ECLIPSE RESOURCES CORP - 10-K - Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with our consolidated financial
statements and related notes appearing elsewhere in this Annual Report. The
following discussion contains "forward-looking statements" that reflect our
future plans, estimates, beliefs and expected performance. We caution that
assumptions, expectations, projections, intentions, or beliefs about future
events may, and often do, vary from actual results and the differences can be
material. Some of the key factors which could cause actual results to vary from
our expectations include changes in natural gas, NGLs and oil prices, the timing
of planned capital expenditures, availability of acquisitions, uncertainties in
estimating proved reserves and forecasting production results, operational
factors affecting the commencement or maintenance of producing wells, the
condition of the capital markets generally, as well as our ability to access
them, and uncertainties regarding environmental regulations or litigation and
other legal or regulatory developments affecting our business, as well as those
factors discussed below and elsewhere in this Annual Report, all of which are
difficult to predict. In light of these risks, uncertainties and assumptions,
the forward-looking events discussed may not occur. See "Cautionary Statement
Regarding Forward-Looking Statements." Also, see the risk factors and other
cautionary statements described in "Item 1A. Risk Factors" of this Annual
Report. We do not undertake any obligation to publicly update any
forward-looking statements except as otherwise required by applicable law.
On June 24, 2014, prior to the closing of our initial public offering ("IPO"),
we completed our Corporate Reorganization, as described under "Note
1-Organization and Nature of Operations" located in the Notes to the
Consolidated Financial Statements included in Item 8 of Part II of this Annual
Report on Form 10-K. As such, information presented in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" for the period
from January 1, 2014 through June 23, 2014, as contained within the year ended
December 31, 2014, and for the years ended December 31, 2013 and 2012, pertain
to the historical financial statements and results of operations of Eclipse I,
our accounting predecessor.
Overview of Our Business
We are an independent exploration and production company engaged in the
acquisition and development of oil and natural gas properties in the Appalachian
Basin. As of December 31, 2015, we had assembled an acreage position
approximating 220,000 net acres in
Eastern Ohio
. Approximately 102,000 of our
net acres are located in what we believe to be the most prolific and economic
area of the Utica Shale fairway, which we refer to as the Utica Core Area, and
approximately 28,000 of these net acres are also prospective for the highly
liquids rich area of the Marcellus Shale in
Eastern Ohio
within what we refer to
as Our Marcellus Project Area.
We are the operator of approximately 85% of our net acreage within the
Utica
Core Area and Our Marcellus Project Area. We intend to focus on developing our
substantial inventory of horizontal drilling locations during commodity price
environments that will allow us to generate attractive returns and will continue
to opportunistically add to this acreage position where we can acquire acreage
at attractive prices.
As of December 31, 2015, we:
• were operating 1 horizontal rig in the Utica Core Area, which had
temporarily suspended drilling;
• had identified 2,450 gross (594 net) horizontal drilling locations across
our acreage, comprised of 2,067 gross (453 net) locations within the
Utica
Core Area and 383 gross (141 net) locations within Our Marcellus Project
Area;
• we, or our operating partners, had commenced drilling 208 gross (92.3 net)
wells within the Utica Core Area and Our Marcellus Project Area, of which
6 gross (4.2 net) were drilling, 28 gross (19.6 net) were awaiting
completion, 3 gross (0.8 net) were awaiting midstream and 171 gross (67.7
net) had been turned to sales.
• had average daily production for the year ended December 31, 2015 of
approximately 207.9 MMcfe comprised of approximately 65% natural gas, 19%
NGLs and 15% oil; and
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• our estimated proved reserves were 348.8 Bcfe, or 58.1 MMBoe, based on
reserve reports prepared by Netherland, Sewell & Associates, Inc., or
NSAI, our independent petroleum engineers, all of which were in
Ohio
and
approximately 80% of which were proved developed reserves. Our estimated
proved reserves were approximately 79% natural gas, 13% NGLs and 8% oil,
as of December 31, 2015.
Factors That Significantly Affect Our Financial Condition and Results of Operations
We derive substantially all of our revenues from the production and sale of
natural gas, NGLs and oil that are extracted from our natural gas during
processing. During the year ended December 31, 2015, our revenues were comprised
of approximately 55%, 13% and 32% from the production and sale of natural gas,
NGLs and oil, respectively. 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. Natural gas, NGLs and oil prices have historically 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 and geopolitical events such as wars or natural disasters.
Sustained periods of low prices for these commodities would materially and
adversely affect our financial condition, our results of operations, the
quantities of natural gas, NGLs and oil that we can economically produce and our
ability to access capital.
We use commodity derivative instruments 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. Our risk management activity is generally accomplished through
over-the-counter commodity derivative contracts with large financial
institutions. Please read "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" for additional discussion of our commodity derivative
contracts.
Like other 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 exploration and production company depletes
part of its asset base with each unit of reserves it produces. We attempt to
overcome this natural decline by drilling to find additional reserves and
acquiring more reserves than we produce. Our future growth will depend on our
ability to enhance production levels from our existing reserves and to continue
to add reserves in excess of production in a cost effective manner. Our ability
to make capital expenditures to increase production from our existing reserves
and to add reserves through drilling is dependent on our capital resources 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.
Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:
• success in drilling new wells;
• natural gas, NGLs and oil prices;
• the availability of attractive acquisition opportunities and our ability
to execute them;
• the amount of capital we invest in the leasing and development of our
properties;
• facility or equipment availability and unexpected downtime;
• delays imposed by or resulting from compliance with regulatory
requirements; and
• the rate at which production volumes on our wells naturally decline.
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Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods
presented may not be comparable, either from period to period or going forward,
for the following reasons:
Initial Public Offering. As a result of our IPO, we have incurred direct
incremental general and administrative ("G&A") expenses as a result of being a
publicly traded company. Information presented in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for the period from
January 1, 2014 through June 23, 2014, as contained within the year ended
December 31, 2014, and for the year ended December 31, 2013 pertain to the
historical financial statements and results of operations of Eclipse I, our
accounting predecessor. As a result, the historical financial data may not give
you an accurate indication of what our actual results would have been had our
Corporate Reorganization been completed at the beginning of the periods
presented or of what our future results of operations are likely to be. In
addition, we were not a tax paying entity prior to the completion of our
Corporate Reorganization on June 24, 2014 and therefore, no income tax expense
was recorded by us prior to such time.
Prior to our Corporate Reorganization, our capital expenditures were financed
with capital contributions from private equity funds managed by EnCap and
investment funds controlled by certain members of our management team, net
proceeds from the issuance of our 12% senior unsecured PIK notes due 2018 and
net cash provided by operating activities. In the future, we may incur
additional indebtedness or issue additional equity securities to fund our
acquisition and development activities. Please read "Credit Arrangements" for
additional discussion of our financing arrangements.
The Oxford Acquisition. We acquired Oxford on June 26, 2013. As such, the
results of Oxford's operations prior to such date are not included in the
historical financial statements of Eclipse I that are presented within this
Annual Report. Accordingly, our historical financial data may not present an
accurate indication of what our actual results would have been if the Oxford
Acquisition had been completed at the beginning of the periods presented or of
what our future results of operations are likely to be.
Financing Arrangements. On July 6, 2015, we issued $550 million in aggregate
principal amount of 8.875% senior notes due 2023 (the "Notes") at an issue price
of 97.903% of the principal amount of the Notes, plus accrued and unpaid
interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers.
In this private offering, the Notes were sold for cash to qualified
institutional buyers in
the United States
pursuant to Rule 144A of the
Securities Act and to persons outside
the United States
in compliance with
Regulation S under the Securities Act. Upon closing, we received proceeds of
approximately $525.5 million, after deducting original issue discount, the
initial purchasers' discounts and estimated offering expenses, of which we used
approximately $510.7 million to finance the redemption of all of our outstanding
12.0% Senior PIK notes due 2018. We intend to use the remaining net proceeds to
fund our capital expenditure plan and for general corporate purposes.
Source of Our Revenues
Our historical revenues are derived from the sale of natural gas, NGLs and oil,
and do not include the effects of derivatives. Revenues from product sales are a
function of the volumes produced, prevailing market prices, product quality, gas
Btu content and transportation costs. We generally sell production at a specific
delivery point, pay transportation costs to a third party and receive proceeds
from the purchaser with no transportation deduction. We record transportation
costs as transportation, gathering and compression expense. Brokered natural gas
and marketing revenues include revenue from brokered gas or revenue we receive
as a result of selling natural gas that is not related to our production. Our
revenues may vary significantly from period to period as a result of changes in
volumes of production sold or changes in commodity prices.
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Principal Components of Our Cost Structure
• Lease operating. These are day-to-day costs incurred to bring hydrocarbons
out of the ground along with the daily costs incurred to maintain our
producing properties. Such costs include compensation of our field
employees, maintenance, repairs and workovers expenses related to our
natural gas and oil properties. These costs are expected to remain a
function of supply and demand.
• Transportation, gathering and compression. These are costs incurred to
bring natural gas, NGLs, and oil to the market. Such costs include the
costs to operate and maintain our low- and high-pressure gathering and
compression systems as well as fees paid to third parties who operate
gathering systems that transport our gas. They also include costs to
process and extract NGLs from our produced gas and to transport our NGLs
and oil to market. We often enter into fixed price long -term contracts
that secure transportation and processing capacity which may include
minimum volume commitments, the cost for which is included in these
expenses to the extent that they are not excess capacity.
• Production and ad valorem taxes. Production taxes are paid on produced
natural gas and oil based on a percentage of market prices or at fixed
rates established by the applicable federal, state or local taxing
authorities. Ad valorem taxes are generally based on reserve values at the
end of each year.
