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Evolution Petroleum Corporation (Registrant) | ||
Date: September 7, 2017 | By: | /s/ Randall D. Keys |
Name: | Randall D. Keys | |
Title: | President and Chief Executive Officer | |
3
INDEX TO EXHIBITS
Exhibit No. | Description | |
Exhibit 99.1 | Evolution Petroleum Corporation Press Release, dated September 6, 2017 | |
4
Exhibit 99.1
 | Company Contact: |
Randy Keys, CEO | |
(713) 935-0122 | |
rkeys@evolutionpetroleum.com | |
Evolution Petroleum Announces Results for Fiscal Year 2017
Houston, TX, September 6, 2017 - Evolution Petroleum Corporation (NYSE American: EPM) today reported financial and operating highlights for its fiscal year ended June 30, 2017 and the fiscal fourth quarter, with comparisons to the fiscal third quarter ended March 31, 2017 (the "prior quarter") and the quarter ended June 30, 2016 (the "year-ago quarter"), as well as the fiscal year ended June 30, 2016 (the “prior year”). Evolution also reported year-end reserves as of June 30, 2017 with comparisons to reserve quantities for the prior year.
Highlights:
• | Generated record revenues of $34.5 million, an increase of 31% over the prior year. |
• | Reported $6.8 million in net income for the year, or $0.21 per common share, marking the sixth consecutive year of positive net income. |
• | Increased our cash dividends on common stock by 50%, from $0.20 per year to the current rate of $0.30 per year. |
• | Maintained our balance sheet strength, finishing the year with $23.4 million of working capital and significant liquidity under our credit facility, with no debt outstanding. |
• | Funded all operations and cash requirements from operating cash flow and internal resources, including $7.6 million of capital spending, $8.4 million of cash dividends to common shareholders and $7.9 million to redeem our preferred stock. |
• | Realized positive results from the Delhi field, with net production up 17% to 2,105 barrels of oil equivalent per day (“BOEPD”) from 1,800 BOEPD in the prior year. The NGL plant was completed and online in December 2016. |
Randy Keys, President and CEO, said: “Fiscal 2017 was another positive year for Evolution, with several important milestones achieved. We completed the NGL plant in the Delhi field and began production and sales of natural gas liquids in January 2017. We redeemed our preferred stock for $7.9 million, resulting in annual dividend savings of $674 thousand, or approximately $0.02 per common share. We increased cash dividends on our common stock by 50%, from $0.20 per year to the current rate of $0.30 per year, and we accomplished all of this while maintaining an exceptionally strong balance sheet. Our recent cash flow from the Delhi field has been significantly above our dividend requirements, which maintains our financial and strategic capabilities. Most recently, we are pleased to note that Delhi field operations were not impacted by last week’s hurricane. While the recovery in oil prices has been slow and uneven, we remain in an enviable position for growth and continued prosperity.”
Financial Results for the Quarter Ended June 30, 2017
In the current quarter, we reported operating revenues of $8.8 million, based on an average realized oil price of $46.51 per barrel and an average realized NGL price of $19.31 per barrel, and generated $2.6 million in income from operations. In the prior quarter, we reported income from operations of $3.9 million on higher revenues of $9.5 million, which was primarily due to higher commodity prices of $49.29 and $23.71 per barrel for oil and NGL’s, respectively. Production volumes were essentially unchanged at 2,244 BOEPD compared to 2,260 BOEPD in the prior quarter, but were 21% above the year-ago quarter rate of 1,856 BOEPD. Quarterly net income to common shareholders was $1.5 million, or $0.05 per common share, compared to $0.07 per share in the prior quarter.
Production costs in the Delhi field increased from $2.8 million in the prior quarter to $3.4 million in the current quarter, driven by a 28% increase in purchased CO2 volumes, from 66 MMCF/D to 85 MMCF/D, higher workover expenses in the field and expenses related to the start-up and operation of the NGL plant, part of which should be non-recurring. Depletion, depreciation and amortization expense increased slightly to $1.6 million from $1.5 million in the prior quarter, as there was a small increase in the DD&A rate per barrel. Our general and administrative expenses were $1.2 million for the quarter, which represents a substantial decrease over the year-ago quarter and are down slightly from the prior quarter. Most of this change resulted from comparably higher litigation expenses in the year-ago quarter, which have been dramatically reduced in fiscal 2017 compared to the prior year.
