CARBON ENERGY CORPORATION The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management's expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors may cause our actual performance and management's actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary or may cause management to deviate from its current plans and expectations is set forth under "Risk Factors." The following discussion should be read in conjunction with "Forward-Looking Statements," "Risk Factors" and our consolidated financial statements, including the notes thereto appearing elsewhere in this Annual Report on Form 10-K. OverviewCarbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located inthe United States . We currently develop and operate oil and gas properties in theAppalachian Basin inKentucky ,Ohio ,Tennessee ,Virginia andWest Virginia , in theIllinois Basin inIllinois andIndiana , and in theVentura Basin inCalifornia through our wholly-owned and majority-owned subsidiaries. We own 100% of the outstanding interests ofNytis USA , which in turn owns 98.11% ofNytis LLC .Nytis LLC holds interests in our operating subsidiaries. We own 53.92% of Carbon California which consolidates as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane.
For a description of our assets, please see Part I, "Business" of this report.
AtDecember 31, 2019 , our proved developed reserves comprised 18.8% oil, 79.8% natural gas and 1.4% NGL. Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our growth plan is centered on the following activities:
? acquire and develop oil and gas producing properties that provide
attractive risk adjusted rates of return, field development projects and
complement our existing asset base; and
? develop, optimize and maintain a portfolio of low risk, long-lived oil and
natural gas properties that provide stable cash flows and attractive risk
adjusted rates of return.
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Factors That Significantly Affect Our Financial Condition and Results of Operations
Our revenue, profitability and future growth rate depend on many factors which are beyond our control, including but not limited to, economic, political and regulatory developments and competition from other industry participants. Our financial results are sensitive to fluctuations in oil and natural gas prices. Oil and gas prices historically have been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. InMarch 2020 , in response to the failure of theOrganization of the Petroleum Exporting Countries and theRussian Federation to agree on production quotas, theKingdom of Saudi Arabia announced its intent to maximize near-term oil production, which, together with the decline in demand due to slowed economic conditions attributable to COVID-19, contributed to a decline in the price of crude oil from$61.14 per barrel onDecember 31, 2019 to$28.70 per Bbl onMarch 16, 2020 . The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last eight calendar quarters: 2019 2018 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Oil (Bbl)$ 54.90 $ 59.96 $ 56.43 $ 56.87 $
62.89
Low oil and natural gas prices may decrease our revenues, may reduce the amount
of oil, natural gas and natural gas liquids that we can produce economically and
potentially lower our oil and natural gas reserves. Our estimated proved
reserves may decrease if the economic life of the underlying producing wells is
shortened as a result of lower oil and natural gas prices. A substantial or
extended decline in oil or natural gas prices may result in future impairments
of our proved reserves and may materially and adversely affect our future
business, financial condition, cash flows, results of operations or liquidity.
Lower oil and natural gas prices may also reduce the amount of borrowing base
under our bank credit facility, which is determined at the discretion of our
lenders and may make it more difficult to comply with the covenants and other
restrictions under our bank credit facility.
We use the full cost method of accounting for our oil and gas properties and
perform a ceiling test quarterly. The ceiling calculation utilizes a rolling
12-month average commodity price. We did not recognize an impairment in 2019 or
2018.
Future write downs or impairments, if any, are difficult to predict and will
depend not only on commodity prices, but also other factors that include, but
are not limited to, incremental proved reserves that may be added each period,
revisions to previous reserve estimates, capital expenditures and operating
costs. There are numerous uncertainties inherent in the estimation of proved
reserves and accounting for oil and natural gas properties in subsequent
periods.
We use commodity derivative instruments, such as swaps and costless collars, to
manage and reduce price volatility and other market risks associated with our
production. These arrangements are structured to reduce our exposure to
commodity price decreases, but they can also limit the benefit we might
otherwise receive from commodity price increases. Please read "Business-Risk
Management" for additional discussion of our commodity derivative contracts.
Impairment charges do not affect cash flows from operating activities but do
adversely affect net income and stockholders' equity. An extended decline in oil
or natural gas prices may materially and adversely affect our future business,
financial condition, cash flows and liquidity.
