Item 2.
|
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 Annual Report on Form 10-K for the year ended December 31, 2016 and our condensed consolidated financial statements and related notes appearing elsewhere in this Quarterly 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. See “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
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 June 30, 2017, we had assembled an acreage position approximating 206,000 net acres in Eastern Ohio, which excludes any acreage currently pending title.
Approximately 99,000 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 15,000 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 Area. We are the operator of approximately 91% of our net acreage within the Utica Core Area and our Marcellus 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 June 30, 2017, we, or our operating partners, had commenced drilling 218 gross wells within the Utica Core Area and our Marcellus Area, of which 6 gross were top holed, 1 gross was drilling, 9 gross were awaiting completion or were in the process of being completed, 2 gross were awaiting midstream, and 200 gross had been turned to sales.
As of June 30, 2017, we were operating 2 horizontal rigs in the Utica Core Area. We had average daily production for the three months ended June 30, 2017 of approximately 287.8 MMcfe comprised of approximately 77% natural gas, 15% NGLs and 8% oil.
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 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.
26
Overview of Results for the
Three and Six Months Ended June 30, 2017
During the three months ended June 30, 2017, we achieved the following financial and operating results:
|
•
|
our average daily net production for the three months ended June 30, 2017 was 287.8 MMcfe per day representing an increase of 22% over the comparable period of the prior year;
|
|
•
|
commenced drilling 9 gross (8.6 net) operated Utica and Marcellus Shale wells, completed 6 gross (5.8 net) operated Utica Shale wells and turned-to-sales 9 gross (9.0 net) operated Utica Shale wells;
|
|
•
|
recognized net income of $11.5 million for the three months ended June 30, 2017 compared to a net loss of ($73.2) million for the three months ended June 30, 2016; and
|
|
•
|
realized Adjusted EBITDAX of $39.6 million for the three months ended June 30, 2017 compared to $16.9 million for three months ended June 30, 2016. Adjusted EBITDAX is a non-GAAP financial measure. See “
Non-GAAP Financial Measure”
for more information.
|
During the six months ended June 30, 2017, we achieved the following financial and operating results:
|
•
|
increased our average daily net production for the six months ended June 30, 2017 by 32% over the comparable period of the prior year, to 288.9 MMcfe per day;
|
|
•
|
completed the drilling of two of our 19,500 foot extended reach lateral wells in less than 17 days to total depth;
|
|
•
|
commenced drilling 13 gross (12.6 net) operated Utica and Marcellus Shale wells, completed 13 gross (12.8 net) operated Utica Shale wells and turned-to-sales 14 gross (13.7 net) operated Utica Shale wells;
|
|
•
|
recognized net income of $38.3 million for the six months ended June 30, 2017 compared to a net loss of ($118.7) million for the six months ended June 30, 2016; and
|
|
•
|
realized Adjusted EBITDAX of $89.8 million for the six months ended June 30, 2017 compared to $37.3 million for the six months ended June 30, 2016. Adjusted EBITDAX is a non-GAAP financial measure. See “
Non-GAAP Financial Measure”
for more information.
|
Market Conditions
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and NYMEX WTI prices for oil for the three and six months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
NYMEX Henry Hub High ($/MMBtu)
|
|
$
|
3.27
|
|
|
$
|
2.94
|
|
|
$
|
3.71
|
|
|
$
|
2.94
|
|
NYMEX Henry Hub Low ($/MMBtu)
|
|
|
2.85
|
|
|
|
1.71
|
|
|
|
2.44
|
|
|
|
1.49
|
|
Average Daily NYMEX Henry Hub ($/MMBtu)
|
|
|
3.08
|
|
|
|
2.16
|
|
|
|
3.05
|
|
|
|
2.09
|
|
Average Monthly NYMEX Settled Henry Hub ($/MMBtu)
|
|
|
3.18
|
|
|
|
1.95
|
|
|
|
3.25
|
|
|
|
2.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX WTI High ($/Bbl)
|
|
$
|
53.38
|
|
|
$
|
51.23
|
|
|
$
|
54.48
|
|
|
$
|
51.23
|
|
NYMEX WTI Low ($/Bbl)
|
|
|
42.48
|
|
|
|
34.30
|
|
|
|
42.48
|
|
|
|
26.19
|
|
Average NYMEX WTI ($/Bbl)
|
|
|
48.10
|
|
|
|
46.21
|
|
|
|
49.85
|
|
|
|
40.88
|
|
Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A 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.