Financial Results for the Year Ended June 30, 2017
For fiscal 2017, net income to common shareholders was $6.8 million, or $0.21 per common share. Revenues for the year increased by 31%, totaling $34.5 million, based on a 17% increase in net production to 2,105 BOEPD and higher product prices. Our average realized oil price was $46.31 per barrel and our average NGL price was $21.28 per barrel. Our revenues in the prior year were $26.1 million on lower production and a lower average oil price of $39.71 per barrel. Net production was significantly higher in 2017 as conformance projects in the Delhi field increased oil rates and the NGL plant was in production for approximately one-half of the fiscal year. During the year, we had a very limited hedging program, realizing a net gain of only $44 thousand, compared to a net gain of $3.3 million in the prior fiscal year. Net income to common shareholders was also impacted by $1.0 million ($0.03 per common share) of deemed preferred stock dividends resulting from the retirement of our outstanding preferred stock.
Our production costs for the year totaled $10.8 million, or $14.10 per barrel of oil equivalent (“BOE”), compared to $9.1 million, or $13.76 per BOE in the prior year. CO2 costs for the current year were $4.5 million, or 10% higher than the prior year due to higher realized oil prices on similar amounts of purchased CO2 volumes. Other lease operating expenses, totaling $6.4 million, increased approximately 28% year over year primarily due to incremental Delhi NGL plant expenses and increased workover expenses in the field. Despite the recent increase in lifting costs and challenging oil price environment, Delhi field margins remain strongly positive. Our depreciation and depletion expense in fiscal 2017 was $5.7 million, an 11% increase from $5.2 million in the prior year, primarily due to a 17% increase in net production. Our full year DD&A rate was down 1% to $7.40 per barrel. We have not had any write-downs of oil and gas property costs since the downturn in oil prices began in 2014.
Our general and administrative expenses were significantly lower in fiscal 2017, dropping by 45% to $5.0 million from $9.1 million in the prior year. The current year reflects a significant reduction in litigation expenses of $2.6 million and a decrease in compensation costs from the strategic decision to separate our artificial lift technology operations last year. We have made excellent progress in lowering G&A expenses over the past three years and are committed to holding these costs at the lowest reasonable level consistent with our responsibilities to our shareholders.
Reserves and Delhi Field Operations
Summary of Reserves as of June 30, 2017 | ||||||||
Oil MBO | NGL MBL | Equivalent MBOE | ||||||
Proved Developed | 6,617 | 1,333 | 7,950 | |||||
Proved Undeveloped | 1,755 | 353 | 2,108 | |||||
Total Proved | 8,372 | 1,686 | 10,058 | |||||
Probable Developed | 3,577 | 720 | 4,297 | |||||
Probable Undeveloped | 808 | 163 | 971 | |||||
Total Probable* | 4,385 | 883 | 5,268 | |||||
Possible Developed | 2,373 | 478 | 2,851 | |||||
Possible Undeveloped | 304 | 61 | 365 | |||||
Total Possible* | 2,677 | 539 | 3,216 | |||||
Cautionary Note to Investors * – Our reserves as of June 30, 2017 and 2016 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. All reserve estimates are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. The SEC’s current rules allow oil and gas companies to disclose not only Proved reserves, but also Probable and Possible reserves that meet the SEC’s definitions of such terms. Estimates of Probable and Possible reserves by their nature are much more speculative than estimates of Proved reserves. These non-proved reserve categories are subject to greater uncertainties and the likelihood of recovering those reserves is subject to substantially greater risk. When estimating the amount of oil and natural gas liquids recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered, generally described as having a 50% probability of recovery. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. These three reserve categories have not been adjusted to different levels of recovery risk among these categories and are therefore not comparable and are not meaningfully combined.
For the year ended June 30, 2017, our proved reserves in the Delhi field totaled 10.1 million barrels of oil equivalent (“MMBOE”), a reduction of 0.7 MMBOE from the prior year. Substantially all of this reduction results from production in the prior fiscal year. Net revisions to prior year reserves were negligible. Our trailing twelve-month average oil price, as specified by SEC guidelines, was $46.65 per barrel of oil, based on a $48.85 per barrel NYMEX WTI reference price. Our NGL price was $20.48 per barrel.
Our probable reserves increased substantially by 18% to 5.3 MMBOE from 4.5 MMBOE in the prior year. Our possible reserves increased by 19% to 3.2 MMBOE from 2.7 MMBOE in the prior year. Of particular note, our probable and possible reserves do not require any additional development capital to produce and are 82% and 89% developed, respectively. These categories of reserves reflect only the incremental reserves associated with different engineering assumptions about the percentage of original oil in place that can be recovered through CO2 enhanced oil recovery.
