Attached files
| file | filename |
|---|---|
| 8-K - 8-K - EVOLUTION PETROLEUM CORP | a8-kearningsfy2016.htm |
Exhibit 99.1
 | Company Contact: |
Randy Keys, CEO | |
(713) 935-0122 | |
rkeys@evolutionpetroleum.com | |
Evolution Petroleum Announces Results for Fiscal Year 2016
Houston, TX, September 7, 2016 - Evolution Petroleum Corporation (NYSE MKT: EPM) today reported financial and operating highlights for its fiscal year and fourth quarter ended June 30, 2016, with comparisons to the fiscal third quarter ended March 31, 2016 (the "prior quarter") and the quarter ended June 30, 2015 (the "year-ago quarter"), as well as the prior fiscal year ended June 30, 2015.
Highlights:
• | Generated $24.0 million in net income for the year, or $0.73 per common share, with the proceeds of the litigation settlement on top of another profitable year. |
• | Improved our balance sheet strength further, finishing the year with $28.6 million of working capital and no debt. |
• | Resolved litigation with the operator of the Delhi field and received a cash settlement of $27.5 million and other consideration. |
• | Funded all operations, including $21.1 million of capital spending to grow Delhi production and $6.6 million of cash dividends to common shareholders, from internal resources without drawing on our new bank facility. |
• | Implemented successful price risk management program that yielded $3.4 million of net gains. |
• | Continued positive operating trends in the Delhi field, with gross production up over 600 barrels of oil equivalent per day (BOEPD) during the year and historically low lifting costs under $12 per barrel in the fourth quarter. |
Randy Keys, President and CEO, said: “The settlement of our Delhi field lawsuit removes the uncertainty and significant legal expense of continuing litigation, while adding $27.5 million in cash and other significant value to the Company. This clears the slate for a more productive relationship with the operator and the opportunity for other meaningful growth opportunities. We had a very productive year, with the Delhi field outperforming our production expectations and generating very strong cash operating margins in this challenging price environment. We are nearing completion of the NGL plant in the Delhi field, a $25 million capital project net to Evolution, and are looking forward to a substantial increase in liquids production as a result by the end of this calendar year. With the majority of this capital spending behind us, the near-term financial outlook is very positive. We have an exceptionally strong balance sheet, consisting of $28.6 million in working capital and the additional resources of an undrawn reserve-based credit line. Our current cash flow from the Delhi field prior to the contributions from the NGL plant is significantly above our current dividend requirements, which further increases our financial capabilities. We ended the current fiscal year in our best position since this industry downturn began two years ago.”
Financial Results for the Quarter Ended June 30, 2016
In the current quarter, we reported operating revenues of $7.2 million, based on an average realized oil price of $42.95 per barrel, and generated $1.0 million in income from operations. In the prior quarter, we reported a $0.7 million loss from operations on revenues of $5.1 million, which was based on decade-low oil prices of $30.00 per barrel. Production volumes increased slightly to 1,856 barrels of oil equivalent per day (BOEPD) from 1,835 BOEPD in the prior quarter and were 10% above the year-ago quarter rate of 1,683 BOEPD. Quarterly net income to common shareholders was $20.7 million, or $0.63 per diluted share, which includes the after-tax effect of the $27.5 million cash litigation settlement in the quarter.
Production costs in the Delhi field declined 7% from $2.2 million in the prior quarter to $2.0 million in the current quarter as lower volumes of purchased CO2 more than offset an increase in CO2 costs, which are tied directly to realized oil prices in the field. If we experience increasing oil prices in the
future, we may see our purchased CO2 costs trend back up, but this should be more than offset by higher revenues and an expanding field margin. Depletion, depreciation and amortization expense decreased slightly to $1.2 million from $1.3 million in the prior quarter, as a small reduction in the DD&A rate per barrel exceeded the effects of slightly higher production. Our general and administrative expenses were $3.0 million for the quarter, which represents a substantial increase over the prior quarter and year-ago quarter. The majority of this increase resulted from higher litigation expenses and also higher non-cash stock-based compensation expense associated with the achievement of net income performance targets.