27
The Company is committed to profitably developing its natural gas, NGLs and condensate reserves through an environmentally res
ponsible and cost-effective operational plan. The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves. Despite the continued low price co
mmodity environment, the Company believes the long-term outlook for its business is favorable due to the Company’s resource base, low cost structure, risk management strategies, and disciplined investment of capital.
It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process. However, to demonstrate the sensitivity of our estimates of natural gas, NGLs and oil reserves to changes in commodity prices, we provided an analysis in our Annual Report on Form 10-K for the year ended December 31, 2016. Further, if we recalculated our reserves using the unweighted arithmetic average first-day-of-the-month price for each of the twelve months in the period ended June 30, 2017 and held all other factors constant, then then our estimated net proved reserves at December 31, 2016 would have increased by approximately 130% from our previously reported estimated net proved reserves at such time, including a 14% addition of proved developed reserves and a 332% addition of proved undeveloped reserves. The foregoing estimate is based upon an average SEC price of $3.01 per MMBtu for natural gas and $48.95 per Bbl for NGLs and oil. This calculation only isolates the potential impact of commodity prices on our estimated proved reserves and does not account for other factors impacting our estimated proved reserves, such as anticipated drilling and completion costs and our production results since December 31, 2016. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. As such, this calculation is provided for illustrative purposes only and should not be construed as indicative of our final year-end reserve estimation process.
We consider future commodity prices when determining our development plan, but many other factors are also considered. 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 June 30, 2017, cash flows from operations, borrowings under our revolving credit facility, proceeds from asset sales, and proceeds from additional debt and/or equity offerings.
Results of Operations
Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to our operations for the three months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Revenues (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
59,890
|
|
|
$
|
23,888
|
|
|
$
|
36,002
|
|
NGL sales
|
|
|
11,151
|
|
|
|
9,331
|
|
|
|
1,820
|
|
Oil sales
|
|
|
15,153
|
|
|
|
12,682
|
|
|
|
2,471
|
|
Brokered natural gas and marketing revenue
|
|
|
(3
|
)
|
|
|
1,165
|
|
|
|
(1,168
|
)
|
Total revenues
|
|
$
|
86,191
|
|
|
$
|
47,066
|
|
|
$
|
39,125
|
|
28
Our production
grew
by approximately
4.7
Bcfe for the
three months ended June 30, 2017
over the same period in
2016
due to new wells that we placed into production
. Our production for the
three months ended June 30, 2017 and 20
16
is set forth in the following table:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
20,127.8
|
|
|
|
15,298.5
|
|
|
|
4,829.3
|
|
NGL sales (Mbbls)
|
|
|
662.1
|
|
|
|
685.9
|
|
|
|
(23.8
|
)
|
Oil sales (Mbbls)
|
|
|
347.8
|
|
|
|
345.2
|
|
|
|
2.6
|
|
Total (MMcfe)
|
|
|
26,187.2
|
|
|
|
21,485.1
|
|
|
|
4,702.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf/d)
|
|
|
221,185
|
|
|
|
168,115
|
|
|
|
53,070
|
|
NGL sales (Bbls/d)
|
|
|
7,276
|
|
|
|
7,537
|
|
|
|
(261
|
)
|
Oil sales (Bbls/d)
|
|
|
3,822
|
|
|
|
3,793
|
|
|
|
29
|
|
Total (Mcfe/d)
|
|
|
287,771
|
|
|
|
236,095
|
|
|
|
51,676
|
|
During the second quarter of 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that increased total net production by approximately 2.2 Bcfe, or 24 MMcfe per day, for the three months ended June 30, 2016.