During fiscal 2017, the Delhi field performed well above our original production expectations from a year ago. In the reserves report as of June 30, 2016, our reservoir engineers were projecting an average gross oil production rate for the 2017 fiscal year of 6,770 BOPD, whereas our actual rate was 7,567 BODP, an increase of almost 12%. The majority of this increased production is attributable to selective improvements in the CO2 flood through conformance efforts and other relatively low cost production enhancement projects. It did not result from new drilling or development to any significant degree. We believe this bodes well for the long term recovery outlook in the Delhi field. Our reserves report reflects this, as the expected ultimate recovery of our proved plus incremental probable (“2P”) reserves has increased from 17.0% to 19.5% over the past two years. The timing of recovery has been accelerated as well. Estimated ultimate recovery of total proved reserves has also increased from 13.0% to 14.3% over this two-year period. We believe this provides solid evidence for future increases in proved reserves and ultimate recoveries.
The discounted value of future net revenues from our proved reserves is typically computed under two methods, both of which are useful for analysts and other readers of our financial statements. One measure, which conforms to Generally Accepted Accounting Principles (“GAAP”), is the after-tax Standardized Measure of Discounted Future Net Cash Flows (“SMOG”), which is calculated as the present value of estimated future net revenues discounted at a 10% interest rate and reduced by estimated future income tax expenses associated with the properties, with such taxes discounted at 10% based on the expected date of future tax payments. The other method is the pre-tax present value of estimated future net revenues discounted at a 10% interest rate, or “PV-10.” PV-10 does not conform to GAAP, but is widely used as a comparative metric in our industry. Both methods utilize the same SEC price assumptions, based on trailing twelve month historical commodity prices in the field, held constant for the life of the properties and also assume continuation of existing economic conditions for operating costs and other deductions. Our discounted values under the two methods are as follows:
Standardized Measure of Proved Reserves (after-tax) $ 82.9 million
Effect of Future Income Taxes, Discounted at 10% $ 28.0 million
PV-10 Value of Proved Reserves $ 110.9 million
The $110.9 million PV-10 value above is comprised of $101.7 million for proved developed producing reserves and $9.2 million for proved undeveloped reserves. It is not practical to allocate future income taxes
and compute SMOG values for producing versus undeveloped reserves, nor is there a comparable GAAP measure for probable or possible reserves.
The NGL plant was completed and online in December 2016. The plant has achieved its intended objectives which were (a) to remove the less dense hydrocarbons, primarily methane, from the CO2 recycle stream to improve the efficiency of the flood, (b) to produce marketable natural gas liquids for sale and (c) to produce sufficient quantities of methane and ethane to fuel the electric turbine to produce electric power in the field. The NGL plant went through an extended startup period during which certain throughput issues were identified and addressed. During this time, the plant has been operating at 25-30% below capacity, which has reduced the volumes of both NGL’s and methane produced and has returned CO2 to the recycle plant for reinjection at slightly below the targeted purity range.
The lower production rate relative to plant capacity required an engineered solution to modify the CO2 processing at the inlet of the recycle plant at a cost of approximately $230 thousand, net to us. This modification project involved a four-day rolling shut-down of the recycle facility and NGL plant and was completed approximately three weeks ago in mid-August. Production results since these modifications were completed appear to have achieved the goals set out for the project. We are pleased to report that during the subsequent three week period, (a) the NGL plant has been operating at substantially 100% of capacity, (b) CO2 purity has been at or above the goal of 96%, (c) NGL volumes have been at our targeted production range of approximately 1,400 barrels per day on a gross basis and (d) methane production has supplied substantially all of the requirements for the electric turbine with minimal purchased natural gas. The electric turbine has been generating power at its rated capacity and supplying part of the power needs of the recycle facility. This should reduce future operating expenses.
Fiscal 2018 Capital Budget and Financial Outlook
We have approved expenditures totaling approximately $6.0 million net to our interest for two projects in the Delhi field. All costs are related to the proved undeveloped reserves. The first project, estimated at $3.2 million, is an infill drilling program consisting of eight wells. Three of the wells are for CO2 injection and the other five are production wells. These wells will target productive oil zones within the currently producing area of the CO2 flood. We believe these wells will both add production and increase ultimate recovery of reserves which are not being swept effectively in the current flood. The second project, estimated to cost approximately $2.8 million, consists of three new water injection wells and related infrastructure in
preparation for development of Phase V of the flood. Total future development costs for Phase V are approximately $10.9 million. At this point, we expect the remaining $8.1 million of spending on Phase V to move forward in late calendar 2018 or 2019.