Financial Results for the Year Ended June 30, 2016
For fiscal 2016, net income to common shareholders was $24.0 million, or $0.73 per share. Revenues for the year totaled $26.3 million, based on net production of 1,800 BOEPD and an average realized price of $39.68 per barrel. Our revenues in the prior year were approximately 5% higher at $27.8 million, on a much higher average price of $61.37 per barrel. Net production was substantially lower in 2015 as we did not earn our reversionary working interest until November 2014 and only had eight months of working interest production, combined with lower gross field production. During the year, we initiated and executed an oil price risk management program that resulted in net gains of $3.4 million. These gains, which are reported as other income, had the effect of increasing our realized oil price by $5.22 per barrel, or 13% of our actual realized oil price.
As a result of the reversion of our working interest in late 2014, our production costs are also not fully comparable between periods. Despite that, our average lifting cost of $13.76 per barrel improved substantially during the year and was dramatically lower than our exit rate last year of $18.52 per barrel in the year-ago fourth quarter. This favorable lifting cost allowed us to maintain a substantial positive field margin during periods when we tested multi-year lows in oil prices. Our depreciation and depletion expense in the current year was higher due to the significant increase in net production, though our DD&A rate was only 5% above the rate for last year at $7.45 per barrel. Unlike many of our peers, we did not suffer a write-down of capitalized costs due to the low price environment.
Our general and administrative costs were higher in the current year, increasing from $6.3 million to $9.1 million. The current year includes approximately $2.7 million of litigation costs and increased compensation expense associated with the achievement of above target net income performance. We have worked diligently to bring our G&A costs down over time by reducing staff, relocating to a smaller office and settling the Delhi-related litigation. As a result, our current G&A budget for fiscal 2017 is slightly below $5.0 million. If successful, this budget will bring our costs down to the lowest level in over three years.
Reserves
Summary Reserves as of June 30, 2016 | ||||||||
Oil MBO | NGL MBL | Equivalent MBOE | ||||||
Proved Developed | 7,168 | — | 7,168 | |||||
Proved Undeveloped | 1,420 | 2,235 | 3,655 | |||||
Total Proved | 8,588 | 2,235 | 10,823 | |||||
Probable Developed | 3,092 | — | 3,092 | |||||
Probable Undeveloped | 471 | 934 | 1,405 | |||||
Total Probable* | 3,563 | 934 | 4,497 | |||||
Possible Developed | 1,964 | — | 1,964 | |||||
Possible Undeveloped | 187 | 563 | 750 | |||||
Total Possible* | 2,151 | 563 | 2,714 | |||||
Cautionary Note to Investors * - Our reserves as of June 30, 2016 and 2015 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. All reserve estimates are continually subject to revision 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 of the amount of oil and natural gas liquids that is 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.
Evolution also reported year-end reserves as of June 30, 2016 with comparisons to the prior year ended June 30, 2015. For the year ended June 30, 2016, our proved reserves in the Delhi field totaled 10.8 MMBOE, a reduction of 1.6 MMBOE from the prior year. This net change in proved reserves is comprised of 0.7 MMBOE of production in the prior year and 0.9 MMBOE of revisions to part of the remaining eastern development area. The area we refer to as Test Site 6, which is the development area on the farthest eastern edge of the field, was deemed to be uneconomic using the low SEC price assumption for the remaining life of the field. As a result of the downturn in our industry, our trailing twelve month average oil price, as specified by SEC guidelines, was $40.91 per barrel in the Delhi field. This price is based on a NYMEX WTI reference price of $42.91 per barrel and is at least $7.00 per barrel lower than the price used by our peers that reported reserves as of December 31, 2015.
The larger part of the eastern development area, which we refer to as Test Site 5, totals 1.4 MMBOE, and remains solidly economic even in this low price environment. Test Site 5 has industry-competitive future development costs of slightly over $8.00 per barrel. It is noteworthy that even in this very low price environment, we did not lose significant future production volumes or economic life from our proved developed producing reserves at Delhi. The remaining economic life of the proved reserves in the field under these low price assumptions is still approximately 25 years. Under the probable reserve case, the field has a productive life in excess of 30 years.