Future property acquisitions or dispositions could have a material impact on our
financial condition and results of operations by increasing or decreasing our
reserves, production and revenues as well as expenses and future capital
expenditures. We currently anticipate that we would finance any future
acquisitions with available borrowings under our credit facility, sales of
properties or the issuance of additional equity or debt.
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Operational Highlights
During 2019 and 2018, we concentrated our efforts on the acquisition and
development of producing properties through the acquisitions consummated by
Carbon California and Carbon Appalachia. On December 31, 2018 , we completed the
purchase of Old Ironsides' interests in Carbon Appalachia, resulting in
ownership of 100% of Carbon Appalachia. Our field development activities have
consisted principally of oil-related drilling, remediation and return to
production and recompletion projects in California . Since closing these
acquisitions, we have focused on operating efficiencies and reduction of
operating expenses, optimization of natural gas gathering and compression
facilities, greater flexibility in transporting our production to markets with
more favorable pricing, and the identification of development project
opportunities to provide more efficient and lower-cost operations. During the
second half of 2019, we executed a two-well drilling program in California , and
as a result of such drilling program, one well was completed in the fourth
quarter of 2019 and the other was completed during the first quarter of 2020.
Subject to the recovery of oil pricing in the remainder of 2020, we plan to
execute a five-well drilling program in California in 2020.
As of December 31, 2019 , we owned working interests in approximately 7,200 gross
wells (6,600 net), royalty interests located primarily in California , Illinois ,
Indiana , Kentucky , Ohio , Tennessee , Virginia , and West Virginia and had
leasehold positions in approximately 313,900 net developed acres and
approximately 1,256,900 net undeveloped acres. Approximately 75.0% of the
undeveloped acreage is held by production and of the remaining undeveloped
acreage, approximately 88.0% have lease terms of greater than five years
remaining in the primary term or contractual extension periods.
Our oil and natural gas assets contain an inventory of field development projects which may provide growth opportunities when oil and natural gas commodity prices warrant capital investment to develop the properties.
How We Evaluate Our Operations
In evaluating our financial results, we focus on the mix of our revenues from oil, natural gas, and NGLs, the average realized price from sales of our production, our production margins, and our capital expenditures.
We also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with the technical capabilities of our management team can generate attractive rates of return as we develop our extensive resource base. Additionally, by focusing on concentrated acreage positions, we can utilize centralized production infrastructure, which enable us to reduce reliance on outside service companies, minimize costs, and increase our returns.
Principal Components of Our Cost Structure
? Lease operating expenses. Lease operating expenses are costs incurred to
bring oil and natural gas out of the ground, together with the costs
incurred to maintain our producing properties. Such costs include
maintenance, repairs and workover expenses related to our oil and natural
gas properties.
? Pipeline operating expenses. Pipeline operating expenses are costsincurred to accept, transport and deliver gas across our midstream assets.
? Transportation and gathering costs. Transportation and gathering costs are
incurred to bring oil and natural gas to market. Gathering refers to the
utilization of low-pressure pipelines to move the oil and natural gas from
the wellhead into a transportation pipeline, or in case of oil, into a
tank battery from which sales of oil are made.
? Production and property taxes. Production and property taxes consist of
severance, property and ad valorem taxes. Production and severance taxes
are paid on oil and natural gas produced based on a percentage of market
prices or at fixed rates established by federal, state or local taxing
authorities. Ad valorem tax rates, which can fluctuate by year, are
determined by individual counties where we have production and are
assessed on our sales one or two years in arrears depending on the
location of the production.
? Marketing gas purchases. Marketing gas purchases consist of third-party
purchases of gas associated with our midstream operations.
? Depreciation, amortization and impairment. We use the full cost method of
accounting for oil and gas properties. All costs incidental to the
acquisition, exploration and development of oil and gas properties,
including costs of undeveloped leasehold, dry holes and leasehold
equipment, are capitalized. We perform a quarterly ceiling test based on
average first-of-the-month prices during the twelve-month period prior to
the reporting date. The full cost ceiling test is a limitation on
capitalized costs prescribed by the SEC . The ceiling test is not a fair
value-based measurement; rather, it is a standardized mathematicalcalculation that compares the net capitalized costs of our full cost pool
to estimated discounted cash flows. Should the net capitalized costs
exceed the sum of the estimated discounted cash flows, a ceiling test
write-down would be recognized to the extent of the excess.