These two capital projects were authorized and initially scheduled to commence in July 2017. However, they have been electively deferred until early 2018 by the operator based on its reallocation of funds available for its calendar 2017 capital budget. As with most capital spending in our industry, the timing is dependent on a range of factors, with commodity prices and related cash flows being the most prominent, but also including rig availability, permitting and other issues.
There will likely be other smaller capital projects to enhance and maintain the effectiveness of the CO2 flood throughout the coming year. We have seen excellent results from these projects over the past two years. The amount of these expenditures cannot be accurately estimated at this time, but is not expected to be material to our financial position.
Our liquidity position remains very strong, with $23.4 million of working capital, at least $10 million of undrawn liquidity under our reserve-based credit facility and the expectation of significant and stable free cash flow over the next fiscal year. This amount of our cash flow is dependent on the net prices we receive for our production. Based on our solid financial position, we expect to continue our common stock cash dividend program for the foreseeable future, and will continue to evaluate the options of increasing common dividends and/or acquiring additional shares under our stock repurchase program. We also continue to explore other opportunities for growth and diversification of our cash flow.
Conference Call
As previously announced, Evolution Petroleum will host a conference call on Thursday, September 7, 2017 at 11:00 a.m. Eastern (10:00 a.m. Central) to discuss results. To access the call, please dial 1-855-327-6837 (US and Canada) or 1-631-891-4304 (International). To listen live or hear a rebroadcast, please go to http://www.evolutionpetroleum.com. A replay will be available one hour after the end of the conference call through September 14, 2017 by calling 1-844-512-2921 (US and Canada) or 1-412-317-6671 (International) and providing the replay pin number of 10003371.
About Evolution Petroleum
Evolution Petroleum Corporation develops and produces petroleum reserves within known oil and gas reservoirs in the U.S., with a focus on maximizing value per share. Our principal asset is our interest in a CO2 enhanced oil recovery project in Louisiana's Delhi Field. Additional information, including the Company's most recent annual report on Form 10-K and its quarterly reports on Form 10-Q, is available on its website at www.EvolutionPetroleum.com.
Cautionary Statement
All forward-looking statements contained in this press release regarding potential results and future plans and objectives of the Company involve a wide range risks and uncertainties. Statements herein using words such as "believe," "expect," "plans," and words of similar meaning are forward-looking statements. Although our expectations are based on engineering, geological, financial and operating assumptions that we believe to be reasonable, many factors could cause actual results to differ materially from our expectations and we can give no assurance that our goals will be achieved. These factors and others are detailed under the heading "Risk Factors" and elsewhere in our periodic documents filed with the SEC. The Company undertakes no obligation to update any forward-looking statement.
Financial Tables to Follow
Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
Three Months Ended | Years Ended | ||||||||||||||||||
June 30, | March 31, | June 30, | |||||||||||||||||
2017 | 2016 | 2017 | 2017 | 2016 | |||||||||||||||
Revenues | |||||||||||||||||||
Crude oil | $ | 8,366,230 | $ | 7,233,190 | $ | 9,060,796 | $ | 33,550,698 | $ | 26,130,762 | |||||||||
Natural gas liquids | 469,472 | 5,553 | 464,641 | 934,202 | 7,885 | ||||||||||||||
Natural gas | — | 1,691 | — | (4 | ) | 2,895 | |||||||||||||