Our probable reserves, however, declined significantly as a result of these lower price assumptions, dropping from 9.5 MMBOE in the prior year to 4.5 MMBOE. The majority of these revisions resulted from lower prices and their effect on the deemed economics of future development projects, while a lesser portion resulted from changes to the operator’s long-term development plans for the field. Our possible reserves of 2.7 MMBOE were affected to a much lesser degree than our probable reserves as the removal of certain proved and probable projects from the reserves report was
substantially offset by positive revisions from improved field performance. With the significant revisions to our probable reserves, our current probable and possible reserves now reflect only the incremental recoveries associated with our existing proved reserves. These recoveries are based on a range of assumptions, from a conservative view of 13.8% recovery in the proved case, to 18.0% total recovery in the probable case, to a total recovery of 20.5% in the possible case.
The discounted value of future net revenues from our proved reserves is typically computed under two different methods, both of which are useful for analysts and other readers of our financial statements. One measure, which conforms to 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 Generally Accepted Accounting Principles (“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 prices in the field, held flat 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) | $ | 78.0 | million | |
Future Income Tax Expenses Discounted at 10% | 22.9 | million | ||
PV-10 Value of Proved Reserves | $ | 100.9 | million | |
The $100.9 million PV-10 value above is comprised of $88.9 million for proved developed producing reserves and $12.0 million for proved undeveloped reserves. It is not practical to allocate future income taxes and compute SMOG values for producing versus undeveloped reserves.
Reserve Price Sensitivities
With the significant volatility in oil and gas prices over the past two years, we do not believe the present value of our reserves calculated under the SEC pricing model provides a complete view of the potential value of our proved reserves and our Company. Accordingly, we are also presenting our discounted present values using two different pricing assumptions to show the hypothetical effect on our present values from a recovery in oil prices. One is based on a NYMEX WTI reference price of $50.00 per barrel and the other is based on a reference price of $60.00. The $50.00 price case is very similar to the one used by our peers at December 31, 2015. In each case, oil and NGL prices were held constant for the life of the property, consistent with SEC guidelines and costs were adjusted only for expenses which have a variable component based on prices or revenues. For comparability purposes, the mix of properties did not change in either case, so there were no properties which were deemed uneconomic at a $42.91 NYMEX price, that were reinstated and included in the higher price cases. The values of our properties under these various price scenarios are reflected in the schedule below:
SEC Case | $50 Case | $60 Case | |||||||||
NYMEX WTI Reference Price | $ | 42.91 | $ | 50.00 | $ | 60.00 | |||||
Estimated Net Realized Price | 40.91 | 47.94 | 57.86 | ||||||||
PV-10 Values ($MM): | |||||||||||
Proved Developed Producing | $ | 88.9 | $ | 112.5 | $ | 145.9 | |||||
Proved Undeveloped | 12.0 | 19.7 | 30.5 | ||||||||
Total Proved PV-10% | $ | 100.9 | $ | 132.2 | $ | 176.4 | |||||
Future Income Tax Expenses Discounted at 10% | (22.9 | ) | (32.9 | ) | (47.8 | ) | |||||
GAAP Standardized Measure ($MM) | $ | 78.0 | $ | 99.3 | $ | 128.6 | |||||
Delhi Operations and Field Performance
The Delhi field has performed well above our production expectations from a year ago. In the reserves report as of June 30, 2015, our reservoir engineers were projecting an average gross production
rate for the 2016 fiscal year of slightly over 6,200 BOPD, whereas our actual rate was almost 6,800 BODP, an increase of almost 10%. The majority of this improved production is attributable to efforts to selectively improve the performance of 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. This bodes very well for the long term recovery outlook in the Delhi field. We have already seen a strong indication of this in our reserves report as the expected ultimate recovery of our probable reserves has been increased from 17% to 18% and the timing of recovery has been significantly accelerated as well. The production rates for the proved developed producing reserves have also been accelerated. We believe this represents a first step toward an increase in proved reserves from the field and ultimate recoveries which are closer to the probable projections than the current proved reserves.
We believe our NGL plant, nearing completion, will be a near-term catalyst for significant production growth from the field. This project was authorized in February 2015 and we are expecting a technical completion date of November 1, 2016. After a short period of startup testing, we expect full production around the end of the calendar year. The NGL plant costs are projected to be close to the original budget of $25 million net to the Company and we are pleased that we see no indications of any significant cost overruns thus far.
We have also experienced very favorable trends in our lifting costs in the Delhi field and these lower lifting costs have had a positive impact on the economics, present value and estimated economic life of the field. A substantial part of our costs result from new purchased CO2 for injection into the field. The cost of this purchased CO2 is directly correlated to oil prices and therefore our lifting costs have a significant variable aspect which is tied to the price received for our oil. This helps us maintain a positive field margin, even when oil prices decline. Our other lifting costs have been subject to aggressive cost reductions and have benefitted to some degree from lower overall costs for goods and services during the current downturn in the industry.
