EPSILON ENERGY LTD. The following discussion is intended to assist in the understanding of trends and significant changes in or results of operations and the financial condition ofEpsilon Energy Ltd. and its subsidiaries for the periods presented. This section should be read in conjunction with the audited consolidated financial statements as ofDecember 31, 2021 and 2020 and for the years then ended together with accompanying notes.
Overview
Epsilon Energy Ltd. (the "Company") is a North American onshore focused independent natural gas and oil company engaged in the acquisition, development, gathering and production of natural gas and oil reserves. Our primary area of operation isPennsylvania . Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Substantially all of the production from ourPennsylvania acreage (4,597 net) is dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located inSusquehanna County, Pennsylvania for a 15-year term expiring in 2026 under an operating agreement whereby the Auburn GGS owners receive a fixed percentage rate of return on the total capital invested in the construction of the system. Epsilon owns a 35% interest in the system which is operated by a subsidiary ofWilliams Partners, LP . In 2021, we paid$1.6 million to the Auburn GGS to gather and treat our 9.8 Bcf of natural gas production inPennsylvania ($1.8 million to the Auburn GGS to gather and treat our 11.0 Bcf in 2020). AtDecember 31, 2021 our total estimated net proved reserves were 110,969 million cubic feet (MMcf) of natural gas reserves, 819,726 barrels (Bbl) of NGL reserves, and 305,052 barrels (Bbl) of oil and other liquids, and we held leasehold rights to approximately 76,544 gross (13,176 net) acres. We have natural gas production inPennsylvania , and natural gas, oil and other liquid production from our operated and non-operated wells inOklahoma .
Business Strategy
Our business strategy is to manage the cash flow generated from our producing leasehold and midstream assets in a manner where the risked capital allocation provides attractive rates of return. Our remaining inventory of drillable locations within existing leasehold is sufficient to maintain this cash flow for several years at capital expenditure levels well within the yearly free cash flow generated from these assets. In addition, we seek to identify attractive onshore natural gas and oil properties inthe United States , to acquire leasehold interests and to develop our leasehold interests with the goal of deploying capital to earn attractive rates of return. The coreMarcellus Shale is one of the most attractive dry gas resources inthe United States and has attracted significant development capital. Well productivity has improved dramatically for many years due to improving techniques in drilling and completing wells, resulting in increasing initial production rates and gas recoveries. The resulting supply of natural gas at times stresses the transportation infrastructure of the Northeast US and exacerbates the local price discount toHenry Hub . In many other basins throughout the US, the increase in natural gas production had historically outpaced demand. Over the past couple of years, this over supply condition has become more balanced and demand growth from increased LNG exports and pipeline exports toMexico have provided attractive markets improving the prices for natural gas. The operating environment remains challenging inNortheast Pennsylvania . We implemented a number of initiatives to enhance the value of our core assets in the Marcellus including a comprehensive review of well spacing and completion productivity for both the Lower and Upper Marcellus, and we are working with our well operators to increase operating efficiency. In addition, we continue to work closely with our gathering system partners in order to optimize the operating conditions, enhance operational safety, and to preserve and grow the long-term value of our gathering system assets. 33 The major producers in the Appalachian region are under pressure from capital markets to demonstrate capital discipline and control costs. Several major producers have announced reduced capital programs to balance the supply-demand for the commodity. Accordingly, we expect local production during 2022 to be flat compared to 2021. Our target is to maintain our current production level or grow modestly, but only if natural gas price levels are sufficient and the capital deployed can achieve our internal hurdle rate of return. In the longer term, we believe natural gas prices will remain constructive due to moderating supply from both dry gas regions and associated gas from oil prone basins, and incremental demand from LNG exports, exports toMexico and further coal to gas switching for domestic electrical power generation. Specifically, LNG export capacity is expected to grow from the current ~ 13 Bcf/d to 17 Bcf/d by 2024 based only on facilities currently commissioning or under construction. In the Northwest STACK ofOklahoma , we continue to appraise recent and historical results of the Meramec formation from both our wells and analog wells within the focus area. AtDecember 31, 2021 , our initial well continues to outperform the pre-completion type curve expectations in terms of both production-to-date and projections for ultimate recoveries. The Company has drilled, but has not yet completed, additional Meramec appraisal wells within the focus area to prove a greater area for further exploitation on an opportunistically prudent timeline. We realized net income of$11.6 million during 2021 as compared to net income of$0.9 million for 2020. AtDecember 31, 2021 , our total estimated net proved reserves of natural gas were 110,969 MMcf, an increase of 22,311 MMcf fromDecember 31, 2020 . Our standardized measure of discounted future net cash flows as ofDecember 31, 2021 and 2020 was$77.7 million and$16.0 million , respectively. This measure of discounted future net cash flows does not include any estimate for future cash flows generated by Epsilon's gathering system assets.