• Brokered natural gas and marketing. These expenses are gas purchases for
brokered natural gas that we buy and sell that is not related to our
production and firm transportation capacity that is marketed to third
parties in excess of production volumes.
• Depreciation, depletion and amortization. This includes the expensing of
the capitalized costs incurred to acquire, explore and develop natural
gas, NGLs and oil. As a successful efforts company, we capitalize all
costs associated with our acquisition and development efforts and all
successful exploration efforts, and apportion these costs to each unit of
production through depreciation, depletion and amortization expense.
• Exploration. These are geological and geophysical costs, seismic costs,
delay rentals and the costs of unsuccessful exploratory dry holes. This
category also includes unproved property impairment and expenses
associated with lease expirations.
• General and administrative. These costs include overhead, including
payroll and benefits for our corporate staff, costs of maintaining our
headquarters, costs of managing our production and development operations,
franchise taxes, audit and other professional fees and legal compliance.
Included in this category are any overhead expense reimbursements we
receive from working interest owners of properties, for which we serve as
the operator. These reimbursements are received during both the drilling
and operational stages of a property's life.
• Impairment of oil and gas properties. Properties are evaluated for
impairment when circumstances indicate that the carrying value of an asset
could exceed its fair value. When the carrying value exceeds the sum of
the future undiscounted cash flows, an impairment loss is recognized for
the difference between the fair market value and carrying value of the
asset.
• Accretion expense. This expense includes the monthly accretion of the
future abandonment costs of tangible assets such as wells, service assets,
pipelines and other facilities.
• Gain (loss) on derivative instruments. We utilize commodity derivative
contracts to reduce our exposure to fluctuations in the price of gas. None
of our derivative contracts are designated as hedges for accounting
purposes. Consequently, our derivative contracts are marked-to-market each
quarter with changes in fair value recognized currently as a gain or loss
in our results of operations. The amount of future gain or loss recognized
on derivative instruments is dependent upon future gas prices, which will
affect the value of the contracts. Cash flow is only impacted to the
extent the actual settlements under the contracts result in making a
payment to or receiving a payment from the counterparty. In addition to
gains and losses recognized from changes in fair value of the derivative
instruments, gain (loss) on derivative instruments includes actual amounts
realized from settlement of derivative instruments upon expiration.
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• Interest expense. We have historically financed a portion of our cash
requirements with proceeds from fixed-rate senior unsecured notes and our
Revolving Credit Facility. As a result, we incur interest expense that is
affected by our financing decisions. We capitalize interest on
expenditures for significant exploration and development projects while
activities are in progress to bring the assets to their intended use. Upon
completion of construction of the asset, the associated capitalized
interest costs are included within our asset base and depleted
accordingly.
How We Evaluate Our Operations
In evaluating our current and future financial results, we focus on production
and revenue growth, lease operating expense, general and administrative expense
(both before and after non-cash stock compensation expense) and operating margin
per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a
non-GAAP measure, to evaluate our financial results. We define Adjusted EBITDAX
as net income (loss) before interest expense or interest income; income taxes;
write-down of abandoned leases; impairments; depreciation, depletion and
amortization ("DD&A"); amortization of deferred financing costs; gain (loss) on
derivative instruments, net cash receipts (payments on settled derivative
instruments, and premiums (paid) received on options that settled during the
period, non-cash compensation expense; gain or loss from sale of interest in gas
properties; exploration expenses; and other unusual or infrequent items.
Adjusted EBITDAX is not a measure of net income as determined by generally
accepted accounting principles in
United States
, or "
U.S.
GAAP."
In addition to the operating metrics above, as we grow our reserve base, we will
assess our capital spending by calculating our operated proved developed
reserves and our operated proved developed finding costs and development costs.
We believe that operated proved developed finding and development costs are one
of the key measurements of the performance of an oil and gas exploration and
production company. We will focus on our operated properties as we control the
location, spending and operations associated with drilling these properties. In
determining our proved developed finding and development costs, only cash costs
incurred in connection with exploration and development will be used in the
calculation, while the costs of acquisitions will be excluded because our board
approves each material acquisition. In evaluating our proved developed reserve
additions, any reserve revisions for changes in commodity prices between years
will be excluded from the assessment, but any performance related reserve
revisions are included.
We also continually evaluate our rates of return on invested capital in our
wells. We believe the quality of our assets combined with our technical and
managerial expertise can generate attractive rates of return as we develop our
acreage in the Utica Core Area and Our Marcellus Project Area. We review changes
in drilling and completion costs; lease operating costs; natural gas, NGLs and
oil prices; well productivity; and other factors in order to focus our drilling
on the highest rate of return areas within our acreage.
Overview of the Year Ended December 31, 2015 Results
Operationally, our performance during the year ended December 31, 2015 reflects
continued development of our acreage, while focusing on capital preservation in
the currently depressed commodity price environment. During the year ended
December 31, 2015, we achieved the following financial and operating results:
• increased our average daily net production for the year ended December 31,
2015 by 186% over the prior year, to 207.9 MMcfe per day;
• commenced drilling 14 gross (13.5 net) operated Utica Shale wells,
completed 16 gross (14.8 net) operated Utica Shale wells and
turned-to-sales 25 gross (23.5 net) wells during the year;
• participated in 17 gross (1.5 net) non-operated Utica Shale wells,
completed 35 gross (5.7 net) non-operated Utica Shale wells and
turned-to-sales 51 gross (10.3 net) wells during the year;
• net loss was $971.4 million for the year ended December 31, 2015 compared
to $183.2 million for the year ended December 31, 2014; and
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• Adjusted EBITDAX was $113.1 million for the year ended December 31, 2015
compared to $62.4 million for the year ended December 31, 2014. Adjusted
EBITDAX is a non-GAAP financial measure. See "Item 6. Selected Financial
Data-Non-GAAP Financial Measures" for more information.
Market Conditions
Prices for various quantities of natural gas, NGLs and oil that we produce
significantly impact our revenues and cash flows. Prices for commodities, such
as hydrocarbons, are inherently volatile. The following table lists average,
high and low NYMEX Henry Hub prices for natural gas and NYMEX WTI prices for oil
for the years ended December 31, 2015, 2014 and 2013.
2015 2014 2013
NYMEX Henry Hub High ($/MMBtu) $ 3.32 $ 6.15 $ 4.46
NYMEX Henry Hub Low ($/MMBtu) 1.63 2.89 3.11
Average NYMEX Henry Hub ($/MMBtu) 2.57 4.26 3.73
NYMEX WTI High ($/Bbl) $ 61.36 $ 107.26 $ 110.53
NYMEX WTI Low ($/Bbl) 34.55 53.27 86.68
Average NYMEX WTI ($/Bbl) 49.33 92.91 98.05
Historically, commodity prices have been extremely volatile, and we expect this
volatility to continue for the foreseeable future. A further or extended decline
in commodity prices could materially and adversely affect our future business,
financial condition, results of operations, liquidity or ability to finance
planned capital expenditures. We make price assumptions that are used for
planning purposes, and a significant portion of our cash outlays, including
rent, salaries and noncancelable capital commitments, are largely fixed in
nature. Accordingly, if commodity prices are below the expectations on which
these commitments were based, our financial results are likely to be adversely
and disproportionately affected because these cash outlays are not variable in
the short term and cannot be quickly reduced to respond to unanticipated
decreases in commodity prices.
The significant price declines experienced during the year ended December 31,
2015 have and could continue to adversely affect the amount of oil, NGLs and
natural gas that we can produce economically, which has resulted in our having
to make significant downward adjustments to our estimated proved undeveloped
reserves. A reduction in production could also result in a shortfall in expected
cash flows and require us to reduce capital spending or raise funds to cover any
such shortfall. Any of these factors could negatively affect our ability to
replace production and our future rate of growth or dilute existing
shareholders.
Commodity price revisions, based on 12-month average SEC prices for 2015, had a
significant impact on our 2015 reserve revisions. If the currently depressed
pricing environment for oil, NGLs and natural gas persists or worsens, it will
continue to have a significant impact on future reserve estimates. From
December 31, 2014 to December 31, 2015, the 12-month average SEC price for WTI
oil declined from $94.99 per Bbl to $50.28 per Bbl, while the 12-month average
SEC price for Henry Hub natural gas declined from $4.35 per MMBtu to $2.59 per
MMBtu. Service costs have also declined significantly during the same time
period, which mitigated a portion of the negative impact of declining commodity
prices on our future reserve estimates. In addition, we expect to continue to
increase our proved reserves through further extensions and discoveries as we
continue to develop our acreage position.
Based on the current market conditions, we have voluntarily begun reducing our
aggregate operated production to approximately 200 MMcfe per day, approximately
the same level as our 2015 average, until commodity prices begin to recover. In
addition, we have reduced the number of our operated horizontal drilling rigs
down to one, compared to three horizontal rigs as of December 31, 2014. During
the fourth quarter of 2015, we temporarily suspended all drilling operations and
have focused our initial 2016 capital plan on limiting cash
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outflows on drilling. As a result of the reduction in drilling activity, we
recorded a charge related to the early termination of drilling rig contracts and
standby costs of $9.7 million during the year ended December 31, 2015 and $3.3
million during the year ended December 31, 2014. This reduction in planned
capital expenditures will likely result in a slower rate of growth of our proved
reserves through extensions and discoveries than previously forecasted as
development of our acreage position is deferred to subsequent years. See
additional details related to our capital expenditures in "-Capital
Requirements".
As a result of the decline in commodity prices, we recognized impairment
expenses relating to proved properties of $691.3 million for the year ended
December 31, 2015 in the Utica Shale. For the year ended December 31, 2014, we
recognized impairment expenses relating to proved properties of $34.9 million,
related primarily to our Conventional properties. In addition, we recognized
impairment expenses relating to unproved properties of $95.6 million and $5.7
million for the years ended December 31, 2015 and 2014, respectively. The
increase in impairment charges related to unproved properties during the year
ended December 31, 2015 is the result of an increase in expected lease
expirations due to the reduction in our planned future drilling activity due to
the current pricing environment.