49
? Depletion. Depletion is calculated using capitalized costs in the full
cost pool, including estimated asset retirement costs and estimated future
expenditures to be incurred in developing proved reserves, net of
estimated salvage values and depleted based on a unit-of-production
method.
? General and administrative expense. General and administrative expense
includes payroll and benefits for our corporate staff, non-cash
stock-based compensation, costs of maintaining our offices, costs of
managing our production, marketing, development and acquisitionoperations, franchise taxes, audit, tax, legal and other professional fees
and legal compliance. Certain of these costs were recovered as management
reimbursements in place with Carbon California and, prior to the
completion of the OIE Membership Acquisition on December 31, 2018 , Carbon
Appalachia .
? Interest expense. We finance a portion of our working capital requirements
for project development activities and acquisitions with borrowings under
our bank credit facilities. As a result, we incur interest expense that is
affected by both fluctuations in interest rates and our financing
decisions.
? Income tax expense. We are subject to state and federal income taxes but
typically have not been in a tax paying position for regular federal
income taxes, primarily due to the current deductibility of intangible
drilling costs ("IDC") and until 2023 tangible drilling costs and net
operating loss ("NOL") carryforwards. We pay alternative minimum tax,
state income or franchise taxes where IDC or NOL deductions do not exceedtaxable income or where state income or franchise taxes are determined on
another basis. See Note 12 - Income Taxes in the consolidated financial
statements in Item 8 for more information.
Factors Affecting Our Business and Outlook
The price we receive for our oil, natural gas and NGL production heavily influences our revenue, profitability, access to capital and future rate of growth. Our revenues, cash flow from operations, and future growth depend substantially on factors beyond our control, such as economic, political, and regulatory developments and competition from other sources of energy. Oil, natural gas and NGLs are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Sustained periods of low prices for oil, natural gas, or NGLs could materially and adversely affect our financial condition, our results of operations, the quantities of oil and natural gas that we can economically produce, and our ability to access capital. See - "Risk Factors - Oil, NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow."
We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. We do not apply hedge accounting, and therefore designate our current portfolio of commodity derivative contracts as hedges for accounting purposes and all changes in commodity derivative fair values are immediately recorded to earnings.
Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by acquiring more reserves than we produce, conducting field development projects or drilling to find additional reserves. Our future growth will depend on our ability to continue to acquire reserves in a cost-effective manner and enhance production levels from our existing reserves. Our ability to continue to acquire reserves and to add reserves through drilling is dependent on our capital resources and commodity prices and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.
As with our historical acquisitions, any future acquisitions could have a substantial impact on our financial condition and results of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.
Factors Affecting Comparability of Results of Operations
Acquisitions affect the comparability of our financial statements from period to period. InDecember 2018 , we completed the OIE Membership Acquisition and as a result, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries. As a result, we consolidate Carbon Appalachia for financial reporting purposes. As discussed in Note 3 - Acquisitions in the consolidated financial statements in Item 8, we completed several acquisitions during 2018 in addition to the OIE Membership Acquisition; therefore, the financial data for 2018 is not comparable in all respects to the financial data for 2019 and is not necessarily indicative of our future results. 50 Results of Operations
The following table sets forth for the periods presented our selected historical statements of operations and production data.