Artificial Lift Technology
In December 2015, as previously disclosed, we completed a transaction to separate our artificial lift technology operations into Well Lift Inc., a separate company controlled by our former SVP of Operations, who is the inventor of the technology. We retained a non-controlling minority interest in Well Lift Inc., with upside potential through convertible preferred stock and a 5% royalty on revenues related to the patents and other intellectual property conveyed. This transaction reduced our headcount from nine to six and is expected to reduce our corporate overhead by approximately $1MM per year.
Fiscal 2017 Capital Budget and Financial Outlook
We currently expect remaining capital expenditures for the NGL plant over the next fiscal year to be $3.5 million. There will likely be other smaller capital projects to enhance and maintain the effectiveness of the CO2 flood. The amount of these expenditures cannot be estimated at this time, but is not expected to be material to our financial position. Unless the operator decides to accelerate the expansion of the CO2 flood to the eastern part of the field, we do not expect any other significant capital spending needs during the next fiscal year. The project to continue the eastern expansion of the Delhi field could occur as early as calendar 2017, but we consider it more likely that this project will be scheduled for calendar 2018. As with most capital projects in our industry, the timing is dependent on a range of factors, with oil prices being the most prominent in the current environment.
Our liquidity position is very strong, with $28.6 million of working capital, undrawn liquidity under our reserve-based credit facility and the expectation of significant free cash flow over the next fiscal year. This cash flow is dependent, of course, on the net prices we receive for our production, net of any proceeds for price risk management activities. Based on our solid financial position, we expect to continue our common stock cash dividend program for the foreseeable future, and will evaluate the options of increasing common dividends, resuming the purchase of shares under our stock repurchase program and potentially redeeming our preferred shares.
Conference Call
As previously announced, Evolution Petroleum will host a conference call on Thursday, September 8, 2016 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 two hours after the end of the conference call through September 15, 2016 by calling 1-877-870-5176 (US and Canada) or 1-858-384-5517 (International) and providing the replay pin passcode of 10001611.
About Evolution Petroleum
Evolution Petroleum Corporation develops petroleum reserves and shareholder value by applying conventional and specialized technology to known oil and gas resources, onshore in the United States. Our principal asset is our interest in a CO2-EOR 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
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
Three Months Ended | |||||||||||||||||||
June 30, | March 31, | Years Ended June 30, | |||||||||||||||||
2016 | 2015 | 2016 | 2016 | 2015 | |||||||||||||||
Revenues | |||||||||||||||||||
Crude oil | $ | 7,233,190 | $ | 9,060,995 | $ | 5,005,955 | $ | 26,130,762 | $ | 27,761,291 | |||||||||
Natural gas liquids | 5,553 | 1,873 | 597 | 7,885 | 37,227 | ||||||||||||||
Natural gas | 1,691 | 814 | 183 | 2,895 | 26,601 | ||||||||||||||
Artificial lift technology services | — | — | 100,000 | 207,960 | 16,146 | ||||||||||||||
Total revenues | 7,240,434 | 9,063,682 | 5,106,735 | 26,349,502 | 27,841,265 | ||||||||||||||
Operating costs | |||||||||||||||||||
Production costs | 2,031,642 | 2,836,606 | 2,192,217 | 9,062,179 | 9,335,244 | ||||||||||||||
Cost of artificial lift technology services | — | 13,325 | 10,933 | 70,932 | 20,369 | ||||||||||||||
Depreciation, depletion and amortization | 1,206,476 | 1,190,128 | 1,268,800 | 5,165,120 | 3,615,737 | ||||||||||||||