29
Our average realized price (including cash derivative settlements and firm third-party transportation costs) received during the
three months ended June 30, 2017
was
$2.84
per Mcfe compared to
$2.42
per
Mcfe during the
three months ended June 30, 2016
. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation
expense. Our average realized price (including all derivative settlements and third-party firm transportation costs) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives) does not include
de
rivative settlements or third-
party transportation costs which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price (excluding cash settled derivatives)
does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the
three months ended June 30, 2017 and 2016
are shown below:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Average Sales Price (excluding cash settled derivatives
and firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.98
|
|
|
$
|
1.56
|
|
|
$
|
1.42
|
|
NGLs ($/Bbl)
|
|
|
16.84
|
|
|
|
13.60
|
|
|
|
3.24
|
|
Oil ($/Bbl)
|
|
|
43.57
|
|
|
|
36.74
|
|
|
|
6.83
|
|
Total average prices ($/Mcfe)
|
|
|
3.29
|
|
|
|
2.14
|
|
|
|
1.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including cash settled derivatives,
excluding firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.86
|
|
|
$
|
2.31
|
|
|
$
|
0.55
|
|
NGLs ($/Bbl)
|
|
|
16.38
|
|
|
|
13.43
|
|
|
|
2.95
|
|
Oil ($/Bbl)
|
|
|
43.57
|
|
|
|
41.38
|
|
|
|
2.19
|
|
Total average prices ($/Mcfe)
|
|
|
3.19
|
|
|
|
2.74
|
|
|
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including firm transportation,
excluding cash settled derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.52
|
|
|
$
|
1.12
|
|
|
$
|
1.40
|
|
NGLs ($/Bbl)
|
|
|
16.84
|
|
|
|
13.60
|
|
|
|
3.24
|
|
Oil ($/Bbl)
|
|
|
43.57
|
|
|
|
36.74
|
|
|
|
6.83
|
|
Total average prices ($/Mcfe)
|
|
|
2.94
|
|
|
|
1.82
|
|
|
|
1.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including cash settled derivatives
and firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.41
|
|
|
$
|
1.86
|
|
|
$
|
0.55
|
|
NGLs ($/Bbl)
|
|
|
16.38
|
|
|
|
13.43
|
|
|
|
2.95
|
|
Oil ($/Bbl)
|
|
|
43.57
|
|
|
|
41.38
|
|
|
|
2.19
|
|
Total average prices ($/Mcfe)
|
|
|
2.84
|
|
|
|
2.42
|
|
|
|
0.42
|
|
During the second quarter of 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that decreased natural gas realized prices by approximately $0.24 per Mcf and increased natural gas liquids prices by $0.61 per Bbl for the three months ended June 30, 2016.
Brokered natural gas and marketing revenue
was less than ($0.1) million and $1.2 million for the three months ended June 30, 2017 and 2016, respectively. 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. The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the three months ended June 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.
30
Costs and Expenses
We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the three months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Operating Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
4,568
|
|
|
$
|
2,248
|
|
|
$
|
2,320
|
|
Transportation, gathering and compression
|
|
|
28,969
|
|
|
|
28,254
|
|
|
|
715
|
|
Production and ad valorem taxes
|
|
|
2,033
|
|
|
|
2,203
|
|
|
|
(170
|
)
|
Depreciation, depletion and amortization
|
|
|
25,152
|
|
|
|
20,949
|
|
|
|
4,203
|
|
General and administrative
|
|
|
10,730
|
|
|
|
10,402
|
|
|
|
328
|
|
Operating Expenses per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
0.17
|
|
|
$
|
0.10
|
|
|
$
|
0.07
|
|
Transportation, gathering and compression
|
|
|
1.11
|
|
|
|
1.32
|
|
|
|
(0.21
|
)
|
Production and ad valorem taxes
|
|
|
0.08
|
|
|
|
0.10
|
|
|
|
(0.02
|
)
|
Depreciation, depletion and amortization
|
|
|
0.96
|
|
|
|
0.98
|
|
|
|
(0.02
|
)
|
General and administrative
|
|
|
0.41
|
|
|
|
0.48
|
|
|
|
(0.07
|
)
|
Lease operating
expense was $4.6 million in the three months ended June 30, 2017 compared to $2.2 million in the three months ended June 30, 2016. Lease operating expense per Mcfe was $0.17 in the three months ended June 30, 2017 compared to $0.10 in the three months ended June 30, 2016. The increase of $2.3 million and $0.07 per Mcfe is attributable to an increase in the number of producing wells and non-recurring workover expenses during the three months ended June 30, 2017, as compared to the three months ended June 30, 2016. Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.