We consider future commodity prices when determining our development plan, but
many other factors are also considered. Although the magnitude of change in
these collective factors within a sustained low commodity price environment is
difficult to estimate, we currently expect to execute our development plan based
on current conditions. To the extent there is a significant increase or decrease
in commodity prices in the future, we will assess the impact on our development
plan at that time, and we may respond to such changes by altering our capital
budget or our development plan. We plan to fund our development budget with a
portion of the cash on hand at December 31, 2015, borrowings under our revolving
credit facility, proceeds from asset sales, and proceeds from additional debt
and/or equity offerings.
Results of Operations
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to natural gas, NGLs and oil sales for the years ended December 31, 2015 and 2014:
Year Ended December 31,
2015 2014 Change
Revenues (in thousands):
Natural gas sales $ 129,561 $ 69,450 $ 60,111
NGLs sales 30,177 21,048 9,129
Oil sales 74,863 47,318 27,545
Total oil and natural gas sales $ 234,601 $ 137,816 $ 96,785
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Our production grew by approximately 49,337 MMcfe for the year ended December 31, 2015 over the same period in 2014, as we placed new wells into production, partially offset by natural decline. Our production for the years ended December 31, 2015 and 2014 is set forth in the following table:
Year Ended December 31,
2015 2014 Change
Production:
Natural gas (MMcf) 49,477.6 19,760.2 29,717.4
NGLs (MBbls) 2,450.3 536.0 1,914.3
Oil (MBbls) 1,950.5 594.9 1,355.6
Total (MMcfe) 75,882.4 26,545.5 49,336.9
Average daily production volume:
Natural gas (Mcf/d) 135,555 54,137 81,418
NGLs (Bbls/d) 6,713 1,468 5,245
Oil (Bbls/d) 5,344 1,630 3,714
Total (Mcfe/d) 207,897 72,727 135,170
Our average realized price (including cash derivative settlements and firm
third-party transportation costs) received during the year ended December 31,
2015 was $3.38 per Mcfe compared to $5.09 per Mcfe during the year ended
December 31, 2014. Because we record transportation costs on two separate bases,
as required by
U.S.
GAAP, we believe computed final realized prices of
production volumes should include the total impact of firm transportation
expense. Our average realized price (including all derivative settlements and
third-party firm transportation costs) calculation also includes all cash
settlements for derivatives. Average sales price (excluding cash settled
derivatives) does not include derivative settlements or third party
transportation costs which are reported in transportation, gathering and
compression expense on the accompanying consolidated statements of operations.
Average sales price (excluding cash settled derivatives) does include
transportation costs where we receive net revenue proceeds from purchasers.
Average realized price calculations for the years ended December 31, 2015 and
2014 are shown below:
Year Ended December 31,
2015 2014 Change
Average Sales Price (excluding cash settled
derivatives)
Natural gas ($/Mcf) $ 2.62 $ 3.51 $ (0.89 )
NGLs ($/Bbl) 12.32 39.27 (26.95 )
Oil ($/Bbl) 38.38 79.54 (41.16 )
Total average prices ($/Mcfe) 3.09 5.19 (2.10 )
Average Realized Price (including cash
settled derivatives)
Natural gas ($/Mcf) $ 3.27 $ 3.52 $ (0.25 )
NGLs ($/Bbl) 12.32 39.27 (26.95 )
Oil ($/Bbl) 40.92 79.54 (38.62 )
Total average prices ($/Mcfe) 3.58 5.20 (1.62 )
Average Realized Price (including firm
transportation)
Natural gas ($/Mcf) $ 2.31 $ 3.37 $ (1.06 )
NGLs ($/Bbl) 12.32 39.27 (26.95 )
Oil ($/Bbl) 38.38 79.54 (41.16 )
Total average prices ($/Mcfe) 2.89 5.09 (2.20 )
Average Realized Price (including cash
settled derivatives and firm transportation)
Natural gas ($/Mcf) $ 2.95 $ 3.38 $ (0.43 )
NGLs ($/Bbl) 12.32 39.27 (26.95 )
Oil ($/Bbl) 38.38 79.54 (41.16 )
Total average prices ($/Mcfe) 3.38 5.09 (1.71 )
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Brokered natural gas and marketing revenue was $20.7 million for the year ended
December 31, 2015. We did not have any brokered natural gas and marketing
revenue for the year ended December 31, 2014. Brokered natural gas and marketing
revenue includes revenue received from selling natural gas not related to
production and from the release of firm transportation capacity.
Costs and Expenses
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2015 and 2014.
Year Ended December 31,
2015 2014 Change
Operating expenses (in thousands):
Lease operating $ 13,904 $ 8,518 $ 5,386
Transportation, gathering and compression 85,846 18,114
67,732
Production and ad valorem taxes 11,621 7,084
4,537
Depreciation, depletion and amortization 244,750 89,218
155,532
General and administrative 46,409 42,109
4,300
Operating expenses per Mcfe:
Lease operating $ 0.18 $ 0.32 $ (0.14 )
Transportation, gathering and compression 1.13 0.68
0.45
Production, severance and ad valorem taxes 0.15 0.27 (0.12 )
Depletion, depreciation and amortization 3.23 3.36 (0.13 )
General and administrative 0.61 1.59 (0.98 )
Lease operating expense was $13.9 million in the year ended December 31, 2015
compared to $8.5 million in the year ended December 31, 2014. The increase of
$5.4 million is attributable to higher production during the year ended
December 31, 2015, as compared to the year ended December 31, 2014. Lease
operating expenses include normally recurring expenses to operate and produce
our wells, non-recurring workovers and repairs. We experience increases in
operating expenses as we add new wells and manage existing properties.
Transportation, gathering and compression expense was $85.8 million during the
year ended December 31, 2015 compared to $18.1 million in the year ended
December 31, 2014. These third party costs were higher in the year ended
December 31, 2015 due to our production growth where we have third party
gathering and compression agreements, as well as firm transportation contracts
that became effective in 2015. The following table details our transportation,
gathering and compression expenses for the years ended December 31, 2015 and
2014:
Year Ended December 31,
2015 2014 Change
Transportation, gathering and compression
(in thousands):
Gathering, compression and fuel $ 30,079 $ 11,819 $ 18,260
Processing and fractionation 30,899 3,067 27,832
Liquids transportation and stabilization 9,342 2,626 6,716
Marketing 48 453 (405 )
Firm transportation 15,478 149 15,329
$ 85,846 $ 18,114 $ 67,732
Production and ad valorem taxes are paid based on market prices and applicable
tax rates. Production and ad valorem taxes were $11.6 million in the year ended
December 31, 2015 compared to $7.1 million in the year ended December 31, 2014.
Production and ad valorem taxes increased from the year ended December 31, 2014
to the year ended December 31, 2015 due to an increase in production volumes
subject to production or ad valorem taxes.
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Depletion, depreciation and amortization was approximately $244.8 million in the
year ended December 31, 2015 compared to $89.2 million in the year ended
December 31, 2014. The increase in the year ended December 31, 2015 when
compared to the year ended December 31, 2014 is due to the increase in
production during 2015. On a per Mcfe basis, DD&A decreased to $3.23 in the year
ended December 31, 2015 from $3.36 in the year ended December 31, 2014.
General and administrative expense was $46.4 million for the year ended
December 31, 2015 compared to $42.1 million for the year ended December 31,
2014. The increase of $4.3 million during the year ended December 31, 2015 when
compared to the year ended December 31, 2014 is primarily due to stock-based
compensation expenses of $4.6 million incurred during the year ended December
31, 2015 compared to $0.3 million incurred during the year ended December 31,
2014.
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not
trend with production. These expenses include exploration expense, impairment
charges and accretion of asset retirement obligation expense and gain on
reduction of pension obligations. The following table details our other
operating expenses for the years ended December 31, 2015 and 2014.
2015 2014
Change
Other Operating Expenses (in thousands):
Brokered natural gas and marketing $ 26,173 $ - $ 26,173
Exploration 116,211 21,186 95,025
Rig termination and standby 9,672 3,283 6,389
Accretion of asset retirement obligations 1,623 791 832
Impairment of proved oil and natural gas
properties 691,334 34,855
656,479
Gain on sale of assets (4,737 ) (960 ) (3,777 )
Gain on reduction of pension obligations - (2,208
) 2,208
Brokered natural gas and marketing expense was $26.2 million for the year ended
December 31, 2015. We did not have any brokered natural gas and marketing
expense for the year ended December 31, 2014. These expenses are natural gas
purchases for brokered natural gas that we buy and sell that is not related to
our production and firm transportation capacity that is marketed to third
parties in excess of production volumes.
Exploration expense increased to $116.2 million in the year ended December 31,
2015 compared to $21.2 million in the year ended December 31, 2014. The increase
was primarily due to higher impairment of unproved properties related to lease
expirations, and higher delay rentals due to lease modifications. The following
table details our exploration-related expenses for the years ended December 31,
2015 and 2014.
2015 2014 Change
Exploration Expenses (in thousands):
Geological and geophysical $ 435 $ 802 $
(367 )
Delay rentals 19,692 13,951
5,741
Impairment of unproved properties 95,573 5,671 89,902
Dry hole 276 762 (486 )
Other exploration 235 - 235
$ 116,211 $ 21,186 $ 95,025
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Impairment of unproved properties was $95.6 million for the year ended
December 31, 2015 compared to $5.7 million for the year ended December 31, 2014.