Results of Operations
The following review of operations for the periods presented below should be read in conjunction with our consolidated financial statements and the notes thereto. Revenues
During the year endedDecember 31, 2021 , revenues increased$18.0 million , or 73.6%, to$42.4 million from$24.4 million during the same period in 2020 due primarily to increased prices and higher production volumes inOklahoma with the new wells. 34 Revenue and volume statistics for the years endedDecember 31, 2021 and 2020 were as follows: Year ended December 31, 2021 2020 Revenues Pennsylvania Natural gas revenue$ 29,909,651 $ 14,819,487 Volume (MMcf) 9,830 10,986 Avg. Price ($/Mcf)$ 3.04 $ 1.35 PA Exit Rate (MMcfpd) 29.3 32.8 Gathering system revenue$ 7,865,825 $ 8,879,728 Total PA Revenues$ 37,775,476 $ 23,699,215 Oklahoma Natural gas revenue$ 1,798,534 $ 387,740 Volume (MMcf) 403 218 Avg. Price ($/Mcf)$ 4.46 $ 1.78 Natural liquids revenue$ 1,053,486 $ 88,185 Volume (MBO) 29.3 8.4 Avg. Price ($/Bbl)$ 35.98 $ 10.47 Oil and condensate revenue$ 1,776,496 $ 250,140 Volume (MBO) 25.1 6.5 Avg. Price ($/Bbl)$ 70.70 $ 38.44 Total OK Revenues$ 4,628,516 $ 726,065 Total Revenues$ 42,403,992 $ 24,425,280
We earn gathering system revenue as a 35% owner of the Auburn Gas Gathering system. This revenue consists of fees paid by Anchor Shippers and third-party customers of the system to transport gas from the wellhead to the compression facility, and then to the delivery meter atTennessee Gas Pipeline . The relative mix of Anchor Shipper gas and third-party gas is critical to the revenue and earnings of the Auburn GGS because the third-party gathering rate is only 25% of the Anchor Shipper rate. Third-party shippers must pay the gathering rate of the originating gathering system plus 25% of the Auburn GGS gathering rate. The purpose of the reduced rate is to attract additional volumes that require delivery toTennessee Gas Pipeline when there is spare capacity at theAuburn compression facility. Throughput at the Auburn CF has declined from 100.1 Bcf in 2018 to 63.2 Bcf in 2021, a decrease of 37%. However, Anchor Shipper gas as a percentage of total throughput has increased from 57% in 2018 to 77% in 2021. As a result of this shift toward a higher percentage of Anchor Shipper gas, revenues and earnings for the gathering system have only declined 21% and 15%, respectively, from 2018 to 2021. For the year endedDecember 31, 2021 , approximately 80% of the Auburn GGS revenues earned are gathering fees, while 20% are compression fees. Third party customers represent approximately 5% of gathering revenues and 4% of compression revenues. For the year endedDecember 31, 2020 , approximately 85% of theAuburn GGS revenues earned were gathering fees, while 15% were compression fees. Third party customers represent approximately 4% of gathering revenues and 2% of compression revenues. Revenues derived from transporting and compressing Epsilon's production which have been eliminated from gathering system revenues amounted to$1.6 million and$1.8 million respectively for the years endedDecember 31, 2021 and 2020. Upstream natural gas revenue for the year endedDecember 31, 2021 increased by$16.5 million , or 109%, over 2020. This was primarily a result of higher natural gas prices partially offset by lower volumes being produced due to natural decline of the wells.