Artificial lift technology services | — | — | — | — | 207,960 | ||||||||||||||
Total revenues | 8,835,702 | 7,240,434 | 9,525,437 | 34,484,896 | 26,349,502 | ||||||||||||||
Operating costs | |||||||||||||||||||
Production costs | 3,387,489 | 2,031,642 | 2,811,258 | 10,835,809 | 9,062,179 | ||||||||||||||
Cost of artificial lift technology services | — | — | — | — | 70,932 | ||||||||||||||
Depreciation, depletion and amortization | 1,614,981 | 1,206,476 | 1,523,475 | 5,719,405 | 5,165,120 | ||||||||||||||
Accretion of discount on asset retirement obligations | 19,772 | 14,499 | 13,562 | 59,664 | 49,054 | ||||||||||||||
General and administrative expenses* | 1,225,060 | 3,032,994 | 1,283,906 | 4,985,408 | 9,079,597 | ||||||||||||||
Restructuring charges | 4,488 | — | — | 4,488 | 1,257,433 | ||||||||||||||
Total operating costs | 6,251,790 | 6,285,611 | 5,632,201 | 21,604,774 | 24,684,315 | ||||||||||||||
Income from operations | 2,583,912 | 954,823 | 3,893,236 | 12,880,122 | 1,665,187 | ||||||||||||||
Other | |||||||||||||||||||
Gain on realized derivative instruments, net | 40,450 | (644,936 | ) | 3,350 | 43,890 | 3,315,123 | |||||||||||||
Gain (loss) on unrealized derivative instruments, net | (47,965 | ) | 4,427 | 47,965 | (14,132 | ) | 124,106 | ||||||||||||
Delhi field litigation settlement | — | 28,096,500 | — | — | 28,096,500 | ||||||||||||||
Delhi field insurance recovery related to pre-reversion event | — | — | — | — | 1,074,957 | ||||||||||||||
Interest and other income | 16,950 | 2,695 | 13,099 | 56,855 | 26,211 | ||||||||||||||
Interest expense | (20,385 | ) | (19,781 | ) | (20,317 | ) | (81,758 | ) | (70,943 | ) | |||||||||
Income before income tax provision | 2,572,962 | 28,393,728 | 3,937,333 | 12,884,977 | 34,231,141 | ||||||||||||||
Income tax provision | 1,072,201 | 7,519,258 | 1,518,190 | 4,840,664 | 9,570,779 | ||||||||||||||
Net income attributable to the Company | 1,500,761 | 20,874,470 | $ | 2,419,143 | 8,044,313 | 24,660,362 | |||||||||||||
Dividends on preferred stock | — | 168,576 | — | 250,990 | 674,302 | ||||||||||||||
Deemed dividend on preferred shares called for redemption | — | — | — | 1,002,440 | — | ||||||||||||||
Net income attributable to common shareholders | $ | 1,500,761 | $ | 20,705,894 | $ | 2,419,143 | $ | 6,790,883 | $ | 23,986,060 | |||||||||
Earnings per common share | |||||||||||||||||||
Basic | $ | 0.05 | $ | 0.63 | $ | 0.07 | $ | 0.21 | $ | 0.73 | |||||||||
Diluted | $ | 0.05 | $ | 0.63 | $ | 0.07 | $ | 0.21 | $ | 0.73 | |||||||||
Weighted average number of common shares outstanding | |||||||||||||||||||
Basic | 33,072,466 | 32,904,481 | 33,062,297 | 33,034,480 | 32,810,375 | ||||||||||||||
Diluted | 33,144,027 | 32,964,109 | 33,115,699 | 33,110,560 | 32,861,231 | ||||||||||||||
* General and administrative expenses for the quarters ended June 30, 2017, June 30, 2016 and March 31, 2017, included non-cash stock-based compensation expense of $302,595, $1,041,463 and $291,151, respectively.
General and administrative expenses for the years ended June 30, 2017 and 2016 included non-cash stock-based compensation expense of $1,180,618 and $1,750,209, respectively.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited)
June 30, 2017 | June 30, 2016 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 23,028,153 | $ | 34,077,060 | |||
Receivables | 2,726,702 | 2,638,188 | |||||
Deferred tax asset | — | 105,321 | |||||
Prepaid expenses and other current assets | 387,672 | 265,881 | |||||
Total current assets | 26,142,527 | 37,086,450 | |||||
Property and equipment, net of depreciation, depletion, and amortization | |||||||
Oil and natural gas property and equipment, net (full-cost method of accounting) | 61,790,068 | 59,970,463 | |||||
Other property and equipment, net | 40,689 | 28,649 | |||||
Total property and equipment | 61,830,757 | 59,999,112 | |||||
Other assets | 295,384 | 365,489 | |||||
Total assets | $ | 88,268,668 | $ | 97,451,051 | |||