We assess individually significant unproved properties for impairment and
recognize a loss where circumstances indicate impairment in value. In
determining whether a significant unproved property is impaired, we consider
numerous factors, including, but not limited to, current exploration plans,
favorable or unfavorable activity on the property being evaluated and/or
adjacent properties, our geologists' evaluation of the property and the
remaining months in the lease term for the property. Impairment of individually
insignificant unproved properties is assessed and amortized on an aggregate
basis based on our average holding period, expected forfeiture rate and
anticipated drilling success. As we continue to review our acreage positions and
high grade our drilling inventory based on the current price environment,
additional leasehold impairments and abandonments may be recorded.
Rig termination and standby expense was $9.7 million for the year ended
December 31, 2015 compared to $3.3 million for the year ended December 31, 2014.
One horizontal rig was terminated during the year ended December 31, 2015, and
we incurred standby costs of approximately $2 million as a result of temporarily
suspending our drilling operations during the fourth quarter of 2015. Two
horizontal rigs were terminated during the year ended December 31, 2014.
Accretion of asset retirement obligations was $1.6 million in the year ended
December 31, 2015, compared to $0.8 million in the year ended December 31, 2014.
The increase in accretion expense primarily relates to the increase in the asset
retirement obligations associated with the increase in the number of producing
wells in the year ended December 31, 2015.
Impairment of proved oil and natural gas properties was $691.3 million for the
year ended December 31, 2015 compared to $34.9 million for the year ended
December 31, 2014. An analysis of proved properties determined the future
undiscounted cash flows were less than the carrying value for certain asset
groupings. An impairment expense was recognized for these asset groupings based
on the difference between the fair market value and carrying value of the asset
groupings. The impairment recorded for the year ended December 31, 2015 related
to Utica Shale properties and $30.9 million of the impairment recorded for the
year ended December 31, 2014 related to Conventional properties.
Gain on sale of assets was $4.7 million for the year ended December 31, 2015
representing the gain on the sale of a central processing facility and certain
pipelines.
Gain on reduction of pension obligations was $0 for the year ended December 31,
2015, compared to $2.2 million in the year ended December 31, 2014. Effective
March 31, 2014, we froze the benefit accruals related to the defined benefit
pension plan we assumed in the Oxford Acquisition, which was completed during
the fiscal 2013. The plan was terminated during October 2015 and final
distributions were made to all participants.
Other Income (Expense)
Gain on derivative instruments was $56.0 million for the year ended December 31,
2015 compared to $20.8 million for the year ended December 31, 2014. We received
cash of approximately $37.1 million on derivative instruments that settled
during the year ended December 31, 2015 and made cash payments of approximately
$0.5 million on derivative instruments that settled during the year ended
December 31, 2014.
Interest expense, net was $53.4 million for the year ended December 31, 2015
compared to $48.3 million for year ended December 31, 2014. The increase in
interest expense during the year ended December 31, 2015 was due to the increase
in the principal balance of our long term debt outstanding for the year ended
December 31, 2015 compared to the year ended December 31, 2014.
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Loss on early extinguishment of debt was $59.4 million for the year ended
December 31, 2015 resulting from the redemption of our outstanding 12.0% Senior
PIK Notes due 2018, comprised of the make-whole premium of $47.6 million and
unamortized discount and deferred financing costs of $11.8 million. There were
no early extinguishment costs incurred in the year ended December 31, 2014.
Income tax benefit was $72.4 million for the year ended December 31, 2015
compared to income tax expense of $71.8 million for the year ended December 31,
2014. The income tax benefit for the year ended December 31, 2015 was due to
pre-tax loss incurred during the year ended December 31, 2015, net of a
valuation allowance of $292.3 million. The income tax expense for the year ended
December 31, 2014 was primarily related to a charge to record the initial impact
of the change in our tax status as a result of the Corporate Reorganization,
partially offset by the income tax benefit of $25.8 million realized from the
operating loss following the Corporate Reorganization.
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to natural gas, NGLs and oil sales for the years ended December 31, 2014 and 2013.
Year Ended December 31,
2014 2013 Change
Revenues (in thousands):
Natural gas sales $ 69,450 $ 4,303 $ 65,147
NGLs sales 21,048 63 20,985
Oil sales 47,318 8,569 38,749
Total oil and natural gas sales $ 137,816 $ 12,935 $ 124,881
Our production grew by approximately 24,895 MMcfe for the year ended December 31, 2014 over the same period in 2013, which was attributable to additions from acquisitions and drilling success as we placed new wells on production, partially offset by natural decline. Our production for the years ended December 31, 2014 and 2013 is set forth in the following table:
Year Ended December 31,
2014 2013 Change
Production:
Natural gas (MMcf) 19,760.2 1,118.8 18,641.4
NGLs (Mbbls) 536.0 1.3 534.7
Oil (Mbbls) 594.9 87.2 507.7
Total (MMcfe) 26,545.5 1,650.2 24,895.3
Average daily production volume:
Natural gas (Mcf/d) 54,137 3,065 51,072
NGLs (Bbls/d) 1,468 4 1,464
Oil (Bbls/d) 1,630 239 1,391
Total (Mcfe/d) 72,727 4,521 68,206
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Our average realized price (including cash derivative settlements and firm
third-party transportation costs) received during the year ended December 31,
2014 was $5.09 per Mcfe compared to $7.84 per Mcfe during the year ended
December 31, 2013. Because we record transportation costs on two separate bases
as required by
U.S.
GAAP, we believe computed final realized prices of
production volumes should include the total impact of firm transportation
expense. Our average realized price (including all derivative settlements and
third-party firm transportation costs) calculation also includes all cash
settlements for derivatives. Average sales price (excluding cash settled
derivatives) does not include derivative settlements or third party
transportation costs which are reported in transportation, gathering and
compression expense on the accompanying consolidated statements of operations.
Average sales price (excluding cash settled derivatives) does include
transportation costs where we receive net revenue proceeds from purchasers.
Average realized price calculations for the years ended December 31, 2014 and
2013 are shown below:
Year Ended December 31,
2014 2013 Change
Average Sales Price (excluding cash settled
derivatives)
Natural gas ($/Mcf) $ 3.51 $ 3.85 $ (0.34 )
NGLs ($/Bbl) 39.27 48.17 (8.90 )
Oil ($/Bbl) 79.54 98.22 (18.68 )
Total average prices ($/Mcfe) 5.19 7.84 (2.65 )
Average Realized Price (including cash
settled derivatives)
Natural gas ($/Mcf) $ 3.52 $ 3.85 $ (0.33 )
NGLs ($/Bbl) 39.27 48.17 (8.90 )
Oil ($/Bbl) 79.54 98.22 (18.68 )
Total average prices ($/Mcfe) 5.20 7.84 (2.64 )
Average Realized Price (including firm
transportation)
Natural gas ($/Mcf) $ 3.37 $ 3.85 $ (0.48 )
NGLs ($/Bbl) 39.27 48.17 (8.90 )
Oil ($/Bbl) 79.54 98.22 (18.68 )
Total average prices ($/Mcfe) 5.09 7.84 (2.75 )
Average Realized Price (including cash
settled derivatives and firm transportation)
Natural gas ($/Mcf) $ 3.38 $ 3.85 $ (0.47 )
NGLs ($/Bbl) 39.27 48.17 (8.90 )
Oil ($/Bbl) 79.54 98.22 (18.68 )
Total average prices ($/Mcfe) 5.09 7.84 (2.75 )
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Costs and Expenses
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2014 and 2013.
Year Ended December 31,
2014 2013 Change
Operating expenses (in thousands):
Lease operating $ 8,518 $ 2,576
$ 5,942
Transportation, gathering and compression 18,114 67
18,047
Production and ad valorem taxes 7,084 77
7,007
Depreciation, depletion and amortization 89,218 6,163
83,055
General and administrative 42,109 21,276
20,833
Operating expenses per Mcfe:
Lease operating $ 0.32 $ 1.56
$ (1.24 )
Transportation, gathering and compression 0.68 0.04
0.64
Production, severance and ad valorem taxes 0.27 0.05
0.22
Depletion, depreciation and amortization 3.36 3.73 (0.37 )
General and administrative 1.59 12.89 (11.30 )
Lease operating expense was $8.5 million in the year ended December 31, 2014
compared to $2.6 million in the year ended December 31, 2013. The increase of
$5.9 million is attributable to higher production during the year ended
December 31, 2014, as compared to the year ended December 31, 2013. Lease
operating expenses include normally recurring expenses to operate and produce
our wells, non-recurring workovers and repairs. We experience increases in
operating expenses as we add new wells and manage existing properties. We
incurred $1.0 million of workover costs in the year ended December 31, 2014
compared to $0 in the year ended December 31, 2013.
Transportation, gathering and compression expense was $18.1 million during the
year ended December 31, 2014 compared to less than $0.1 million in the year
ended December 31, 2013. These third party costs were higher in the year ended
December 31, 2014 due to our production growth where we have third party
gathering and compression agreements.
Production and ad valorem taxes are paid based on market prices and applicable
tax rates. Production and ad valorem taxes were $7.1 million in the year ended
December 31, 2014 compared to less than $0.1 million in the year ended
December 31, 2013. Production and ad valorem taxes increased from the year ended
December 31, 2013 to the year ended December 31, 2014 due to an increase in
production volumes subject to production or ad valorem taxes.
Depletion, depreciation and amortization was approximately $89.2 million in the
year ended December 31, 2014 compared to $6.2 million in the year ended
December 31, 2013. The increase in the year ended December 31, 2014 when
compared to the year ended December 31, 2013 is due to the increase in
production during 2014. On a per Mcfe basis, DD&A decreased to $3.36 in the year
ended December 31, 2014 from $3.73 in the year ended December 31, 2013, which
was predominantly driven by a lower depletion rate. The decrease in depletion
rate during the year ended December 31, 2014 was due to total proved reserves
(the denominator) increasing at a higher rate than production (the numerator)
over the year.