Upstream oil and other liquids revenue for the year ended
The Company's share of gathering system revenue decreased$1.0 million , or 11%, during the year endedDecember 31, 2021 over 2020. The Auburn GGS is subject to a cost of service model, whereby the Anchor Shippers 35 dedicate acreage and reserves to the Auburn GGS. In exchange for this dedication, the owners of theAuburn system agree to a fixed rate of return on capital invested which cannot be exceeded. Therefore, rather than being subject to a fixed gathering rate, the Shippers are subject to a fluctuating gathering rate which is re determined annually in order to produce the contractual return on capital to the Auburn GGS owners. The term of the model is fixed from 2012 to 2026. Each year, actual throughput, revenue, operating expenses and capital are captured in the model, and the remaining years are forecasted. The model then iterates for a gathering rate that yields the contractual rate of return. All else being equal, to the extent that throughput is higher or capital is lower than the preceding year's forecast, the gathering rate will decline.
Operating Costs
The following table presents total cost and cost per unit of production (Mcfe), including ad valorem, severance, and production taxes for the years endedDecember 31, 2021 and 2020: Year ended December 31, 2021 2020 Lease operating costs$ 7,897,738 $ 8,052,471 Gathering system operating costs 726,646 429,749$ 8,624,384 $ 8,482,220 Upstream operating costs-Total $/Mcfe 0.75 0.71 Gathering system operating costs $ / Mcf 0.10 0.04
Upstream operating costs consist of lease operating expenses necessary to extract natural gas and oil, including gathering and treating the natural gas and oil to ready it for sale.
For the year endedDecember 31, 2021 , upstream operating costs decreased by$0.2 million , or 2.1% from the same period in 2020. The decrease in total cost was primarily due to the decrease in volumes produced primarily inPennsylvania . The $/Mcfe increased primarily due to increased cost of discretionary maintenance during the year. Gathering system operating costs consist primarily of rental payments for the natural gas fueled compression units. Other significant gathering system operating costs include chemicals (to prevent corrosion and to reduce water vapor in the gas stream), saltwater disposal, measurement equipment / calibration and general project management. The gathering system operating total per unit operating costs reported include the effects of elimination entries to remove the gas gathering fees billed by the gas gathering system operator to Epsilon's upstream operations, and the volume associated with those fees. The elimination entries amounted to$1.6 million and$1.8 million for the years endedDecember 31, 2021 and 2020, respectively (see Note 12, "Operating Segments," of the Notes to Consolidated Financial Statements). Gathering system costs (net of intercompany elimination) for the year endedDecember 31, 2021 increased$0.3 million , or 69% from the same period in 2020. Although the Company's gross share of total gathering system costs increased only$0.06 million , or 3%, for the year endedDecember 31, 2021 over 2020, the elimination entry decreased by$0.2 , or 11% for the same period. This was due to a decrease in throughput in the gathering system resulting in a higher cost per MCF.
Depletion, Depreciation, Amortization and Accretion (DD&A)
Year ended
2021 2020
Depletion, depreciation, amortization and accretion
Natural gas and oil and gathering system assets are depleted and depreciated using the units of production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. At this time, the Company has only minimal leasehold acquisition costs. For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves. A reserve report is prepared as ofDecember 31 , each year. 36 Depreciation expense includes amounts pertaining to our office furniture and fixtures, leasehold improvements, computer hardware. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 7 years. Also included in depreciation expense is an amount pertaining to buildings owned by the Company. Depreciation for the buildings is calculated using the straight-line method over an estimated useful life of 30 years.
Accretion expense is related to the asset retirement costs.
During the year endedDecember 31, 2021 , DD&A expense decreased by$2.9 million , or 31%, compared to the same period in 2020. This was primarily due to the increase in reserves reported and the decrease in production volumes. The lower volumes spread over the increased reserves resulted in lower DD&A. Impairment Year ended December 31, 2021 2020 Impairment$ 153,058 $ 1,760,000 Epsilon performs a quantitative impairment test quarterly or whenever events or changes in circumstances indicate that an asset group's carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. When indicators of impairment are present, GAAP requires that the Company first compare expected future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required. Additionally, GAAP requires that if an exploratory well is determined not to have found proved reserves, the costs incurred, net of any salvage value, should be charged to expense. During the three months endedMarch 31, 2020 , the Company recognized certain indicators of impairments specific to ourOklahoma assets and determined that carrying value of those assets was not recoverable. As a result of this assessment, a$1.76 million impairment was assessed on the Company'sOklahoma assets atMarch 31, 2020 . No additional impairment was required as ofDecember 31, 2020 .
Gain (Loss) on Sale of Properties
Year ended December 31,
2021 2020
Gain on sale of properties $ 484,902 $ -
For the year ended December 31, 2021 , the Company recorded a gain on the sale of
the shallow rights leases and wells in Oklahoma . We had no sales for the year
ended December 31, 2020 .