Transportation, gathering and compression
expense was $29.0 million during the three months ended June 30, 2017 compared to $28.3 million in the three months ended June 30, 2016. Transportation, gathering and compression expense per Mcfe was $1.11 in the three months ended June 30, 2017 compared to $1.32 in the three months ended June 30, 2016. The following table details our transportation, gathering and compression expenses for the three months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Transportation, gathering and compression (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, compression and fuel
|
|
$
|
11,165
|
|
|
$
|
11,176
|
|
|
$
|
(11
|
)
|
Processing and fractionation
|
|
|
7,444
|
|
|
|
8,320
|
|
|
|
(876
|
)
|
Liquids transportation and stabilization
|
|
|
1,244
|
|
|
|
1,937
|
|
|
|
(693
|
)
|
Marketing
|
|
|
6
|
|
|
|
6
|
|
|
|
—
|
|
Firm transportation
|
|
|
9,110
|
|
|
|
6,815
|
|
|
|
2,295
|
|
|
|
$
|
28,969
|
|
|
$
|
28,254
|
|
|
$
|
715
|
|
Transportation, gathering and compression per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, compression and fuel
|
|
$
|
0.43
|
|
|
$
|
0.52
|
|
|
$
|
(0.09
|
)
|
Processing and fractionation
|
|
|
0.28
|
|
|
|
0.39
|
|
|
|
(0.11
|
)
|
Liquids transportation and stabilization
|
|
|
0.05
|
|
|
|
0.09
|
|
|
|
(0.04
|
)
|
Marketing
|
|
|
—
|
|
|
|
0.00
|
|
|
|
—
|
|
Firm transportation
|
|
|
0.35
|
|
|
|
0.32
|
|
|
|
0.03
|
|
|
|
$
|
1.11
|
|
|
$
|
1.32
|
|
|
$
|
(0.21
|
)
|
The increase to expenses in the three months ended June 30, 2017 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the fourth quarter of 2016. The decrease on a per unit basis was primarily related to increased production associated with natural gas and lower contractual rates.
31
Production and ad valorem taxes
are paid based on market prices and applicable tax rates. Production and ad valorem taxes were
$2.0
million in the
three months ended June 30, 2017
compared to
$2.2
million in the
three months ended June 30, 2016
.
Production and ad valorem taxes per Mcfe
was
$0.08
in the
three months ended June 30, 2017
compared to
$0.10
in the
three months ended June 30, 2016
.
The decrease in p
roduction and ad valorem taxes
on both a total and per unit basis
is due to the l
ower taxable value rate for the three months end
ed June 30, 2017
.
Depreciation, depletion and amortization
was approximately $25.2 million in the three months ended June 30, 2017 compared to $20.9 million in the three months ended June 30, 2016. The increase in the three months ended June 30, 2017 when compared to the three months ended June 30, 2016 is due to the increase in production for the three months ended June 30, 2017. On a per Mcfe basis, DD&A decreased to $0.96 in the three months ended June 30, 2017 from $0.98 in the three months ended June 30, 2016, which was predominantly driven by the lower depletion rate resulting from our increased reserves for the three months ended June 30, 2017.