Year Ended
December 31 , Percent(in thousands except production and per unit data) 2019 2018(1)
Change
Revenue:
Natural gas sales $ 56,468 $ 16,018 253 %
Natural gas liquids sales 578 1,143 (49 )%
Oil sales 36,795 30,891 19 %
Transportation and handling 1,928 - *
Marketing gas sales 16,920 - *
Commodity derivative gain 3,044 4,894 *
Other income 892 105 *
Total revenues 116,625 53,051 120 %
Expenses:
Lease operating expenses 29,714 15,960 86 %
Pipeline operating expenses 11,153 - *
Transportation and gathering costs 6,086 4,453 37 %
Production and property taxes 5,507 1,813 204 %
Marketing gas purchases 18,684 - *
General and administrative 16,342 13,779 (19 )%
General and administrative-deferred fees
write-down - 1,999 *
General and administrative-related party
reimbursement - (4,547 ) *
Depreciation, depletion and amortization 15,757 8,108 94 %
Accretion of asset retirement obligations 1,625 868 87 %
Total expenses 104,868 42,433 147 %
Operating income $ 11,757 $ 10,618 11 %
Other income and (expense):
Interest expense $ (12,848 ) $ (5,920 ) 117 %
Warrant derivative gain - 225 *
Gain on derecognized equity investment in
affiliate-Carbon California - 5,390 *
Investment in affiliates 90 2,469 *
Other income - (3 ) *
Total other (expense) income $ (12,758 ) $ 2,161 *
Production data:
Natural gas (MMcf) 21,436 5,320 303 %
Oil (MBbl) 589 451 31 %
Natural gas liquids (MBbl) 36 33 8 %
Combined (MMcfe) 25,182 8,223 206 %
Average prices before effects of hedges:
Natural gas (per Mcf) $ 2.63 $ 3.01 (13 )%
Oil and liquids (per Bbl) $ 62.50 $ 68.53 (9 )%
Natural gas liquids (per Bbl) $ 16.18 34.55 (53 )%
Combined (per Mcfe) $ 3.73 $ 5.84 (36 )%
Average prices after effects of hedges**:
Natural gas (per Mcf) $ 2.80 $ 2.96 (5 )%
Oil and liquids (per Bbl) $ 62.38 $ 60.65 3 %
Natural gas liquids (per Bbl) $ 16.18 34.55 (53 )%
Combined (per Mcfe) $ 3.87 $ 5.38 (28 )%
Average costs (per Mcfe):
Lease operating expenses $ 1.18 $ 1.94 (39 )%
Transportation costs $ 0.24 $ 0.54 (56 )%
Production and property taxes $ 0.22 $ 0.22 0 %
Depreciation, depletion and amortization $ 0.63 $ 0.99 (36 )%
* Not meaningful or applicable
** Includes effect of settled commodity derivative gains and losses (1) Includes Carbon California activity for the period of consolidation from
affiliates does not include Carbon Appalachia activity during 2018 as
the OIE Membership Acquisition. As of
of Carbon Appalachia and holds a 53.92% proportionate share of
California . See Factors Affecting Comparability of Results of Operations. 51 2019 Compared to 2018 Oil and natural gas sales- Sales of natural gas, natural gas liquids and oil increased by approximately$46.0 million during 2019 as compared to 2018 primarily due to a 206% increase in natural gas, natural gas liquids and oil sales volumes, partially offset by a 36% decrease in combined product pricing. The increases in production were primarily due to the acquisitions ofCarbon Appalachia and Carbon California and the resultant consolidation of the related activity for the year endedDecember 31, 2019 . Commodity derivative gains (losses)- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the years endedDecember 31, 2019 and 2018, we had commodity derivative gains of approximately$3.0 million and$4.9 million , respectively. Lease operating expenses- Lease operating expenses increased approximately$14.0 million during 2019 as compared to 2018, primarily due to the OIE Membership Acquisition and the resultant increased production volumes. Lease operating expenses associated with oil production are generally higher on a per Mcfe
basis versus gas production.
Transportation and gathering costs- Transportation and gathering costs increased by 37% during 2019, as compared to 2018 primarily due to the OIE Membership Acquisition and a full year of Carbon California operations.