General and Administrative ("G&A")
Year ended December 31,
2021 2020
General and administrative $ 6,831,815 $ 5,589,963
G&A expenses consist of general corporate expenses such as compensation, legal,
accounting and professional fees, consulting services, travel and other related
corporate costs such as stock options granted and restricted shares of stock
granted and the related non-cash compensation.
37
The G&A expenses increased by $1.2 million , or 22%, during the year ended
December 31, 2021 from the same period in 2020. This was mainly due to increased
legal fees related to the complaint filed against Chesapeake, the addition of a
salary and benefits for the CEO, and increased stock-based compensation
associated with the 2020 stock grants.
Interest Expense
Year ended December 31,
2021 2020
Interest expense $ 101,382 $ 114,515 Interest expense relates to the interest and commitment fees paid on the revolving line of credit.
Interest expense decreased by
Net gain (loss) on commodity contracts
Year ended December 31,
2021 2020
(Loss) gain on derivative contracts
During the years endedDecember 31, 2021 and 2020, Epsilon entered into NYMEX Henry Hub Natural Gas Futures swap, Dominion basis swap, and two-way costless collar derivative contracts for the purpose of hedging its physical natural gas sales revenue. The amounts recorded represent the fair value changes on our derivative instruments during the period. For the year endedDecember 31, 2021 , the Company paid net cash settlements of$4,243,085 . For the year endedDecember 31, 2020 , the Company received$4,503,457 on the settlement of contracts. InFebruary 2021 , the Company addedHenry Hub collars totaling 3.96 Bcf and basis swaps totaling 0.31 Bcf. InAugust 2021 , the Company addedHenry Hub collars totaling 0.46 Bcf and basis swaps totaling 1.10 Bcf. NYMEX HH prices generally increased throughout 2021 resulting in large realized losses for the year endedDecember 31, 2021 . During 2020, the Company added 0.6 Bcf ofHenry Hub swaps and 2.14 Bcf of basis swaps to its existing 2020 hedge portfolio. BothHenry Hub prices and basis prices generally declined throughout 2020 resulting in large realized gains for the year endedDecember 31, 2020 . The Company did not add any 2021 hedges during 2020. Other Income (Expense) Year endedDecember 31, 2021 2020
Interest income and other income
For the years ended
38
Net Income Compared to Adjusted EBITDA
Year ended December 31,
2021 2020
Net income $ 11,627,517 $ 875,171
Add Back:
Net interest expense 62,517 70,975
Income tax expense 4,440,508 575,420Depreciation, depletion, amortization, and accretion 6,627,016
9,557,891
Impairment expense 153,058
1,760,000
Stock based compensation expense 956,084
849,631
Loss on derivative contracts net of cash received or paid on settlement 239,824
1,999,802
Foreign currency translation loss 1,454
2,065
Adjusted EBITDA $ 24,107,978 $ 15,690,955
Epsilon defines Adjusted EBITDA as earnings before (1) net interest expense, (2)
taxes, (3) depreciation, depletion, amortization and accretion expense, (4)
impairments of natural gas and oil properties, (5) non-cash stock compensation
expense, (6) gain or loss on derivative contracts net of cash received or paid
on settlement, and (7) other income. Adjusted EBITDA is not a measure of
financial performance as determined under U.S. GAAP and should not be considered
in isolation from or as a substitute for net income or cash flow measures
prepared in accordance with U.S. GAAP 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 natural gas and oil
companies providing corresponding non-U.S. GAAP financial measures or that have
different financing and capital structures or tax rates. These non-U.S. GAAP
financial measures should be considered in addition to, but not as a substitute
for, measures for financial performance prepared in accordance with U.S. GAAP.
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 U.S. GAAP and should be reviewed carefully.