Liabilities and Stockholders' Equity | |||||||
Current liabilities | |||||||
Accounts payable | $ | 2,101,055 | $ | 5,809,107 | |||
Accrued liabilities and other | 617,839 | 2,097,951 | |||||
State and federal taxes payable | — | 621,850 | |||||
Total current liabilities | 2,718,894 | 8,528,908 | |||||
Long term liabilities | |||||||
Deferred income taxes | 15,826,291 | 11,840,693 | |||||
Asset retirement obligations | 1,253,628 | 760,300 | |||||
Total liabilities | 19,798,813 | 21,129,901 | |||||
Commitments and contingencies (Note 18) | |||||||
Stockholders' equity | |||||||
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued; no shares outstanding at June 30, 2017 as all shares were redeemed November 14, 2016 (Note 10); and 317,319 shares outstanding at June 30, 2016 with a liquidation preference of $7,932,975 ($25.00 per share) | — | 317 | |||||
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,087,308 and 32,907,863 shares as of June 30, 2017 and 2016, respectively | 33,087 | 32,907 | |||||
Additional paid-in capital | 40,961,957 | 47,171,563 | |||||
Retained earnings | 27,474,811 | 29,116,363 | |||||
Total stockholders' equity | 68,469,855 | 76,321,150 | |||||
Total liabilities and stockholders' equity | $ | 88,268,668 | $ | 97,451,051 | |||
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
June 30, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities | |||||||
Net income attributable to the Company | $ | 8,044,313 | $ | 24,660,362 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 5,775,946 | 5,211,494 | |||||
Impairments included in restructuring charge | — | 569,228 | |||||
Stock-based compensation | 1,180,618 | 1,809,548 | |||||
Accretion of discount on asset retirement obligations | 59,664 | 49,054 | |||||
Settlement of asset retirement obligations | (157,910 | ) | — | ||||
Deferred income taxes | 4,090,919 | 575,235 | |||||
(Gain) loss on derivative instruments, net | (29,758 | ) | (3,439,229 | ) | |||
Noncash gain on Delhi field litigation settlement | — | (596,500 | ) | ||||
Write-off of deferred loan costs | — | 50,414 | |||||
Changes in operating assets and liabilities: | |||||||
Receivables | (88,514 | ) | 484,285 | ||||
Prepaid expenses and other current assets | (135,923 | ) | 24,754 | ||||
Accounts payable and accrued expenses | (1,626,648 | ) | 822,730 | ||||
Income taxes payable | (621,850 | ) | 431,818 | ||||
Net cash provided by operating activities | 16,490,857 | 30,653,193 | |||||
Cash flows from investing activities | |||||||
Derivative settlements received | (272,318 | ) | 3,633,831 | ||||
Capital expenditure for development of oil and natural gas properties | (10,158,960 | ) | (21,095,901 | ) | |||
Capital expenditures for technology and other equipment | (32,260 | ) | (6,883 | ) | |||
Other assets | — | (161,345 | ) | ||||
Net cash used by investing activities | (10,463,538 | ) | (17,630,298 | ) | |||
Cash flows from financing activities | |||||||
Proceeds from the exercise of stock options | — | 51,000 | |||||
Common share repurchases, including shares surrendered for tax withholding | (459,858 | ) | (1,357,185 | ) | |||
Cash dividends to common stockholders | (8,432,435 | ) | (6,565,823 | ) | |||
Cash dividends to preferred stockholders | (250,990 | ) | (674,302 | ) | |||
Redemption of preferred shares | (7,932,975 | ) | — | ||||
Deferred loan costs | — | (168,972 | ) | ||||
Tax benefits related to stock-based compensation | — | 9,650,657 | |||||
Other | 32 | 33 | |||||
Net cash provided (used) by financing activities | (17,076,226 | ) | 935,408 | ||||
Net increase (decrease) in cash and cash equivalents | (11,048,907 | ) | 13,958,303 | ||||
Cash and cash equivalents, beginning of year | 34,077,060 | 20,118,757 | |||||
Cash and cash equivalents, end of year | $ | 23,028,153 | $ | 34,077,060 | |||
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Three Months Ended | ||||||||||||||
June 30, 2017 | March 31, 2017 | Variance | Variance % | |||||||||||