General and administrative
expense was $10.7 million for the three months ended June 30, 2017 compared to $10.4 million for the three months ended June 30, 2016. General and administrative expense per Mcfe was $0.41 in the three months ended June 30, 2017 compared to $0.48 in the three months ended June 30, 2016. The increase of $0.3 million during the three months ended June 30, 2017 when compared to three months ended June 30, 2016 was primarily due to higher salaries and benefits associated with increased headcount for the three months ended June 30, 2017. The decrease of $0.07 per Mcfe is due to fixed costs being spread across higher production as of June 30, 2017 as compared to June 30, 2016.
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the three months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Other Operating Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Brokered natural gas and marketing expense
|
|
$
|
6
|
|
|
$
|
2,160
|
|
|
$
|
(2,154
|
)
|
Exploration
|
|
|
8,997
|
|
|
|
17,444
|
|
|
|
(8,447
|
)
|
Rig termination and standby
|
|
|
—
|
|
|
|
1,292
|
|
|
|
(1,292
|
)
|
Accretion of asset retirement obligations
|
|
|
128
|
|
|
|
89
|
|
|
|
39
|
|
(Gain) loss on sale of assets
|
|
|
6
|
|
|
|
(1,024
|
)
|
|
|
1,030
|
|
Brokered natural gas and marketing expense
was less than $0.1 million for the three months ended June 30, 2017 compared to $2.2 million for the three months ended June 30, 2016. Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties. The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the three months ended June 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.
Exploration
expense was $9.0 million for the three months ended June 30, 2017 compared to $17.4 million for the three months ended June 30, 2016. The following table details our exploration-related expenses for the three months ended June 30, 2017 and 2016:
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Exploration Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
364
|
|
|
$
|
395
|
|
|
$
|
(31
|
)
|
Delay rentals
|
|
|
4,429
|
|
|
|
7,178
|
|
|
|
(2,749
|
)
|
Impairment of unproved properties
|
|
|
4,125
|
|
|
|
9,360
|
|
|
|
(5,235
|
)
|
Dry hole and other
|
|
|
79
|
|
|
|
511
|
|
|
|
(432
|
)
|
|
|
$
|
8,997
|
|
|
$
|
17,444
|
|
|
$
|
(8,447
|
)
|
Delay rentals
were $4.4 million for the three months ended June 30, 2017 compared to $7.2 million for the three months ended June 30, 2016. The decrease in delay rental expenses relates to the reduction of converting future lump-sum extension payments into annual delay rentals during the current year period.
32
Impairment of unproved properties
was
$4.1
million for the
three months ended June 30, 2017
compared to
$9.4
million for the
three months ended June 30, 2016
.
The decrease in impairment charges during the three months ended June 30, 2017 is the result of a decrease in expected lease expirations due to the increase in our planned future drilling
activity.
As we continue to review our acreage positions and high g
rade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.
Rig termination and standby
expense for the three months ended June 30, 2016 were $1.3 million related primarily to standby costs that we incurred from temporarily suspending our drilling operations for a portion of such period. There were no rig termination and standby expenses for the three months ended June 30, 2017.
Accretion of asset retirement obligations
was $0.1 million for the three months ended June 30, 2017 compared to $0.1 million for three months ended June 30, 2016. The accretion expense primarily relates to the asset retirement obligations associated with the number of producing wells.
Other Income (Expense)
Gain (loss) on derivative instruments
was $18.2 million for the three months ended June 30, 2017 compared to ($29.6) million for the three months ended June 30, 2016, driven by changes in commodity prices during each year. Cash payments were approximately $2.6 million and cash receipts were approximately $12.9 million for derivative instruments that settled during the three months ended June 30, 2017 and June 30, 2016, respectively.
Interest expense, net
was $12.3 million for the three months ended June 30, 2017 compared to $12.4 million for three months ended June 30, 2016. Interest expense primarily relates to our senior unsecured notes and was relatively consistent during such periods.