Production and property taxes- Production and property taxes increased 204% during 2019 as compared to 2018 due to increased oil and natural gas sales as a result of the consolidation of Carbon Appalachia and a full year ofCarbon California production, partially offset by decreased ad valorem estimated tax rates. Production taxes averaged approximately 4% and 2% of product sales for the years endedDecember 31, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 14% and 33% of our production mix for the years endedDecember 31, 2019 and 2018, respectively. Depreciation, depletion and amortization (DD&A)- DD&A increased approximately$8.0 million during 2019 as compared to 2018, primarily due to increased oil and natural gas production and the increase in oil and gas properties associated with the OIE Membership Acquisition. General and administrative expenses- General and administrative expenses decreased by 4% during 2019 as compared to 2018, primarily due to$2.0 million in financing costs written off during 2018 for an abandoned equity offering. Such financing costs were not incurred during 2019. As a result of the consolidation of Carbon Appalachia and Carbon California, management reimbursements which partially offset general and administrative expenses are now eliminated. These management reimbursements account for a decrease of approximately$4.6 million during 2019 as compared to 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from$1.23 per Mcfe for 2018 to$0.59 per Mcfe for 2019. Cash-based general and administrative expenses for the years endedDecember 31, 2019 and 2018 are summarized in the following table: Year Ended General and administrative expensesDecember 31 , (in thousands) 2019
2018
General and administrative expenses$ 16,342 $
15,778
Adjustments:
Stock-based compensation (1,448 ) (1,133 ) General and administrative - related party reimbursement - (4,547 ) Cash-based general and administrative expense$ 14,894 $ 10,098 52 Interest expense- Interest expense increased by 117% during 2019 as compared to 2018, primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition. Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases- Subsequent to the OIE Membership Acquisition onDecember 31, 2018 , we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our consolidated statements of operations during the year endedDecember 31, 2019 . These revenues and expenses were not presented in our consolidated statements of operations during the
year endedDecember 31, 2018 .
Liquidity and Capital Resources
Our primary sources of liquidity and capital resources are cash flows from operations, borrowings under our credit facility and Carbon California Senior Revolving Notes, and the sale of non-core assets. Borrowings under the credit facility and Carbon California Senior Revolving Notes may be used to fund field development projects, to fund future complementary acquisitions and for general working capital purposes. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain financial flexibility. As ofDecember 31, 2019 , our liquidity was approximately$17.9 million , consisting of cash on hand of approximately$900,000 and approximately$17.0 million of available borrowing capacity on our credit facility andCarbon California Senior Revolving Notes. OnFebruary 14, 2020 , we amended our credit facility, resulting in a borrowing base of$73.0 million with subsequent borrowing base reductions totaling$6.0 million scheduled throughMay 1, 2020 . OnDecember 31, 2018 , we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia; therefore, we receive 100% of the cash flows associated with Carbon Appalachia. Prior to the consolidation of Carbon California and Carbon Appalachia effectiveFebruary 1, 2018 andDecember 31, 2018 , respectively, we generated operating cash flow by providing management services to these unconsolidated subsidiaries. These management service reimbursements were included in general and administrative - related party reimbursement on our consolidated statement of operations. We also received reimbursements of operating expenses, our share of which were included in investments in affiliates on our consolidated statement of operations. As we now consolidate Carbon California and Carbon Appalachia, these management and operating reimbursements are eliminated in the consolidated statement of operations for the year endedDecember 31, 2019 . We continuously evaluate our portfolio of oil and gas assets and make acquisitions, investments and divestitures as part of our strategic plan. In the current environment, we are actively analyzing options such as selling assets, including potentially our Appalachian business, primarily in order to reduce indebtedness and, to a lesser extent, to fund higher value acquisition or development opportunities. Any decision to divest would be made based upon several criteria, including but not limited to the value we could obtain for such assets, the outlook for commodity prices, our expected return on invested capital and the impact on our overall leverage. Commodity Derivatives Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow. This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2022. Future hedging activities may result in reduced income or even financial losses to us. See "Risk Factors-The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income," for further details of the risks associated with our hedging activities. In the future, we may determine to increase or decrease our hedging positions. See Note 14 - Commodity Derivatives in the consolidated financial statements in Item 8 for more information, including further details about our outstanding derivatives.
Credit Facilities and Notes Payable
We have a$500.0 million bank credit facility withProsperity Bank (formerly known asLegacyTexas Bank ), as the administrative agent, and a syndicate of financial institutions, as lenders. The credit facility has a borrowing base of$75.0 million atDecember 31, 2019 and$72.0 million atMarch 16, 2020 , the outstanding balance of which was approximately$69.2 million atDecember 31, 2019 and$71.2 million atMarch 16, 2020 . Additionally, we have$15.0 million associated with a term loan under the same facility, which balance was approximately$5.8 million atDecember 31, 2019 and$3.3 million atMarch 16, 2020 . Finally, we have notes payable to Old Ironsides, the balance of which was approximately$25.7 million as ofDecember 31, 2019 andMarch 16, 2020 .