Oil and gas production: | ||||||||||||||
Crude oil revenues | $ | 8,366,230 | $ | 9,060,796 | $ | (694,566 | ) | (7.7 | )% | |||||
NGL revenues | 469,472 | 464,641 | 4,831 | 1.0 | % | |||||||||
Total revenues | $ | 8,835,702 | $ | 9,525,437 | $ | (689,735 | ) | (7.2 | )% | |||||
Crude oil volumes (Bbl) | 179,895 | 183,811 | (3,916 | ) | (2.1 | )% | ||||||||
NGL volumes (Bbl) | 24,309 | 19,594 | 4,715 | 24.1 | % | |||||||||
Natural gas volumes (Mcf) | — | — | — | — | % | |||||||||
Equivalent volumes (BOE) | 204,204 | 203,405 | 799 | 0.4 | % | |||||||||
Crude oil (BOPD, net) | 1,977 | 2,042 | (65 | ) | (3.2 | )% | ||||||||
NGLs (BOEPD, net) | 267 | 218 | 49 | 22.5 | % | |||||||||
Natural gas (BOEPD, net) | — | — | — | — | % | |||||||||
Equivalent volumes (BOEPD, net) | 2,244 | 2,260 | (16 | ) | (0.7 | )% | ||||||||
Crude oil price per Bbl | $ | 46.51 | $ | 49.29 | $ | (2.78 | ) | (5.6 | )% | |||||
NGL price per Bbl | 19.31 | 23.71 | (4.40 | ) | (18.6 | )% | ||||||||
Natural gas price per Mcf | — | — | — | — | % | |||||||||
Equivalent price per BOE | $ | 43.27 | $ | 46.83 | $ | (3.56 | ) | (7.6 | )% | |||||
CO2 costs | $ | 1,308,957 | $ | 1,049,035 | $ | 259,922 | 24.8 | % | ||||||
All other lease operating expenses | 2,078,532 | 1,762,223 | 316,309 | 17.9 | % | |||||||||
Production costs | $ | 3,387,489 | $ | 2,811,258 | $ | 576,231 | 20.5 | % | ||||||
Production costs per BOE | $ | 16.59 | $ | 13.82 | $ | 2.77 | 20.0 | % | ||||||
CO2 volumes (Mcf, gross) | 7,748,488 | 5,970,494 | 1,777,994 | 29.8 | % | |||||||||
CO2 volumes (MMcf per day, gross) | 85.1 | 66.3 | 18.8 | 28.4 | % | |||||||||
Oil and gas DD&A (a) | $ | 1,607,085 | $ | 1,515,368 | $ | 91,717 | 6.1 | % | ||||||
Oil and gas DD&A per BOE | $ | 7.87 | $ | 7.45 | $ | 0.42 | 5.6 | % | ||||||
(a) Excludes non-operating depreciation and amortization of $7,896 and $8,107 for the three months ended June 30, 2017 and March 31, 2017, respectively.
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Three Months Ended June 30, | ||||||||||||||
2017 | 2016 | Variance | Variance % | |||||||||||
Oil and gas production: | ||||||||||||||
Crude oil revenues | $ | 8,366,230 | $ | 7,233,190 | $ | 1,133,040 | 15.7 | % | ||||||
NGL revenues | 469,472 | 5,553 | 463,919 | n.m. | ||||||||||
Natural gas revenues | — | 1,691 | (1,691 | ) | (100.0 | )% | ||||||||
Total revenues | $ | 8,835,702 | $ | 7,240,434 | $ | 1,595,268 | 22.0 | % | ||||||
Crude oil volumes (Bbl) | 179,895 | 168,397 | 11,498 | 6.8 | % | |||||||||
NGL volumes (Bbl) | 24,309 | 320 | 23,989 | n.m. | ||||||||||
Natural gas volumes (Mcf) | — | 986 | (986 | ) | (100.0 | )% | ||||||||
Equivalent volumes (BOE) | 204,204 | 168,881 | 35,323 | 20.9 | % | |||||||||
Crude oil (BOPD, net) | 1,977 | 1,851 | 126 | 6.8 | % | |||||||||
NGLs (BOEPD, net) | 267 | 4 | 263 | n.m. | ||||||||||
Natural gas (BOEPD, net) | — | 1 | (1 | ) | (100.0 | )% | ||||||||
Equivalent volumes (BOEPD, net) | 2,244 | 1,856 | 388 | 20.9 | % | |||||||||
Crude oil price per Bbl | $ | 46.51 | $ | 42.95 | $ | 3.56 | 8.3 | % | ||||||
NGL price per Bbl | 19.31 | 17.35 | 1.96 | 11.3 | % | |||||||||
Natural gas price per Mcf | — | 1.72 | (1.72 | ) | (100.0 | )% | ||||||||
Equivalent price per BOE | $ | 43.27 | $ | 42.87 | $ | 0.40 | 0.9 | % | ||||||
CO2 costs | $ | 1,308,957 | $ | 852,862 | $ | 456,095 | 53.5 | % | ||||||
All other lease operating expenses | 2,078,532 | 1,178,780 | 899,752 | 76.3 | % | |||||||||
Production costs | $ | 3,387,489 | $ | 2,031,642 | $ | 1,355,847 | 66.7 | % | ||||||
Production costs per BOE | $ | 16.59 | $ | 12.03 | $ | 4.56 | 37.9 | % | ||||||
CO2 volumes (Mcf, gross) | 7,748,488 | 5,344,143 | 2,404,345 | 45.0 | % | |||||||||
CO2 volumes (MMcf per day, gross) | 85.1 | 58.7 | 26.4 | 45.0 | % | |||||||||
Oil and gas DD&A (a) | $ | 1,607,085 | $ | 1,200,737 | $ | 406,348 | 33.8 | % | ||||||
Oil and gas DD&A per BOE | $ | 7.87 | $ | 7.11 | $ | 0.76 | 10.7 | % | ||||||
n.m. Not meaningful.