Accretion of discount on asset retirement obligations | 14,499 | 11,169 | 11,695 | 49,054 | 34,866 | ||||||||||||||
General and administrative expenses* | 3,032,994 | 1,677,907 | 2,304,237 | 9,079,597 | 6,256,783 | ||||||||||||||
Restructuring charges | — | — | — | 1,257,433 | (5,431 | ) | |||||||||||||
Total operating costs | 6,285,611 | 5,729,135 | 5,787,882 | 24,684,315 | 19,257,568 | ||||||||||||||
Income from operations | 954,823 | 3,334,547 | (681,147 | ) | 1,665,187 | 8,583,697 | |||||||||||||
Other | |||||||||||||||||||
Gain on settled derivative instruments, net | (644,936 | ) | — | 1,795,431 | 3,315,123 | — | |||||||||||||
Gain (loss) on unsettled derivative instruments, net | 4,427 | (109,974 | ) | (1,314,044 | ) | 124,106 | (109,974 | ) | |||||||||||
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 | 2,695 | 8,165 | 11,851 | 26,211 | 35,991 | ||||||||||||||
Interest (expense) | (19,781 | ) | (18,392 | ) | (14,036 | ) | (70,943 | ) | (73,636 | ) | |||||||||
Income before income tax provision | 28,393,728 | 3,214,346 | (201,945 | ) | 34,231,141 | 8,436,078 | |||||||||||||
Income tax provision | 7,519,258 | 1,326,003 | (72,337 | ) | 9,570,779 | 3,444,221 | |||||||||||||
Net income attributable to the Company | 20,874,470 | 1,888,343 | (129,608 | ) | 24,660,362 | 4,991,857 | |||||||||||||
Dividends on preferred stock | 168,576 | 168,576 | 168,575 | 674,302 | 674,302 | ||||||||||||||
Net income attributable to common shareholders | $ | 20,705,894 | $ | 1,719,767 | $ | (298,183 | ) | $ | 23,986,060 | $ | 4,317,555 | ||||||||
Earnings per common share | |||||||||||||||||||
Basic | $ | 0.63 | $ | 0.05 | $ | (0.01 | ) | $ | 0.73 | $ | 0.13 | ||||||||
Diluted | $ | 0.63 | $ | 0.05 | $ | (0.01 | ) | $ | 0.73 | $ | 0.13 | ||||||||
Weighted average number of common shares outstanding | |||||||||||||||||||
Basic | 32,904,481 | 32,903,020 | 32,879,381 | 32,810,375 | 32,817,456 | ||||||||||||||
Diluted | 32,964,109 | 32,967,583 | 32,879,381 | 32,861,231 | 32,924,018 | ||||||||||||||
* | General and administrative expenses for the quarters ended June 30, 2016, June 30, 2015 and March 31, 2016 included non-cash stock-based compensation expense of $1,041,463, $227,789 and $277,907, respectively. These quarters also correspondingly included $646,931, $468,209, and $1,076,343 of litigation expenses. |
General and administrative expenses for the years ended June 30, 2016 and 2015 included non-cash stock-based compensation expense of $1,750,209, and $943,653, respectively, as well as litigation expense of $2,729,755 and $1,015,105, respectively.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited)
June 30, 2016 | June 30, 2015 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 34,077,060 | $ | 20,118,757 | |||
Receivables | 2,638,188 | 3,122,473 | |||||
Deferred tax asset | 105,321 | 82,414 | |||||
Derivative assets, net | 14,132 | — | |||||
Prepaid expenses and other current assets | 251,749 | 369,404 | |||||
Total current assets | 37,086,450 | 23,693,048 | |||||
Property and equipment, net of depreciation, depletion, and amortization | |||||||
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization | 59,970,463 | 45,186,886 | |||||
Other property and equipment, net | 28,649 | 276,756 | |||||
Total property and equipment, net | 59,999,112 | 45,463,642 | |||||
Other assets | 365,489 | 726,037 | |||||
Total assets | $ | 97,451,051 | $ | 69,882,727 | |||
Liabilities and Stockholders' Equity | |||||||
Current liabilities | |||||||
Accounts payable | $ | 5,809,107 | $ | 8,173,878 | |||
Accrued liabilities and other | 2,097,951 | 855,373 | |||||
Derivative liabilities, net | — | 109,974 | |||||
State and federal taxes payable | 621,850 | 190,032 | |||||
Total current liabilities | 8,528,908 | 9,329,257 | |||||
Long term liabilities | |||||||
Deferred income taxes | 11,840,693 | 11,242,551 | |||||