General and administrative expense was $42.1 million for the year ended
December 31, 2014 compared to $21.3 million for the year ended December 31,
2013. The increase of $20.8 million during the year ended December 31, 2014 when
compared to year ended December 31, 2013 is primarily due to higher salaries and
benefits related to the hiring of a significant number of new employees during
the year ended December 31, 2014.
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Other Operating Expenses
Our total operating expenses also include other expenses that generally do not
trend with production. These expenses include exploration expense, impairment
charges and accretion of asset retirement obligation expense and gain on
reduction of pension obligations. The following table details our other
operating expenses for the years ended December 31, 2014 and 2013.
2014 2013
Change
Other Operating Expenses (in thousands):
Exploration $ 21,186 $ 3,022 $ 18,164
Rig termination and standby 3,283 -
3,283
Accretion of asset retirement obligations 791 364
427
Impairment of proved oil and natural gas properties 34,855 2,081
32,774
Gain on sale of assets (960 ) - (960 )
Gain on reduction of pension obligations (2,208 ) -
(2,208 )
Exploration expense increased to $21.2 million in the year ended December 31,
2014 compared to $3.0 million in the year ended December 31, 2013. The increase
was due to higher impairment of unproved properties related to lease
expirations, dry hole costs, and delay rentals due to acreage increases and
lease modifications. The following table details our exploration-related
expenses for the years ended December 31, 2014 and 2013.
2014 2013 Change
Exploration Expenses (in thousands):
Geological and geophysical $ 802 $ 124 $ 678
Delay rentals 13,951 2,688 11,263
Impairment of unproved properties 5,671 - 5,671
Dry hole 762 210 552
$ 21,186 $ 3,022 $ 18,164
Impairment of unproved properties was $5.7 million for the year ended
December 31, 2014 compared to $0 million for the year ended December 31, 2013.
We assess individually significant unproved properties for impairment and
recognize a loss where circumstances indicate impairment in value. In
determining whether a significant unproved property is impaired, we consider
numerous factors, including, but not limited to, current exploration plans,
favorable or unfavorable activity on the property being evaluated and/or
adjacent properties, our geologists' evaluation of the property and the
remaining months in the lease term for the property. Impairment of individually
insignificant unproved properties is assessed and amortized on an aggregate
basis based on our average holding period, expected forfeiture rate and
anticipated drilling success. As we continue to review our acreage positions and
high grade our drilling inventory based on the current price environment,
additional leasehold impairments and abandonments may be recorded.
Rig termination and standby was $3.3 million for the year ended December 31,
2014. No such costs were incurred during the year ended December 31, 2013. We
terminated two of our drilling rig contracts during the year ended December 31,
2014.
Accretion of asset retirement obligations was $0.8 million in the year ended
December 31, 2014, compared to $0.4 million in the year ended December 31, 2013.
The increase in accretion expense primarily relates to the increase in the asset
retirement obligations associated with new wells drilled during the year ended
December 31, 2014 and existing wells acquired in the Oxford Acquisition in June
2013.
Impairment of proved oil and natural gas properties was $34.9 million for the
year ended December 31, 2014 compared to $2.1 million for the year ended
December 31, 2013. An analysis of proved properties determined the future
undiscounted cash flows were less than the carrying value for certain asset
groupings. An impairment expense was recognized for these asset groupings based
on the difference between the fair market value and carrying value of the asset
groupings.
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Gain on sale of assets was $1.0 million for the year ended December 31, 2014 representing the gain on the sale of a central processing facility. No such sales occurred during the year ended December 31, 2013.
Gain on reduction of pension obligations was $2.2 million for the year ended
December 31, 2014, compared to $0 in the year ended December 31, 2013. Effective
March 31, 2014, we froze the benefit accruals related to the defined benefit
pension plan we assumed in the Oxford Acquisition, which was completed during
the fiscal 2013.
Other Income (Expense)
Gain on derivative instruments was $20.8 million for the year ended December 31,
2014. There was no gain or loss on derivatives in the year ended December 31,
2013 as we did not have derivative instruments in place during this period. We
made cash payments of approximately $0.5 million on derivative instruments that
settled during the year ended December 31, 2014.
Interest expense, net was $48.3 million for the year ended December 31, 2014
compared to $20.9 million for year ended December 31, 2013. The increase in
interest expense during the year ended December 31, 2014 was due to the June
2013 and December 2013 issuances of $281.2 million and $100.0 million,
respectively, of our 12% senior unsecured PIK notes due 2018, net of discounts
and offering expenses, as well as the $26.9 million drawn on our Revolving
Credit Facility during 2014.
Income tax expense was $71.8 million for the year ended December 31, 2014
primarily related to a charge of $97.6 million to record the initial impact of
the change in our tax status as a result of the Corporate Reorganization,
partially offset by the income tax benefit of $25.8 million realized from the
operating loss following the Corporate Reorganization.
Cash Flows, Capital Resources and Liquidity
Cash Flows
Cash flows from operations are primarily affected by production volumes and
commodity prices. Our cash flows from operations also are impacted by changes in
working capital. Short-term liquidity needs are satisfied by our operating cash
flow, proceeds from asset sales, and proceeds from issuances of debt and equity.
We sell a large portion of our production at the wellhead under floating market
contracts.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Net cash provided by operations in the year ended December 31, 2015 was $80.3
million compared to $8.5 million in the year ended December 31, 2014. The
increase in cash provided from operating activities from the year ended December
31, 2014 to 2015 reflects an increase in production, partially offset by higher
operating costs. Net cash provided from operations is also affected by working
capital changes or the timing of cash receipts and disbursements.
Net cash used in investing activities in the year ended December 31, 2015 was $437.3 million compared to $718.4 million in the year ended December 31, 2014.
During the year ended December 31, 2015, we:
• spent $475.7 million on capital expenditures for oil and natural gas
properties;
• spent $1.7 million on property and equipment;
• received proceeds of $40.1 million from the sale of gathering facilities
and equipment; and
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During the year ended December 31, 2014, we:
• spent $731 million on capital expenditures for oil and natural gas
properties;
• spent $3.6 million on property and equipment;
• received proceeds of $15.5 million from the sale of a central processing
facility; and
• received proceeds of $0.8 million related to the acquisition of Eclipse
Operating.
Net cash provided by financing activities in the year ended December 31, 2015 decreased to $473.9 million compared to $667.9 million in the year ended December 31, 2014.
During the year ended December 31, 2015, we:
• issued shares of common stock in a private placement transaction for
proceeds to us totaling approximately $434.1 million, net of $5.9 million
of issuance costs; and
• received net proceeds of $525.2 million from the issuance of senior
unsecured notes, net of debt issuance costs; and
• paid $485.3 million for the redemption of 12.0% Senior PIK notes,
comprised of outstanding principal balance of $437.3 million and
make-whole premium of $47.6 million.
During the year ended December 31, 2014, we:
• issued shares of common stock in our IPO for proceeds to us totaling
approximately $544.7 million, net of $5.3 million of IPO costs;
• received capital contributions of $124.7 million from private equity funds
managed by EnCap and investment funds controlled by certain members of our
management prior to the IPO.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Net cash provided by operations in the year ended December 31, 2014 was $8.5
million compared to $12.4 million in the year ended December 31, 2013. The
increase in cash provided from operating activities from the year ended 2013 to
2014 reflects an increase in production, partially offset by higher operating
costs. Net cash provided from operations is also affected by working capital
changes or the timing of cash receipts and disbursements.
Net cash used in investing activities in the year ended December 31, 2014 was $718.4 million compared to $894.3 million in the year ended December 31, 2013.
During the year ended December 31, 2014, we:
• spent $731 million on capital expenditures for oil and natural gas
properties;
• spent $3.6 million on property and equipment;
• received proceeds of $15.5 million from the sale of a central processing
facility; and
• received proceeds of $0.8 million related to the acquisition of Eclipse
Operating.
During the year ended December 31, 2013, we:
• spent $250 million on capital expenditures for oil and natural gas
properties;
• spent $651.8 million on the Oxford acquisition; and
• received proceeds of $8.5 million from the sale of properties.
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Net cash provided by financing activities in the year ended December 31, 2014 decreased to $667.9 million compared to $964.3 million in the year ended December 31, 2013.
During the year ended December 31, 2014, we:
• issued shares of common stock in our IPO for proceeds to us totaling
approximately $544.7 million, net of $5.3 million of IPO costs;
• received capital contributions of $124.7 million from private equity funds
managed by EnCap and investment funds controlled by certain members of our
management prior to the IPO.
During the year ended December 31, 2013, we:
• received proceeds of $380.7 million from the issuance of debt, net of debt
issuance costs; and
• received capital contributions of $583.6 million from private equity funds
managed by EnCap and investment funds controlled by certain members of our
management.
Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated
cash flow from operations, asset sales and access to the debt and equity capital
markets. We must find new and develop existing reserves to maintain and grow our
production and cash flows. We accomplish this primarily through successful
drilling programs which requires substantial capital expenditures. We
periodically review capital expenditures and adjust our budget based on
liquidity, drilling results, leasehold acquisition opportunities, and commodity
prices. We believe that our existing cash on hand, operating cash flow and
available proceeds under our Revolving Credit Facility will be adequate to meet
our capital and operating requirements for 2016.