Capital Resources and Liquidity
Cash Flow
The primary source of cash during the year endedDecember 31, 2021 was funds generated from operations. For the year endedDecember 31, 2020 , the primary source of funds was from operations in addition to cash received on the settlement of derivative contracts. For the years endedDecember 31, 2021 and 2020, cash was primarily used for operations, as well as the development of natural gas and oil properties, the buyback of common shares through our share repurchase program, and the pre-payment of income taxes. AtDecember 31, 2021 , we had a working capital surplus of$24.1 million , an increase of$10.8 million from the$13.3 million surplus atDecember 31, 2020 . The surplus increased fromDecember 31, 2020 primarily due to the increase in realized prices during 2021. The Company anticipates its current cash balance, cash flows from operations, and available sources of liquidity to be sufficient to meet its cash requirements. 39
Year ended
During the year ended
We used$4.4 million for investing activities during the year endedDecember 31, 2021 , compared to$6.5 million in 2020, a$2.1 million , or 32%, decrease. This was spent primarily on development costs targeting increasing production inPennsylvania andOklahoma , partially offset by the proceeds from the sale of the shallow right leases and wells inOklahoma .
During the year ended
During the year ended
Credit Agreement In addition, the Company has a senior secured credit facility which includes a total commitment of up to$100 million . The current effective borrowing base is$14 million , which is subject to semi-annual redetermination. There are currently no borrowings under the facility. If Epsilon decided to access the facility, depending on the level of borrowing, the Company might need to increase its hedging activity. Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, and for letters of credit and other general corporate purposes. Upon each advance, interest is charged at the highest of a) rate of LIBOR plus an applicable margin (2.75%-3.75% based on the percent of the line of credit utilized), b) the Prime Rate, or c) the sum of the Federal Funds Rate plus 0.5%. EffectiveApril 6, 2021 , the agreement was amended to extend the maturity date toMarch 1, 2024 . In addition, the agreement was amended to include a Benchmark Replacement definition and transition plan to be used at such time when the LIBOR rate is discontinued.
On
OnNovember 23, 2021 , the borrowing base of$14 million was reaffirmed untilMay 1, 2022 , the next periodic redetermination of the borrowing base . The bank has a first priority security interest in the tangible and intangible assets ofEpsilon Energy USA, Inc. to secure any outstanding amounts under the agreement. Under the terms of the agreement, the Company must maintain the following covenants:
? Interest coverage ratio greater than 3 based on income adjusted for interest,
taxes and non-cash amounts.
? Current ratio, adjusted for line of credit amounts used and available and
non-cash amounts, greater than 1.
? Leverage ratio less than 3.5 based on income adjusted for interest, taxes and
non-cash amounts.
We were in compliance with the financial covenants of the agreement as of
Balance at Balance at
December 31, December 31, Borrowing Base Interest
2021 2020 December 31, 2021 RateRevolving line of credit $ - $ - $
14,000,000 3 mo. LIBOR + 3.25%
40
Repurchase Transactions
Commencing on January 1, 2021 , Epsilon has conducted a normal course issuer bid
("NCIB") to repurchase our issued and outstanding common shares, when doing so
has been accretive to management's estimates of intrinsic value per share. The
NCIB ended on December 31, 2021 . Since the commencement of the NCIB, Epsilon has
strengthened its financial position. With sufficient cash flow from operations,
it used discretionary cash to fund these repurchases. During the year ended
December 31, 2021 , Epsilon has repurchased 534,015 common shares of the
authorized 1,193,000 purchase amount and spent $2,423,007 under the NCIB.
Commencing on May 20, 2019 , Epsilon conducted a normal course issuer bid
("NCIB") to repurchase up to 1,367,762 issued and outstanding common shares.
The NCIB ended on May 19, 2020 . Additionally, on May 14, 2020 , the Company's
Board of Directors announced its intention to commence a substantial issuer
bid/issuer tender offer to purchase for cash up to an aggregate of approximately
$6.2 million of its common shares. The tender offer expired on June 30, 2020 .
During the year ended December 31, 2020 , the Company repurchased 2,994,348
common shares and spent $9,062,089 , excluding fees and expenses The Company
canceled all common shares taken up and paid for under the NCIB and tender
offer. The Company funded the repurchases with cash on hand.
Derivative Transactions
The Company has entered into hedging arrangements to reduce the impact of natural gas price volatility on operations. By removing the price volatility from a significant portion of natural gas production, the potential effects of changing prices on operating cash flows have been mitigated, but not eliminated. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we might otherwise receive from increases in commodity prices.