Asset retirement obligations | 760,300 | 715,767 | |||||
Deferred rent | — | 18,575 | |||||
Total liabilities | 21,129,901 | 21,306,150 | |||||
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 and outstanding at June 30, 2016 and 2015, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share) | 317 | 317 | |||||
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,907,863 and 32,845,205 shares as of June 30, 2016 and 2015, respectively | 32,907 | 32,845 | |||||
Additional paid-in capital | 47,171,563 | 36,847,289 | |||||
Retained earnings | 29,116,363 | 11,696,126 | |||||
Total stockholders' equity | 76,321,150 | 48,576,577 | |||||
Total liabilities and stockholders' equity | $ | 97,451,051 | $ | 69,882,727 | |||
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
Years Ended June 30, | |||||||||||
2016 | 2015 | 2014 | |||||||||
Cash flows from operating activities | |||||||||||
Net income attributable to the Company | $ | 24,660,362 | $ | 4,991,857 | $ | 3,597,313 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation, depletion and amortization | 5,211,494 | 3,664,373 | 1,272,778 | ||||||||
Impairments included in restructuring charge | 569,228 | — | — | ||||||||
Stock-based compensation | 1,750,209 | 943,653 | 1,352,322 | ||||||||
Stock-based compensation related to restructuring | 59,339 | — | 376,365 | ||||||||
Accretion of discount on asset retirement obligations | 49,054 | 34,866 | 41,626 | ||||||||
Settlement of asset retirement obligations | — | (223,564 | ) | (315,952 | ) | ||||||
Deferred income taxes | 575,235 | 1,422,489 | 1,344,812 | ||||||||
Deferred rent | — | (17,145 | ) | (17,145 | ) | ||||||
(Gain) loss on derivative instruments, net | (3,439,229 | ) | 109,974 | — | |||||||
Noncash (gain) on Delhi field litigation settlement | (596,500 | ) | — | — | |||||||
Write-off of deferred loan costs | 50,414 | — | — | ||||||||
Changes in operating assets and liabilities: | |||||||||||
Receivables | 484,285 | (1,665,261 | ) | 507,592 | |||||||
Prepaid expenses and other current assets | 24,754 | 378,049 | (480,899 | ) | |||||||
Accounts payable and accrued expenses | 822,730 | 551,452 | 663,645 | ||||||||
Income taxes payable | 431,818 | 190,032 | (233,548 | ) | |||||||
Net cash provided by operating activities | 30,653,193 | 10,380,775 | 8,108,909 | ||||||||
Cash flows from investing activities | |||||||||||
Derivative settlements received | 3,633,831 | — | — | ||||||||
Proceeds from asset sales | — | 398,242 | 542,347 | ||||||||
Development of oil and natural gas properties | (21,095,901 | ) | (4,890,909 | ) | (966,931 | ) | |||||
Acquisitions of oil and natural gas properties | — | — | (59,315 | ) | |||||||
Capital expenditures for technology and other equipment | (6,883 | ) | (313,059 | ) | (312,890 | ) | |||||
Maturities of certificates of deposit | — | — | 250,000 | ||||||||
Other assets | (161,345 | ) | (236,559 | ) | (202,017 | ) | |||||
Net cash used by investing activities | (17,630,298 | ) | (5,042,285 | ) | (748,806 | ) | |||||
Cash flows from financing activities | |||||||||||
Proceeds from the exercise of stock options | 51,000 | 141,600 | 3,252,801 | ||||||||
Acquisitions of treasury stock | (1,357,185 | ) | (333,841 | ) | (1,655,251 | ) | |||||
Common stock dividends paid | (6,565,823 | ) | (9,833,642 | ) | (9,723,833 | ) | |||||
Preferred stock dividends paid | (674,302 | ) | (674,302 | ) | (674,302 | ) | |||||
Deferred loan costs | (168,972 | ) | (94,075 | ) | (63,535 | ) | |||||
Tax benefits related to stock-based compensation | 9,650,657 | 1,633,946 | 509,096 | ||||||||
Other | 33 | 67 | 6,850 | ||||||||
Net cash provided (used) by financing activities | 935,408 | (9,160,247 | ) | (8,348,174 | ) | ||||||
Net increase (decrease) in cash and cash equivalents | 13,958,303 | (3,821,757 | ) | (988,071 | ) | ||||||
Cash and cash equivalents, beginning of year | 20,118,757 | 23,940,514 | 24,928,585 | ||||||||
