EPSILON ENERGY LTD. MANAGEMENT REPORT AND ANALYSIS OF FINANCIAL POSITION AND OPERATING RESULTS. (Form 10-K)

The following discussion is intended to assist in the understanding of trends
and significant changes in or results of operations and the financial condition
of Epsilon Energy Ltd. and its subsidiaries for the periods presented. This
section should be read in conjunction with the audited consolidated financial
statements as of December 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 is Pennsylvania. 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 our Pennsylvania acreage (4,597 net) is
dedicated to the Auburn Gas Gathering System, or the Auburn GGS, located in
Susquehanna 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 of
Williams 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 in Pennsylvania ($1.8 million to
the Auburn GGS to gather and treat our 11.0 Bcf in 2020).

At December 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 in Pennsylvania, and natural gas, oil and other liquid
production from our operated and non-operated wells in Oklahoma.

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 in the 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 core Marcellus Shale is one of the most attractive dry gas resources in the
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 to Henry 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 to Mexico have provided attractive markets improving the prices for
natural gas.

The operating environment remains challenging in Northeast 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.

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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 to Mexico 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 of Oklahoma, we continue to appraise recent and
historical results of the Meramec formation from both our wells and analog wells
within the focus area.  At December 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. At December 31, 2021, our total estimated net proved
reserves of natural gas were 110,969 MMcf, an increase of 22,311 MMcf from
December 31, 2020. Our standardized measure of discounted future net cash flows
as of December 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.

Operating results

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 ended December 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 in Oklahoma with the
new wells.

Revenue and volume statistics for the years ended December 31, 2021 and 2020
were as follows:

                                          Year ended
                                        December 31,
                                     2021            2020
Revenues
Natural gas revenue              $ 31,708,185    $ 15,207,227
Volume (MMcf)                          10,233          11,204
Avg. Price ($/Mcf)               $       3.10    $       1.36
PA Exit Rate (MMcfpd)                    29.3            32.8
Oil and other liquids revenue    $  2,829,982    $    338,325
Volume (MBO)                             54.4            14.9
Avg. Price ($/Bbl)               $      52.02    $      22.66
Gathering system revenue         $  7,865,825    $  8,879,728
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 at Tennessee Gas Pipeline. For the year
ended December 31, 2021, approximately 80% of the Auburn GGS revenues earned are
gathering fees, while 20% are compression fees. Third party

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customers represent approximately 5% of gathering revenues and 4% of compression
revenues. For the year ended December 31, 2020, approximately 85% of the Auburn
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 ended
December 31, 2021 and 2020.

Upstream natural gas revenue for the year ended December 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 petroleum products and other liquids for the year ended December 31, 2021
increased by $2.5 millioni.e. 736% compared to 2020. This is due to the increase in production from new wells in addition to the increase in oil prices.

The Company's share of gathering system revenue decreased $1.0 million, or 11%,
during the year ended December 31, 2021 over 2020. The Auburn GGS is subject to
a cost of service model, whereby the Anchor Shippers dedicate acreage and
reserves to the Auburn GGS. In exchange for this dedication, the owners of the
Auburn 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 ended
December 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 expenses include lease operating expenses required to extract natural gas and oil, including gathering and processing the natural gas and oil to prepare it for sale.

For the year ended December 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 in Pennsylvania. 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
ended December 31, 2021 and 2020, respectively (see Note 12, "Operating
Segments," of the Notes to Consolidated Financial Statements).

Collection system costs (net of inter-company eliminations) for the year ended
December 31, 2021 increase $0.3 millionor 69% compared to the same period in 2020. Although the gross share of the company in the total costs of the collection system

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increased only $0.06 million, or 3%, for the year ended December 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 

the 31st of December,

                                                           2021            

2020

Depletion, depreciation, amortization and accretion $6,627,016 $9,557,891


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 of December 31, each year.

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 relates to asset retirement costs.

During the year ended December 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 ended March 31, 2020, the Company recognized certain
indicators of impairments specific to our Oklahoma 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's Oklahoma
assets at March 31, 2020. No additional impairment was required as of December
31, 2020.

Gain (loss) on sale of properties

                                Year ended December 31,
                                    2021             2020
Gain on sale of properties    $         484,902      $   -


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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.

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 interest and commitment fees paid on the revolving line of credit.

Interest expense decreased by $0.01 millioni.e. 11%, during the year ended
December 31, 2021 compared to the same period in 2020. The decrease is due to the reduction in the borrowing base on our line of credit during this period.

Net gain (loss) on commodity contracts

                                         Year ended December 31,
                                           2021            2020

(Loss) gain on derivative contracts ($4,482,909) $2,503,655


During the years ended December 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 ended December 31, 2021,
the Company paid net cash settlements of $4,243,085. For the year ended December
31, 2020, the Company received $4,503,457 on the settlement of contracts.