(a) Excludes non-operating depreciation and amortization of $7,896 and $5,739 for the three months ended June 30, 2017 and 2016, respectively.
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Year Ended June 30, | ||||||||||||||
2017 | 2016 | Variance | Variance % | |||||||||||
Oil and gas production: | ||||||||||||||
Crude oil revenues | $ | 33,550,698 | $ | 26,130,762 | $ | 7,419,936 | 28.4 | % | ||||||
NGL revenues | 934,202 | 7,885 | 926,317 | n.m. | ||||||||||
Natural gas revenues | (4 | ) | 2,895 | (2,899 | ) | n.m. | ||||||||
Total revenues | $ | 34,484,896 | $ | 26,141,542 | $ | 8,343,354 | 31.9 | % | ||||||
Crude oil volumes (Bbl) | 724,523 | 658,041 | 66,482 | 10.1 | % | |||||||||
NGL volumes (Bbl) | 43,907 | 491 | 43,416 | n.m. | ||||||||||
Natural gas volumes (Mcf) | 16 | 1,620 | (1,604 | ) | n.m. | |||||||||
Equivalent volumes (BOE) | 768,433 | 658,802 | 109,631 | 16.6 | % | |||||||||
Crude oil (BOPD, net) | 1,985 | 1,798 | 187 | 10.4 | % | |||||||||
NGLs (BOEPD, net) | 120 | 1 | 119 | n.m. | ||||||||||
Natural gas (BOEPD, net) | — | 1 | (1 | ) | n.m. | |||||||||
Equivalent volumes (BOEPD, net) | 2,105 | 1,800 | 305 | 16.9 | % | |||||||||
Crude oil price per Bbl | $ | 46.31 | $ | 39.71 | $ | 6.60 | 16.6 | % | ||||||
NGL price per Bbl | 21.28 | 16.06 | 5.22 | 32.5 | % | |||||||||
Natural gas price per Mcf | (0.25 | ) | 1.79 | (2.04 | ) | n.m. | ||||||||
Equivalent price per BOE | $ | 44.88 | $ | 39.68 | $ | 5.20 | 13.1 | % | ||||||
CO2 costs | $ | 4,477,866 | $ | 4,090,938 | $ | 386,928 | 9.5 | % | ||||||
All other lease operating expenses (a) | 6,357,943 | 4,971,241 | 1,386,702 | 27.9 | % | |||||||||
Production costs | $ | 10,835,809 | $ | 9,062,179 | $ | 1,773,630 | 19.6 | % | ||||||
Production costs per BOE | $ | 14.10 | $ | 13.76 | $ | 0.34 | 2.5 | % | ||||||
CO2 volumes (Mcf, gross) | 26,664,188 | 26,996,624 | (332,436 | ) | (1.2 | )% | ||||||||
CO2 volumes (MMcf per day, gross) | 73.1 | 73.8 | (0.7 | ) | (0.9 | )% | ||||||||
Oil and gas DD&A (b) | $ | 5,687,903 | $ | 4,906,123 | $ | 781,780 | 15.9 | % | ||||||
Oil and gas DD&A per BOE | $ | 7.40 | $ | 7.45 | $ | (0.05 | ) | (0.7 | )% | |||||
Artificial lift technology services: | ||||||||||||||
Services revenues | $ | — | $ | 207,960 | $ | (207,960 | ) | (100.0 | )% | |||||
Cost of service | — | 70,932 | (70,932 | ) | (100.0 | )% | ||||||||
Depreciation and amortization expense | $ | — | $ | 238,475 | $ | (238,475 | ) | (100.0 | )% | |||||
n.m. Not meaningful.
(a) Includes ad valorem and production taxes of $214,553, and $294,689 for the years ended June 30, 2017 and 2016, respectively.
(b) Excludes depreciation and amortization expense for artificial lift technology services and $31,502 and $20,522 of other depreciation and amortization expense for the years ended June 30, 2017 and 2016, respectively.
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