Cash and cash equivalents, end of year | $ | 34,077,060 | $ | 20,118,757 | $ | 23,940,514 | |||||
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Three Months Ended | ||||||||||||||
June 30, 2016 | March 31, 2016 | Variance | Variance % | |||||||||||
Oil and gas production: | ||||||||||||||
Crude oil revenues | $ | 7,233,190 | $ | 5,005,955 | $ | 2,227,235 | 44.5 | % | ||||||
NGL revenues | 5,553 | 597 | 4,956 | 830.2 | % | |||||||||
Natural gas revenues | 1,691 | 183 | 1,508 | 824.0 | % | |||||||||
Total revenues | $ | 7,240,434 | $ | 5,006,735 | $ | 2,233,699 | 44.6 | % | ||||||
Crude oil volumes (Bbl) | 168,397 | 166,881 | 1,516 | 0.9 | % | |||||||||
NGL volumes (Bbl) | 320 | 47 | 273 | 580.9 | % | |||||||||
Natural gas volumes (Mcf) | 986 | 145 | 841 | 580.0 | % | |||||||||
Equivalent volumes (BOE) | 168,881 | 166,952 | 1,929 | 1.2 | % | |||||||||
Equivalent volumes per day (BOE/D) | 1,856 | 1,835 | 21 | 1.1 | % | |||||||||
Crude oil price per Bbl | $ | 42.95 | $ | 30.00 | $ | 12.95 | 43.2 | % | ||||||
NGL price per Bbl | 17.35 | 12.70 | 4.65 | 36.6 | % | |||||||||
Natural gas price per Mcf | 1.72 | 1.26 | 0.46 | 36.5 | % | |||||||||
Equivalent price per BOE | $ | 42.87 | $ | 29.99 | $ | 12.88 | 42.9 | % | ||||||
Production costs | $ | 2,031,642 | $ | 2,192,217 | $ | (160,575 | ) | (7.3 | )% | |||||
Production costs per BOE | $ | 12.03 | $ | 13.13 | $ | (1.10 | ) | (8.4 | )% | |||||
Oil and gas DD&A (a) | $ | 1,200,737 | $ | 1,262,164 | $ | (61,427 | ) | (4.9 | )% | |||||
Oil and gas DD&A per BOE | $ | 7.11 | $ | 7.56 | $ | (0.45 | ) | (6.0 | )% | |||||
Artificial lift technology services: | ||||||||||||||
Services revenues | $ | — | $ | 100,000 | $ | (100,000 | ) | (100.0 | )% | |||||
Cost of service | — | 10,933 | (10,933 | ) | (100.0 | )% | ||||||||
Depreciation and amortization expense | $ | — | $ | — | $ | — | — | % | ||||||
(a) Excludes $5,739 and $6,636 of other depreciation and amortization expense for the three months ended June 30 and March 31, 2016, respectively.
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Three Months Ended June 30, | ||||||||||||||
2016 | 2015 | Variance | Variance % | |||||||||||
Oil and gas production: | $ | 7,233,190 | $ | 9,060,995 | $ | (1,827,805 | ) | (20.2 | )% | |||||
Crude oil revenues | 5,553 | 1,873 | 3,680 | 196.5 | % | |||||||||
NGL revenues | 1,691 | 814 | 877 | 107.7 | % | |||||||||
Natural gas revenues | $ | 7,240,434 | $ | 9,063,682 | $ | (1,823,248 | ) | (20.1 | )% | |||||
Total revenues | ||||||||||||||
168,397 | 153,004 | 15,393 | 10.1 | % | ||||||||||
Crude oil volumes (Bbl) | 320 | 107 | 213 | 199.1 | % | |||||||||
NGL volumes (Bbl) | 986 | 394 | 592 | 150.3 | % | |||||||||
Natural gas volumes (Mcf) | 168,881 | 153,177 | 15,704 | 10.3 | % | |||||||||
Equivalent volumes (BOE) | ||||||||||||||
1,856 | 1,683 | 173 | 10.3 | % | ||||||||||
Equivalent volumes per day (BOE/D) | ||||||||||||||
$ | 42.95 | $ | 59.22 | $ | (16.27 | ) | (27.5 | )% | ||||||
Crude oil price per Bbl | 17.35 | 17.50 | (0.15 | ) | (0.9 | )% | ||||||||
NGL price per Bbl | 1.72 | 2.07 | (0.35 | ) | (16.9 | )% | ||||||||
Natural gas price per Mcf | $ | 42.87 | $ | 59.17 | $ | (16.30 | ) | (27.5 | )% | |||||
Equivalent price per BOE | ||||||||||||||
$ | 2,031,642 | $ | 2,836,606 | $ | (804,964 | ) | (28.4 | )% | ||||||
Production costs | $ | 12.03 | $ | 18.52 | $ | (6.49 | ) | (35.0 | )% | |||||
Production costs per BOE | ||||||||||||||
$ | 1,200,737 | $ | 1,159,550 | $ | 41,187 | 3.6 | % | |||||||
Oil and gas DD&A (a) | $ | 7.11 | $ | 7.57 | $ | (0.46 | ) | (6.1 | )% | |||||
Oil and gas DD&A per BOE | ||||||||||||||
Artificial lift technology services: | ||||||||||||||
Services revenues | $ | — | $ | — | $ | — | — | % | ||||||
Cost of service | — | 13,325 | (13,325 | ) | n.m. | |||||||||
Depreciation and amortization expense | $ | — | $ | 26,165 | $ | (26,165 | ) | (100.0 | )% | |||||
n.m. Not meaningful.