In February 2021, the Company added Henry Hub collars totaling 3.96 Bcf and
basis swaps totaling 0.31 Bcf. In August 2021, the Company added Henry 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 ended December 31, 2021.

During 2020, the Company added 0.6 Bcf of Henry Hub swaps and 2.14 Bcf of basis
swaps to its existing 2020 hedge portfolio. Both Henry Hub prices and basis
prices generally declined throughout 2020 resulting in large realized gains for
the year ended December 31, 2020. The Company did not add any 2021 hedges during
2020.

Other Income (Expense)

                                      Year ended December 31,
                                        2021             2020

Interest and other income $39,995 $39,155


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For the years ended December 31, 2021 and other income in 2020 consisted primarily of interest income and was constant over the periods.

Net profit 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           575,420

Amortization, 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 ended December 31, 2021 was funds
generated from operations. For the year ended December 31, 2020, the primary
source of funds was from operations in addition to cash received on the
settlement of derivative contracts. For the years ended December 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.

At December 31, 2021, we had a working capital surplus of $24.1 million, an
increase of $10.8 million from the $13.3 million surplus at December 31, 2020.
The surplus increased from December 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.

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Year ended December 31, 2021 compared to 2020

During the year ended December 31, 2021, $20.0 million was contributed by our operating activities, versus $14.8 million in 2020, a $5.2 million, or 35%, increase. The increase is primarily attributable to higher realized prices, which resulted in higher revenue offset by higher cash paid for the settlement of derivative contracts.

We used $4.4 million for investing activities during the year ended December 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 in
Pennsylvania and Oklahoma, partially offset by the proceeds from the sale of the
shallow right leases and wells in Oklahoma.

During the year ended December 31, 2021, $2.3 million of the cash used for financing activity was mainly related to the repurchase of common shares of Epsilon.

During the year ended December 31, 2020, $9.1 million of the cash used for financing activity was mainly related to the repurchase and cancellation of common shares of Epsilon.

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%.

Effective April 6, 2021, the agreement was amended to extend the maturity date
to March 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.

At June 28, 2021the borrowing base went from $18 million for $14 million.

On November 23, 2021, the borrowing base of $14 million was reaffirmed until May
1, 2022, the next periodic redetermination of the borrowing base . The bank has
a first priority security interest in the tangible and intangible assets of
Epsilon 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 interest-adjusted income,

taxes and non-monetary amounts.

? Current ratio, adjusted for used and available line of credit amounts and

non-monetary amounts, greater than 1.

? Leverage ratio below 3.5 based on earnings adjusted for interest, taxes and

non-cash amounts.

We complied with the financial covenants of the agreement
December 31, 2021 and expect to be in compliance for the next 12 months. We expect to remain compliant as we currently have no borrowings under the facility and have funded all operations for 2021 from operating cash flow and free cash and expect to continue to do so until ‘in 2022.

                                    Balance at         Balance at
                                   December 31,       December 31,        Borrowing Base            Interest
                                       2021               2020           December 31, 2021            Rate
Revolving line of credit          $             -    $             -    $  
     14,000,000    3 mo. LIBOR + 3.25%


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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 December 31, 2021Epsilon’s outstanding natural gas swap contracts included the following:

                                          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 make commitments for capital expenditures before expenditures are incurred. At any given time, it is estimated that we have committed to capital expenditures equal to approximately one quarter of our capital budget by giving the necessary authorizations to the operator of the asset to commit the expenditures in a future period . Current commitments amount to approximately $3.8 millionthat we plan to engage in 2022.

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

From December 31, 2021 and 2020, we had no off-balance sheet arrangements.

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Summary of Significant 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
in the United States, or GAAP, and SEC 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.

Accounting for successful efforts

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 our
Pennsylvania 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.

Proven reserves of natural gas and oil

Our engineers estimate proved natural gas and oil reserves in accordance with
SEC 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."

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Unproven properties of natural gas and oil

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 Petroleum Properties and Gathering Systems

Estimated proved reserves quantities of natural gas and oil form a significant component of our calculation of depreciation, depletion and amortization expense, and revisions to these estimates may change the rate of future expense. Holding all other factors constant, if reserves were revised up or down, profits 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, revisions to reserves (up or down) and additions, property acquisitions and/or or asset disposals and write-downs.

Depreciation 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 properties of the collection system may be impaired, Epsilon compares the undiscounted expected future cash flows related to the collection system to the unamortized capitalized cost of the asset. If the

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the undiscounted expected future cash flows are less than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the income approach, which takes into account 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 the U.S. and Canada 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 the Notes to the Consolidated Financial Statements.

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