Future success in growing reserves and production will be highly dependent on
capital resources available and the success of finding or acquiring additional
reserves. We will continue using net cash on hand, cash flows from operations
and proceeds available under our Revolving Credit Facility to satisfy near-term
financial obligations and liquidity needs, and as necessary, we will seek
additional sources of debt or equity to fund these requirements. Longer-term
cash flows are subject to a number of variables including the level of
production and prices we receive for our production as well as various economic
conditions that have historically affected the natural gas and oil business. Our
ability to expand our reserve base is, in part, dependent on obtaining
sufficient capital through internal cash flow, bank borrowings, asset sales or
the issuance of debt or equity securities. There can be no assurance that
internal cash flow and other capital sources will provide sufficient funds to
maintain capital expenditures that we believe are necessary to offset inherent
declines in production and proven reserves
As of December 31, 2015, we were in compliance with all of our debt covenants
under our Revolving Credit Facility and 8.875% Senior Unsecured Notes due 2023.
Further, based on our current forecast and activity levels, we expect to remain
in compliance with all such debt covenants for the next twelve months. However,
if oil and natural gas prices remain at current levels for longer than we
expect, or fall to lower levels, we are likely to generate lower operating cash
flows, which would make it more difficult for us to remain in compliance with
all of our debt covenants, including requirements with respect to working
capital and interest coverage ratios. This could negatively impact our ability
to maintain sufficient liquidity and access to capital resources.
Credit Arrangements
Long-term debt at December 31, 2015, excluding discount, totaled $550.0 million
and at December 31, 2014 totaled $422.5 million. We redeemed all of the
outstanding 12.0% Senior PIK Notes on July 13, 2015 for approximately $510.7
million, including outstanding principal balance, a make-whole premium and
accrued interest. (See Note 8-Debt located in the Notes to the Consolidated
Financial Statements included in Item 8 of Part II of this Annual Report on Form
10-K).
On July 6, 2015, we issued $550 million in aggregate principal amount of 8.875% senior notes due 2023 (the "Notes") at an issue price of 97.903% of the principal amount of the Notes, plus accrued and unpaid interest,
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if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this
private offering, the Notes were sold for cash to qualified institutional buyers
in
the United States
pursuant to Rule 144A of the Securities Act and to persons
outside
the United States
in compliance with Regulation S under the Securities
Act. Upon closing, we received proceeds of approximately $525.5 million, after
deducting original issue discount, the initial purchasers' discounts and
estimated offering expenses, of which we used approximately $510.7 million to
finance the redemption of all of our outstanding 12.0% Senior PIK notes due
2018. We intend to use the remaining net proceeds to fund our capital
expenditure plan and for general corporate purposes. (See Note 8-Debt located in
the Notes to the Consolidated Financial Statements included in Item 8 of Part II
of this Annual Report on Form 10-K).
The indenture governing the Notes (the "Indenture") contains covenants that,
among other things, limit the ability of our restricted subsidiaries to:
(i) incur additional indebtedness, (ii) pay dividends on capital stock or
redeem, repurchase or retire our capital stock or subordinated indebtedness,
(iii) transfer or sell assets, (iv) make investments, (v) create certain liens,
(vi) enter into agreements that restrict dividends or other payments to the
Company from its restricted subsidiaries, (vii) consolidate, merge or transfer
all or substantially all of the assets of the Company and its restricted
subsidiaries, taken as a whole, (viii) engage in transactions with affiliates,
and (ix) create unrestricted subsidiaries. These covenants are subject to a
number of important exceptions and qualifications set forth in the Indenture. In
addition, if the Notes achieve an investment grade rating from either Moody's
Investors Service, Inc. or Standard & Poor's Ratings Services, and no default
under the Indenture has then occurred and is continuing, many of such covenants
will be suspended. The Indenture also contains events of default, which include,
among others and subject in certain cases to grace and cure periods, nonpayment
of principal or interest, failure by the Company to comply with its other
obligations under the Indenture, payment defaults and accelerations with respect
to certain other indebtedness of the Company and its restricted subsidiaries,
failure of any guarantee on the Notes to be enforceable, and certain events of
bankruptcy or insolvency. We were in compliance with all covenants at
December 31, 2015.
In February 2014, we entered into our $500 million Revolving Credit Facility,
which was amended and restated on January 12, 2015. The Revolving Credit
Facility matures on January 15, 2018 and includes customary affirmative and
negative covenants. As of December 31, 2014, the borrowing base was $100 million
and we had no outstanding borrowings. In March 2015, we had a redetermination of
the borrowing base under the Revolving Credit Facility, which increased the
borrowing base to $125 million. The redeterminations completed in November 2015
and February 2016 resulted in no change to the borrowing base of $125 million.
After giving effect to our outstanding letters of credit issued, totaling $27.8
million, we had available borrowing capacity under our Revolving Credit Facility
of $97.2 million at December 31, 2015. The borrowing base under our Revolving
Credit Facility is scheduled to be redetermined semi-annually (in April and
October) with our next redetermination expected to be completed by October 2016.
The Revolving Credit Facility was further amended and restated on June 11, 2015
and became effective upon the issuance of the Notes. Among other things,
pursuant to this amendment, we assumed all of the rights and obligations of
Eclipse I as the borrower under the Revolving Credit Facility. Furthermore, the
amendment allowed for the issuance of the Notes and provided that we would not
incur an immediate reduction in borrowing base under the Revolving Credit
Facility as a result of the issuance of the Notes. Accordingly, the borrowing
base under the Revolving Credit Facility immediately following the issuance of
the Notes remained at $125.0 million until the redetermination performed during
October 2015. This redetermination was completed in November 2015, resulting in
no change to the borrowing base of $125.0 million.
On February 24, 2016, we amended our Revolving Credit Facility to, among other
things, adjust our quarterly minimum interest coverage ratio, which is the ratio
of EBITDAX to Cash Interest Expense, and to permit the sale of certain
conventional properties. The amendment to the Revolving Credit Facility also
increases the Applicable Margin (as defined in the Credit Agreement) applicable
to loans and letter of credit participation fees under the Credit Agreement by
0.5% and requires us to, within 60 days of the effectiveness of the amendment,
execute and deliver additional mortgages on our oil and gas properties that
include at least 90% of our proved reserves.
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Commodity Hedging Activities
Our primary market risk exposure is in the prices we receive for our natural
gas, NGLs and oil production. Realized pricing is primarily driven by the spot
regional market prices applicable to our
U.S.
natural gas, NGLs and oil
production. Pricing for natural gas, NGLs and oil production has been volatile
and unpredictable for several years, and we expect this volatility to continue
in the future. The prices we receive for production depend on many factors
outside of our control, including volatility in the differences between product
prices at sales points and the applicable index price.
To mitigate the potential negative impact on our cash flow caused by changes in
natural gas, NGLs and oil prices, we may enter into financial commodity
derivative contracts to ensure that we receive minimum prices for a portion of
our future natural gas production when management believes that favorable future
prices can be secured. We typically hedge the NYMEX Henry Hub price for natural
gas, the West Texas Intermediate, or WTI, price for oil and an NGLs basket based
on prices at
Mont Belvieu, Texas
.
Our hedging activities are intended to support natural gas, NGLs and oil prices
at targeted levels and to manage our exposure to price fluctuations. The
counterparty is required to make a payment to us for the difference between the
floor price specified in the contract and the settlement price, which is based
on market prices on the settlement date, if the settlement price is below the
floor price. We are required to make a payment to the counterparty for the
difference between the ceiling price and the settlement price if the ceiling
price is below the settlement price. These contracts may include price swaps
whereby we will receive a fixed price for our production and pay a variable
market price to the contract counterparty, zero cost collars that set a floor
and ceiling price for the hedged production, and puts which require us to pay a
premium either up front or at settlement and allow us to receive a fixed price
at our option if the put price is above the market price. As of December 31,
2015, we had entered into the following derivative contracts:
Natural Gas Derivatives
Volume Weighted Average
Description (MMBtu/d) Production Period Price ($/MMBtu)
Natural Gas Swaps:
65,000 January 2016-December 2016 $ 3.28
Natural Gas Collar:
Floor purchase price
(put) 30,000 January 2016-December 2017 $ 3.00
Ceiling sold price
(call) 30,000 January 2016-December 2017 $ 3.50
Natural Gas Three-way
Collars:
Floor purchase price
(put) 40,000 January 2016-December 2016 $ 2.90
Ceiling sold price
(call) 20,000 January 2016-December 2016 $ 3.25
Ceiling sold price
(call) 20,000 January 2016-December 2016 $ 3.22
Floor sold price (put) 40,000 January 2016-December 2016 $ 2.35
Natural Gas Call/Put
Options:
Put sold 16,800 January 2016-December 2016 $ 2.75
Call sold 40,000 January 2018-December 2018 $ 3.75
Basis Swaps:
20,000 January 2016-March 2016 $ 0.83
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Oil Derivatives
Volume Weighted Average
Description (Bbls/d) Production Period Price ($/Bbl)
Oil Collar:
Floor purchase price (put) 3,000 January 2016-February 2016 $ 55.00
Ceiling sold price (call) 3,000 January 2016-February 2016 $ 61.40
Oil Three-way Collar:
Floor purchase price (put) 1,000 March 2016-December 2016 $ 60.00
Ceiling sold price (call) 1,000 March 2016-December 2016 $ 70.10
Floor sold price (put) 1,000 March 2016-December 2016 $ 45.00
NGL Derivatives
Volume Weighted Average
Description (Gal/d) Production Period Price ($/Gal)
Propane Swaps:
42,000 January 2016-December 2016 $ 0.46
21,000 January 2016-June 2016 $ 0.44
10,500 July 2016-September 2016 $ 0.46
(1) The natural gas derivative contracts are settled based on the NYMEX price of
natural gas at Henry Hub on the last commodity business day of the futures
contract corresponding to the calculation period.