(a) Excludes depreciation and amortization expense for artificial lift technology services below and $5,739 and $4,413 of other depreciation and amortization expense for the three months ended June 30, 2016 and 2015, respectively.
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Years Ended June 30, | ||||||||||||||
2016 | 2015 | Variance | Variance % | |||||||||||
Oil and gas production: | ||||||||||||||
Crude oil revenues | $ | 26,130,762 | $ | 27,761,291 | $ | (1,630,529 | ) | (5.9 | )% | |||||
NGL revenues | 7,885 | 37,227 | (29,342 | ) | (78.8 | )% | ||||||||
Natural gas revenues | 2,895 | 26,601 | (23,706 | ) | (89.1 | )% | ||||||||
Total revenues | $ | 26,141,542 | $ | 27,825,119 | $ | (1,683,577 | ) | (6.1 | )% | |||||
Crude oil volumes (Bbl) | 658,041 | 450,713 | 207,328 | 46.0 | % | |||||||||
NGL volumes (Bbl) | 491 | 1,358 | (867 | ) | (63.8 | )% | ||||||||
Natural gas volumes (Mcf) | 1,620 | 7,981 | (6,361 | ) | (79.7 | )% | ||||||||
Equivalent volumes (BOE) | 658,802 | 453,401 | 205,401 | 45.3 | % | |||||||||
Equivalent volumes per day (BOE/D) | 1,800 | 1,242 | 558 | 44.9 | % | |||||||||
Crude oil price per Bbl | $ | 39.71 | $ | 61.59 | $ | (21.88 | ) | (35.5 | )% | |||||
NGL price per Bbl | 16.06 | 27.41 | (11.35 | ) | (41.4 | )% | ||||||||
Natural gas price per Mcf | 1.79 | 3.33 | (1.54 | ) | (46.2 | )% | ||||||||
Equivalent price per BOE | $ | 39.68 | $ | 61.37 | $ | (21.69 | ) | (35.3 | )% | |||||
Production costs | $ | 9,062,179 | $ | 9,335,244 | $ | (273,065 | ) | (2.9 | )% | |||||
Production costs per BOE | $ | 13.76 | $ | 20.59 | $ | (6.83 | ) | (33.2 | )% | |||||
Oil and gas DD&A (a) | $ | 4,906,123 | $ | 3,220,990 | $ | 1,685,133 | 52.3 | % | ||||||
Oil and gas DD&A per BOE | $ | 7.45 | $ | 7.10 | $ | 0.35 | 4.9 | % | ||||||
Artificial lift technology services: | ||||||||||||||
Services revenues | $ | 207,960 | $ | 16,146 | $ | 191,814 | 1,188.0 | % | ||||||
Cost of service | 70,932 | 20,369 | 50,563 | 248.2 | % | |||||||||
Depreciation and amortization expense | $ | 238,475 | $ | 374,371 | $ | (135,896 | ) | (36.3 | )% | |||||
(a) Excludes depreciation and amortization expense for artificial lift technology services below and $20,522 and $20,376 of other depreciation and amortization expense for the years ended June 30, 2016 and 2015, respectively.
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