For further information about our outstanding debt, see Note 7 - Credit Facilities and Notes Payable in the consolidated financial statements in Item 8.
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Sources and Uses of Cash
The following table presents net cash provided by or used in operating, investing and financing activities:
Year Ended
December 31,
(in thousands) 2019 2018
Net cash provided by operating activities $ 18,856 $ 10,845
Net cash used in investing activities$ (6,570 ) $
(70,436 )
Net cash (used in) provided by financing activities
Operating Activities Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately$8.0 million for the year endedDecember 31, 2019 as compared to the same period in 2018. This increase was primarily due to increased revenues attributable to the OIE Membership Acquisition andSeneca Acquisition. Investing Activities Net cash used in investing activities is primarily comprised of the acquisition, exploration and development of oil and natural gas properties in addition to expenditures to fund our drilling program in Carbon California, net of dispositions of oil and natural gas properties. Net cash used in investing activities decreased approximately$63.9 million for the year endedDecember 31, 2019 as compared to the same period in 2018, primarily due to the OIE Membership Acquisition and Seneca Acquisition consummated in 2018. Financing Activities
Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facility and the Carbon California Senior Revolving Notes. During the year endedDecember 31, 2019 , the Company paid$2.0 million in principal associated with the Old Ironsides Notes, paid approximately$14.2 million in principal associated with our credit facility, and paid approximately$7.5 million in principal associated with the Carbon California Senior Revolving Notes. The payments were partially offset by borrowings under our credit facility and Senior Revolving Notes of approximately$7.0 million . During the year endedDecember 31, 2018 , the Company borrowed approximately$28.0 million to partially fund the Seneca Acquisition inMay 2018 , borrowed approximately$3.0 million to partially fund the Liberty Acquisition (as defined in Note 3 to the consolidated financial statements in Item 8) inJuly 2018 , and borrowed approximately$84.2 million , netted against approximately$64.2 million in repayments of the previous credit facility, to partially fund the OIE Membership Acquisition inDecember 2018 . Also in 2018, the Company received$5.0 million in proceeds from the issuance of preferred stock toYorktown and received an equity contribution of$5.0 million from Prudential related to
the
Seneca Acquisition.
Capital Expenditures
Capital expenditures in the table below represent cash used for capital
expenditures:
Year Ended
December 31,
(in thousands) 2019 2018
Acquisition of oil and gas properties:
Unevaluated properties $ - $ 3,464 Oil and natural gas producing properties - 63,517
Drilling and development 7,676 2,074 Pipeline and gathering - 460 Other 352 921 Total capital expenditures$ 8,028 $ 70,436 54
During the second half of 2019, we executed a two-well drilling program inCalifornia , and as a result of such drilling program, one well was completed in the fourth quarter of 2019 and the other was completed during the first quarter of 2020. Due to low natural gas prices, the Company has focused itsAppalachia operations on the optimization of our gathering, compression and storage facilities and marketing arrangements to provide greater flexibility in moving natural gas production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions and weather disruptions. Due to the recent developments surrounding the COVID-19 virus and relative pricing volatility, we are currently evaluating our 2020 capital program.
Off-balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of
Critical Accounting Policies, Estimates, Judgments, and Assumptions
We prepare our financial statements and the accompanying notes in conformity with GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompany 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 deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The following is a discussion of our most critical accounting policies that require management to make difficult, subjective or complex accounting estimates.