At
Volume Ceiling Floor Basis Fair Value of Asset
Derivative Type (MMbtu) Differential Price Differential December 31, 2021
2022
Two-way costless collar 590,000 $ 3.34 $ 2.80 $ - (239,824)
590,000 $ (239,824)
Contractual Obligations
We enter into commitments for capital expenditures in advance of the
expenditures being made. At a given point in time, it is estimated that we have
committed to capital expenditures equal to approximately one quarter of our
capital budget by means of giving the necessary authorizations to the asset
operator to incur the expenditures in a future period. Current commitments
amounted to approximately
Based on current natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate to meet liquidity needs for the next 12 months and beyond, including satisfying our financial obligations and funding our operating and development activities.
Off Balance Sheet Arrangements
As of
41
Summary of Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements and accompany notes, which have been prepared in accordance with accounting principles generally accepted inthe United States , or GAAP, andSEC rules which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Described below are the most significant accounting policies we apply in preparing our consolidated financial statements. We also describe the most significant estimates and assumptions we make in applying these policies.
Successful Efforts Accounting
We use the successful efforts method of accounting for natural gas and oil operations. Under this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. We do not currently do any exploratory drilling so this does not currently
come into use. Gathering System
We hold an undivided interest in a gas gathering system asset that supports ourPennsylvania operations. We account for the costs and revenue from this system using the proportionate consolidation method. Additionally, we are required to make an entry each reporting period to eliminate the Company's share of gathering system revenue related to the volume of gas produced by the Company and billed to the Company by the operator of the gathering system.
Proved Natural gas and oil Reserves
Our engineers estimate proved natural gas and oil reserves in accordance withSEC regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved natural gas and oil reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. We cannot predict the types of reserve revisions that will be required in future periods. For related discussion, see the sections titled "Risk Factors" and "Supplemental Information to Consolidated Financial Statements." 42
Unproved Natural gas and oil Properties
Unproved properties generally consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of natural gas and oil properties in the consolidated statements of operations and comprehensive income (loss). Unproved natural gas and oil property costs are transferred to proved natural gas and oil properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved natural gas and oil properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.
Depreciation, Depletion and Amortization of Natural gas and oil Properties and Gathering Systems
The quantities of estimated proved natural gas and oil reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively.
Oil and natural gas and gathering system assets are depleted and depreciated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved and unproved properties, the reserve base used to calculate depreciation and depletion is total proved reserves. For natural gas and oil development and gathering system costs, the reserve base used to calculate depletion and depreciation is proved developed reserves.
Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.
Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.
Impairments
The carrying value of unproved and proved oil and natural gas properties and gathering system assets are reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. Such indicators include changes in our business plans, changes in commodity prices leading to unprofitable performance, and, for natural gas and oil properties, significant downward revisions of estimated proved reserve quantities or significant increases in the estimated development costs. We compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the carrying value of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the carrying value of the asset, the carrying value is reduced to fair value. Fair value is generally calculated using the Income Approach based on estimated discounted net cash flows. Estimates of future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. We evaluate impairment of proved and unproved natural gas and oil properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. The basis for future depletion, depreciation, amortization, and accretion will take into account the reduction in the value of the asset as a result of any accumulated impairment losses.
When circumstances indicate that the gathering system properties may be impaired, Epsilon compares expected undiscounted future cash flows related to the gathering system to the unamortized capitalized cost of the asset. If the
43
expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach, which considers estimated discounted future cash flows.
Derivative Financial Instruments
Derivative financial instruments are used to hedge exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap and collar contracts. The use of these instruments is subject to policies and procedures as approved by the Board. Derivative financial instruments are not traded for speculative purposes. No derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the consolidated statements of operations and comprehensive income (loss). The estimated fair value of derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values reported in Epsilon's financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.
Asset Retirement Obligations ("ARO")
We recognize asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. For our upstream properties, these obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. For our gathering system, these obligations consist of estimated future costs associated with the removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the natural gas and oil or gathering system asset. The initial recognition of an ARO fair value requires that management make numerous assumptions regarding such factors as the amounts and timing of settlements; the credit-adjusted risk-free discount rate; and the inflation rate. In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the natural gas and oil property or gathering system asset.
Income Taxes
Tax regulations and legislation in theU.S. andCanada are subject to change and differing interpretations requiring judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires judgment. Income tax filings are subject to audits and re-assessments. Changes in facts, circumstances, and interpretations of the standards may result in a material increase or decrease in our provision for income taxes.
Recently Issued Accounting Standards
See Note 3 Summary of Significant Accounting Policies in Notes to the Consolidated Financial Statements.
44
© Edgar Online, source