By using derivative instruments to hedge exposures to changes in commodity
prices, we expose ourselves to the credit risk of our counterparties. Credit
risk is the potential failure of the counterparty to perform under the terms of
the derivative contract. When the fair value of a derivative contract is
positive, the counterparty is expected to owe us, which creates credit risk. To
minimize the credit risk in derivative instruments, it is our policy to enter
into derivative contracts only with counterparties that are creditworthy
financial institutions deemed by management as competent and competitive market
makers. The creditworthiness of our counterparties is subject to periodic
review. We have derivative instruments in place with Bank of Montreal, Citibank,
N.A. and Key Bank NA. We believe both institutions currently are an acceptable
credit risk. As of December 31, 2015, we did not have any past due receivables
from counterparties.
Subsequent to December 31, 2015, we entered into the following derivative instruments to mitigate our exposure to both oil and gas prices:
Natural Gas:
Weighted Average
Description (MMBtu/d) Production Period Price ($/MMBtu)
Floor purchased (put) 30,000 January 2017-December 2017 $ 2.50
Ceiling sold (call) 15,000 January 2017-December 2017 $ 3.02
Ceiling sold (call) 15,000 January 2016-December 2017 $ 3.04
Oil:
Weighted Average
Description Bbls/d Production Period Price ($/Bbl)
Call Sold 1,000 January 2018-December 2018 $ 50.00
Swap 850 March 2016-December 2016 $ 45.55
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Capital Requirements
Our primary needs for cash are for exploration, development and acquisition of
natural gas and oil properties and repayment of principal and interest on
outstanding debt. During the year ended December 31, 2015, capital expenditures
and delay rental payments on natural gas and oil properties were $309.5 million,
compared to $809.4 million for the year ended December 31, 2014. Our fiscal 2015
capital program was funded by net cash flow from operations, proceeds from asset
sales and proceeds from the issuances of common stock.
As a result of the current pricing environment, we reduced our 2016 capital
expenditure and delay rental payment budget to $167.8 million, which represents
a reduction from our corresponding 2015 amounts. We expect to fund our capital
expenditures for 2016 with cash generated by operations, borrowings under our
Revolving Credit Facility, proceeds from asset sales, and proceeds from
additional debt or equity offerings. The actual amount and timing of our future
capital expenditures may differ materially from our estimates as a result of,
among other things, natural gas, NGLs and oil prices, actual drilling results,
the availability of drilling rigs and other services and equipment, and
regulatory, technological and competitive developments. A reduction in natural
gas, NGLs or oil prices from current levels may result in a further decrease in
our actual capital expenditures, which would negatively impact our ability to
grow production and our proved reserves as well as our ability to maintain
compliance with our debt covenants. Our financing needs may require us to alter
or increase our capitalization substantially through the issuance of debt or
equity securities or the sale of assets.
In addition, we may from time to time seek to pay down, retire or repurchase our
outstanding debt using cash or through exchanges of other debt or equity
securities, in open market purchases, privately negotiated transactions or
otherwise. Such repurchases or exchanges, if any, will depend on available
funds, prevailing market conditions, our liquidity requirements, contractual
restrictions in our revolving credit agreement and other factors.
Capitalization
As of December 31, 2015 and December 31, 2014, our total debt, excluding debt
discount and issuance costs, and capitalization were as follows (in millions):
2015 2014
Senior unsecured notes $ 550.0 $ 422.5
Stockholders' equity 620.6 1,152.7
Total capitalization $ 1,170.6 $ 1,575.2
Cash Contractual Obligations
Our contractual obligations include long-term debt, operating leases, drilling
commitments, firm transportation, gas processing, gathering, and compressions
services, asset retirement obligations. As of December 31, 2015 and December 31,
2014, we do not have any capital leases, any significant off-balance sheet debt
or other such unrecorded obligations, and we have not guaranteed any debt of any
unrelated party. The table below provides estimates of the timing of future
payments that we are obligated to make based on agreements in place at
December 31, 2015. In addition to the contractual obligations listed in the
table below, our balance sheet at December 31, 2015 reflects accrued interest
payable on our senior unsecured Notes of $23.6 million, compared to $25.2
million as of December 31, 2014. We paid the accrued interest balance in January
2016.
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The following summarizes our contractual financial obligations at December 31,
2015 and their future maturities. We expect to fund these contractual
obligations with cash generated from operating activities, borrowings under our
Revolving Credit Facility, additional debt and equity issuances, and proceeds
from asset sales (in millions):
2016 2017 2018 2019 2020 Thereafter Total
Senior unsecured notes(1) $ - $ - $ - $ - $ - $ 550.0 $ 550.0
Drilling rig commitments(2) 15.2 8.1 - - - - 23.3
Firm transportation(3) 35.5 109.0 126.6 120.1 117.9 113.7 622.8
Gas processing, gathering, and
compression services(4) 9.1 9.1 18.5 22.6 11.1 - 70.4
Asset retirement obligation
liability(5) - - - - - 22.5 22.5
Operating leases 0.8 0.8 0.8 0.8 0.7 2.7 6.6
Vehicle loans 0.6 0.6 0.5 0.3 - - 2.0
$ 61.2 $ 127.6 $ 146.4 $ 143.8 $ 129.7 $ 688.9 $ 1,297.6
(1) The ultimate settlement amount and timing cannot be precisely determined in
advance. See Note 8 to our consolidated financial statements as of and for
the year ended December 31, 2015.
(2) At December 31, 2015, we had a contract for the service of one rig, which
expires in September 2017. We also had remaining termination obligations
related to two of the three rigs that were terminated in 2015 and 2014. The
values in the table represent the gross amounts that we are committed to pay;
however, we will record in our financial statements our proportionate share
of costs based on our working interest, as applicable.
(3) We have entered into firm transportation agreements with various pipelines in
order to facilitate the delivery of production to market. These contracts
commit us to transport minimum daily natural gas or NGL volumes at a
negotiated rate, or pay for any deficiencies at a specified reservation fee
rate. The amounts in this table represent our minimum daily volumes at the
reservation fee rate. The values in the table represent the gross amounts
that we are committed to pay; however, we will record in our financial
statements our proportionate share of costs based on our working interest.
(4) Contractual commitments for gas processing, gathering and compression service
agreements represent minimum commitments under long-term gas processing
agreements as well as various gas compression agreements. The values in the
table represent the gross amounts that we are committed to pay; however, we
will record in our financial statements our proportionate share of costs
based on our working interest.
(5) Neither the ultimate settlement amounts nor the timing of our asset
retirement obligations can be precisely determined in advance; however, we
believe it is likely that a very small amount of these obligations will be
settled within the next five years.
Other
We lease acreage that is generally subject to lease expiration if operations are
not commenced within a specified period, generally 5 years and approximately 53%
of our leases in the Utica Core Area have a 5-year extension at our option.
Based on our evaluation of prospective economics, including the cost of
infrastructure to connect production, we have allowed acreage to expire and will
allow additional acreage to expire in the future. To date, our expenditures to
comply with environmental or safety regulations have not been a significant
component of our cost structure and are not expected to be significant in the
future. However, new regulations, enforcement policies, claims for damages or
other events could result in significant future costs.
Interest Rates
At December 31, 2015, we had $550.0 million as compared to $422.5 million as of
December 31, 2014, of senior unsecured notes outstanding, excluding discounts,
which bore interest at a fixed cash interest rate of 8.875% and was due
semi-annually from the date of issuance.
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In February 2014, we entered into a $500 million senior secured revolving bank
credit facility, which was amended and restated on January 12, 2015, and further
amended and restated on June 11, 2015 and February 24, 2016 and matures in 2018.
Borrowings under our Revolving Credit Facility are subject to borrowing base
limitations based on the collateral value of our proved properties and commodity
hedge positions and are subject semiannual redeterminations. At December 31,
2014, the borrowing base was $100 million and we had no outstanding borrowings.
In March 2015, the borrowing base was redetermined, which increased the
borrowing base to $125 million. The redeterminations completed in November 2015
and February 2016 resulted in no change to the borrowing base of $125 million.
After giving effect to our outstanding letters of credit, totaling $27.8
million, we had available borrowing capacity under our Revolving Credit Facility
of $97.2 million at December 31, 2015. The next borrowing base redetermination
is expected to be completed by October 2016.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance our liquidity or capital resource position,
or for any other purpose. However, as is customary in the oil and gas industry,
we have various contractual work commitments which are described above under
"-Cash Contractual Obligations.
Inflation and Changes in Prices
Our revenues, the value of our assets and our ability to obtain bank loans or
additional capital on attractive terms have been and will continue to be
affected by changes in natural gas, NGLs and oil prices and the costs to produce
our reserves. Natural gas, NGLs and oil prices are subject to significant
fluctuations that are beyond our ability to control or predict. Although certain
of our costs and expenses are affected by general inflation, it does not
normally have a significant effect on our business. We expect costs in fiscal
2015 to continue to be a function of supply and demand.
Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations
are based upon consolidated financial statements, which have been prepared in
accordance with GAAP. The preparation of our financial statements requires us to
make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at year end,
the reported amounts of revenues and expenses during the year and proved natural
gas and oil reserves. Some accounting policies involve judgments and
uncertainties to such an extent there is a reasonable likelihood that materially
different amounts could have been reported under different conditions, or if
different assumptions had been used. We evaluate our estimates and assumptions
on a regular basis. We base our estimates on historical experience and various
other assumptions that we believe are reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying value of
assets and liabilities that are not readily apparent from other sources. Actual
results could differ from the estimates and assumptions used.
Certain accounting estimates are considered to be critical if (a) the nature of
the estimates and assumptions is material due to the level of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility
of such matters to changes; and (b) the impact of the estimates and assumptions
on financial condition or operating performance is material.