Full Cost Method of Accounting
The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements. We use the full cost method of accounting as defined by SEC Release No. 33-8995 and FASB ASC 932 because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves. Under the full cost method, separate cost centers are maintained for each geographic area in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded. Capitalized costs applicable to each full cost center are depleted using the units-of-production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Based on this accounting policy, ourDecember 31, 2019 and 2018 reserve estimates were used for our respective period depletion calculations. These reserve estimates were calculated in accordance withSEC rules. See "Business-Reserves" and Notes 2 and 17 to the consolidated financial statements for a more complete discussion of the rule and our estimated proved reserves as ofDecember 31, 2019 and 2018. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a quarterly ceiling test for each cost center. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement. Rather, it is a standardized mathematical calculation. The test determines a limit, or ceiling, on the book value of our oil and natural gas properties. That limit is basically the after-tax present value of the future net cash flows from proved oil and natural gas reserves. This ceiling is compared to the net book value of the oil and natural gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. Such impairments are permanent and cannot be recovered even if the sum of the components noted above exceeds capitalized costs in future periods. The two primary factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value of estimated future net revenues. In 2019 and 2018, we did not recognize a ceiling test impairment. Lower oil and natural gas prices may not only decrease our revenues but may also reduce the amount of oil and natural gas that we can produce economically and potentially lower our oil and natural gas reserves. Negative revisions to estimates of oil and natural gas reserves and decreases in prices can have a material impact on the present value of estimated future net revenues which may require us to recognize impairments of our oil and natural gas properties in future periods. 55 In areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion and amortization and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practical to individually assess properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool. Subject to industry conditions, evaluation of most of our unproved properties and inclusion of these costs in proved property costs subject to amortization are expected to be completed within five years.
Oil and Natural Gas Reserve Estimates
Our estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural gas properties are also subject to a "ceiling test" limitation based in part on the quantity of our proved reserves. Reference should be made to "Business-Reserves" and "Risk Factors-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves."
Accounting for Derivative Instruments
We recognize all derivative instruments as either assets or liabilities at fair value. We have elected not to use hedge accounting and as a result, all changes in the fair values of our derivative instruments are recognized in commodity derivative gain or loss in our consolidated statements of operations. The fair value of our commodity derivative assets and liabilities are measured utilizing a third-party valuation specialist. The valuations consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments; and (e) the counterparty's credit risk. We review these valuations and analyze changes in the fair value of the derivatives. Volatility in oil and natural gas prices could have a significant impact on the fair value of our derivative contracts. The values we report in our consolidated financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period and we expect the volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated atDecember 31, 2019 and will depend exclusively on the price of the commodities on the specified settlement dates provided by
the
derivative contracts.
56
Income Taxes
We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.
In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Positive evidence considered by management includes current book income in 2017, 2018 and 2019, and forecasted book income if commodity prices increase. Negative evidence considered by management includes book losses in certain years which were driven primarily from ceiling test write-downs, which are not fair value-based measurements and current commodity prices which will impact forecasted income or loss. As ofDecember 31, 2019 and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use our deferred tax assets and determined that it is more-likely-than-not that the deferred tax assets will not be realized in the near future. Based on this assessment, we recorded a net valuation allowance of approximately$13.1 million and$14.6 million on our deferred tax assets as ofDecember 31, 2019 and 2018, respectively.
Asset Retirement Obligations
We have obligations to remove tangible equipment and restore locations at the
end of oil and natural gas production operations. FASB ASC Topic 410, Asset
Retirement and Environmental Obligations, requires that the discounted fair
value of a liability for an asset retirement obligation ("ARO") 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 oil and natural gas asset.
Estimating the future restoration and removal costs, or ARO, is difficult and
requires management to make estimates and judgments, because most of the
obligations are many years in the future, and contracts and regulations often
have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental,
safety, and public relations considerations.
Inherent in the calculation of the present value of our ARO are numerous
assumptions and judgments, including the ultimate settlement amounts, inflation
factors, credit adjusted discount rates, timing of settlement, and changes in
the legal, regulatory, environmental, and political environments. To the extent
future revisions to these assumptions impact the present value of the existing
ARO liability, a corresponding adjustment is made to the oil and natural gas
property balance. Increases in the discounted ARO liability resulting from the
passage of time are reflected as accretion expense in the consolidated
statements of operations. See Note 6 - Asset Retirement Obligations in the
consolidated financial statements in Item 8 for more information.
Accounting for Business Combinations
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. We may use the cost, income, or market valuation approaches depending on the quality of the information available to support management's assumptions. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. Revenue Recognition
We derive our revenue from the sale of oil, natural gas and NGLs. Revenues are recognized when we meet our performance obligations to deliver the production volumes and control is transferred. Oil, natural gas and NGL revenues are recognized on the basis of our net working revenue interest. Payment is received 30 to 90 days after the date of production. At the end of each month, we make estimates of the amount of production delivered and the price we will receive. Variances between our estimated revenue and actual amounts received are recorded in the month payment is received.
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