Natural Gas and Oil Properties
We follow the successful efforts method of accounting for natural gas and oil
producing activities. Unsuccessful exploration drilling costs are expensed and
can have a significant effect on reported operating results. Successful
exploration drilling costs and all development costs are capitalized and
systematically charged to expense using the units of production method based on
proved developed natural gas and oil reserves as estimated by our engineers and
audited by independent engineers. Costs incurred for exploratory wells that find
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reserves that cannot yet be classified as proved are capitalized on our balance
sheet if (a) the well has found a sufficient quantity of reserves to justify its
completion as a producing well; and (b) we are making sufficient progress
assessing the reserves and the economic and operating viability of the project.
Proven property leasehold costs are amortized to expense using the units of
production method based on total proved reserves. Properties are assessed for
impairment as circumstances warrant (at least annually) and impairments to value
are charged to expense. The successful efforts method inherently relies upon the
estimation of proved reserves, which includes proved developed and proved
undeveloped volumes.
Proved reserves are defined by the SEC as those volumes of natural gas, NGLs,
condensate and crude oil that geological and engineering data demonstrate with
reasonable certainty are economically recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
reserves are volumes expected to be recovered through existing wells with
existing equipment and operating methods, or in which the cost of the required
equipment is relatively minor compared to the cost of a new well. Although our
engineers are knowledgeable of and follow the guidelines for reserves
established by the SEC, including the rule revisions designed to modernize the
oil and gas company reserves reporting requirements which were adopted effective
December 31, 2009, the estimation of reserves requires engineers to make a
significant number of assumptions based on professional judgment. Reserve
estimates are updated at least annually and consider recent production levels
and other technical information. Estimated reserves are often subject to future
revisions, which could be substantial, based on the availability of additional
information, including: reservoir performance, new geological and geophysical
data, additional drilling, technological advancements, price and cost changes
and other economic factors. Changes in natural gas, NGLs and oil prices can lead
to a decision to start-up or shut-in production, which can lead to revisions to
reserve quantities. Reserve revisions in turn cause adjustments in our depletion
rates. We cannot predict what reserve revisions may be required in future
periods. Reserve estimates are reviewed and approved by our Vice President,
Reservoir Engineering who reports directly to our Chief Financial Officer. To
further ensure the reliability of our reserve estimates, we engage independent
petroleum engineers to prepare our estimates of proved reserves at least
annually. NSAI, our independent petroleum engineers, prepared 100% of our
reserves in 2015, 2014, 2013 and 2012. For additional discussion, see "Item 1.
Business-Proved Reserves."
Depletion rates are determined based on reserve quantity estimates and the
capitalized costs of producing properties. As the estimated reserves are
adjusted, the depletion expense for a property will change, assuming no change
in production volumes or the capitalized costs. While total depletion expense
for the life of a property is limited to the property's total cost, proved
reserve revisions result in a change in the timing of when depletion expense is
recognized. Downward revisions of proved reserves may result in an acceleration
of depletion expense, while upward revisions tend to lower the rate of depletion
expense recognition. Estimated reserves are used as the basis for calculating
the expected future cash flows from property asset groups, which are used to
determine whether that property may be impaired. Reserves are also used to
estimate the supplemental disclosure of the standardized measure of discounted
future net cash flows relating to natural gas and oil producing activities and
reserve quantities in Note 19-Supplemental Oil and Gas Information to our
consolidated financial statements. Changes in the estimated reserves are
considered a change in estimate for accounting purposes and are reflected on a
prospective basis.
We monitor our long-lived assets recorded in natural gas and oil properties in
our consolidated balance sheets to ensure they are fairly presented. We must
evaluate our properties for potential impairment when circumstances indicate
that the carrying value of an asset could exceed its fair value. A significant
amount of judgment is involved in performing these evaluations since the results
are based on estimated future events. Such events include a projection of future
natural gas, NGLs and oil prices, an estimate of the ultimate amount of
recoverable natural gas, NGLs and oil reserves that will be produced from the
property asset groups future production, future production costs, future
abandonment costs, and future inflation. The need to test a property asset group
for impairment can be based on several factors, including a significant
reduction in sales prices for natural gas, NGLs and/or oil, unfavorable
adjustments to reserves, physical damage to production equipment and facilities,
a change in costs, or other changes to contracts or environmental regulations.
Our natural gas and oil
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properties are reviewed for potential impairments at the lowest levels for which
there are identifiable cash flows that are largely independent of other groups
of assets. All of these factors must be considered when testing a property asset
groups carrying value for impairment.
The review is done by determining if the historical cost of proved and unproved
properties less the applicable accumulated depreciation, depletion and
amortization is less than the estimated undiscounted future net cash flows. The
expected undiscounted future net cash flows are estimated based on our plans to
produce and develop reserves. Expected undiscounted future net cash inflows from
the sale of produced reserves are calculated based on estimated future prices
and estimated operating and development costs. We estimate prices based upon
market related information including published futures prices. The estimated
future level of production, which is based on proved and risk adjusted probable
reserves, has assumptions surrounding the future levels of prices and costs,
field decline rates, market demand and supply and the economic and regulatory
climates. In certain circumstances, we also consider potential sales of
properties to third parties in our estimates of undiscounted future cash flows.
When the carrying value exceeds the sum of undiscounted future net cash flows,
an impairment loss is recognized for the difference between the estimated fair
market value (as determined by discounted future net cash flows using a discount
rate similar to that used by market participants) and the carrying value of the
asset. We cannot predict whether impairment charges may be required in the
future.
We believe that a sensitivity analysis regarding the effect of changes in
assumptions on estimated impairment is impractical to provide because of the
number of assumptions and variables involved which have interdependent effects
on the potential outcome. If natural gas, NGLs and oil prices decrease or
drilling efforts are unsuccessful, we may be required to record additional
impairments.
We evaluate our unproved property investment periodically for impairment. The
majority of these costs generally relate to the acquisition of leaseholds. The
costs are capitalized and evaluated (at least quarterly) as to recoverability,
based on changes brought about by economic factors and potential shifts in
business strategy employed by management. Impairment of a significant portion of
our unproved properties is assessed and amortized on an aggregate basis based on
our average holding period, expected forfeiture rate and anticipated drilling
success. Potential impairment of individually significant unproved property is
assessed on a property-by-property basis considering a combination of time,
geologic and engineering factors.
Acquisitions
As part of our business strategy, we periodically pursue the acquisition of oil
and natural gas properties. The purchase price in an acquisition is allocated to
the assets acquired and liabilities assumed based on their relative fair values
as of the acquisition date, which may occur many months after the announcement
date. Therefore, while the consideration to be paid may be fixed, the fair value
of the assets acquired and liabilities assumed is subject to change during the
period between the announcement date and the acquisition date. Our most
significant estimates in our allocation typically relate to the value assigned
to future recoverable oil and natural gas reserves and unproved properties. As
the allocation of the purchase price is subject to significant estimates and
subjective judgments, the accuracy of this assessment is inherently uncertain.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and restore land at
the end of natural gas and oil production operations. Removal and restoration
obligations are primarily associated with plugging and abandoning wells.
Estimating the future asset removal costs is difficult and requires us to make
estimates and judgments because most of the removal 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 fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal,
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regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing asset
retirement obligation ("ARO"), a corresponding adjustment is made to the natural
gas and oil property balance. For example, as we analyze actual plugging and
abandonment in formation, we may revise our estimate of current costs, the
assumed annual inflation of the costs and/or the assumed productive lives of our
wells. In addition, increases in the discounted ARO liability resulting from the
passage of time are reflected as accretion expense, a component of depletion,
depreciation and amortization in the accompanying consolidated statements of
operations. Because of the subjectivity of assumptions and the relatively long
lives of most of our wells, the costs to ultimately retire our wells may vary
significantly from prior estimates.
Revenue Recognition
Natural gas, NGLs and oil sales are recognized when the products are sold and
delivery to the purchaser has occurred. We use the sales method to account for
gas imbalances, recognizing revenue based on gas delivered rather than our
working interest share of gas produced. We generally sell natural gas, NGLs and
oil under two types of agreements, which are common in our industry. Both types
of agreements include transportation charges. We report our gathering and
transportation costs in accordance with Financial Accounting Standards Board
("FASB") Section 605-45-05 of Subtopic 605-45 for Revenue Recognition.
Under one type of agreement, we sell natural gas, NGLs or oil at a specific
delivery point, pay transportation, gathering and compression to a third party
and receive proceeds from the purchaser with no deduction. In that case, we
record these costs as transportation, gatherings and compression expense. The
other type of agreement is a netback arrangement under which we sell natural gas
and oil at the wellhead and collect a price, net of transportation incurred by
the purchaser. In this case, we record revenue at the price we received from the
purchaser. In the case of NGLs, we receive a net price from the purchaser (which
is net of processing costs) which is recorded in revenue at the net price.
Regardless of agreement type, revenue is recorded in the month the product is
delivered to the purchaser as title has transferred.
To the extent we have not been paid for production related to a given reporting
period, we record an accrual for revenue based on our estimate of the amount of
production delivered to purchasers and the price we will receive, along with any
related transportation costs. We estimate volumes delivered based on production
information or from historical operating results of individual properties when
production information is not available, for example, for certain non-operated
properties. Prices for such production and related transportation costs are
defined in sales contracts and are readily determinable based on publicly
available indices. Given the information available to us, we do not believe
there to be any material implications with respect to uncertainties in
developing these estimates and historically, our actual receipts have not been
materially different from our accruals. The purchasers of such production have
historically made payment for oil, NGLs and natural gas purchases within 30-60
days of the end of each production month, at which time any variance between our
estimated revenue and transportation costs and actual payments is recorded.
Recent Accounting Pronouncements
Information related to recent accounting pronouncements is described in Note 3 to our consolidated financial statements and is incorporated herein by reference.
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