Gain on early extinguishment of debt
was $5.8 million for the three months ended June 30, 2016 resulting from the repurchase of $21.0 million of our outstanding senior unsecured notes on the open market for $14.3 million with cash on hand. The outstanding senior unsecured notes principal repurchased less cash proceeds and unamortized debt discount and deferred financing costs of $0.8 million were charged to gain on early extinguishment of debt. No gain or loss on early extinguishment of debt was recognized for the three months ended June 30, 2017.
Income tax benefit (expense)
was not recognized for the three months ended June 30, 2017 and 2016 due to the Company reducing the valuation allowance to the extent of the tax effect of recorded pre-tax income and recording valuation allowance due to recurring pre-tax losses, respectively.
Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to our operations for the six months ended June 30, 2017 and 2016:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Revenues (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
121,310
|
|
|
$
|
51,929
|
|
|
$
|
69,381
|
|
NGL sales
|
|
|
28,213
|
|
|
|
15,853
|
|
|
|
12,360
|
|
Oil sales
|
|
|
36,102
|
|
|
|
18,607
|
|
|
|
17,495
|
|
Brokered natural gas and marketing revenue
|
|
|
2,428
|
|
|
|
10,283
|
|
|
|
(7,855
|
)
|
Total revenues
|
|
$
|
188,053
|
|
|
$
|
96,672
|
|
|
$
|
91,381
|
|
33
Our prod
uction grew by approximately
12.5
Bcfe for the
six months ended June 30, 2017
over the same period in 2016
as we placed new wells into production. Our production for the
six months ended June 30, 2017 and 2016
is set f
orth in the following table:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
39,509.4
|
|
|
|
28,985.8
|
|
|
|
10,523.6
|
|
NGL sales (Mbbls)
|
|
|
1,327.1
|
|
|
|
1,199.6
|
|
|
|
127.5
|
|
Oil sales (Mbbls)
|
|
|
801.9
|
|
|
|
600.5
|
|
|
|
201.4
|
|
Total (MMcfe)
|
|
|
52,283.4
|
|
|
|
39,786.4
|
|
|
|
12,497.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf/d)
|
|
|
218,284
|
|
|
|
159,263
|
|
|
|
59,021
|
|
NGL sales (Bbls/d)
|
|
|
7,332
|
|
|
|
6,591
|
|
|
|
741
|
|
Oil sales (Bbls/d)
|
|
|
4,430
|
|
|
|
3,299
|
|
|
|
1,131
|
|
Total (Mcfe/d)
|
|
|
288,859
|
|
|
|
218,603
|
|
|
|
70,256
|
|
During the six months ended June 30, 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that increased total net production by approximately 2.2 Bcfe, or 12 MMcfe per day, for such period.
34
Our average realized price (including cash derivative settlements and firm third-party transportation costs) received during the
six months ended June 30, 2017
was
$3.04
per Mcfe compared to
$2.63
per Mcfe during the
six months ended June 30, 2016
. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm trans
portation expense. Our average realized price (including all derivative settlements and third-party firm transportation costs) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives) does not
include
derivative settlements or third-
party transportation costs which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price (excluding cash settled der
ivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the
six months ended June 30, 2017 and 2016
are shown below:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Average Sales Price (excluding cash settled derivatives
and firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
3.07
|
|
|
$
|
1.79
|
|
|
$
|
1.28
|
|
NGLs ($/Bbl)
|
|
|
21.26
|
|
|
|
13.22
|
|
|
|
8.04
|
|
Oil ($/Bbl)
|
|
|
45.02
|
|
|
|
30.99
|
|
|
|
14.03
|
|
Total average prices ($/Mcfe)
|
|
|
3.55
|
|
|
|
2.17
|
|
|
|
1.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including cash settled derivatives,
excluding firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.94
|
|
|
$
|
2.60
|
|
|
$
|
0.34
|
|
NGLs ($/Bbl)
|
|
|
20.23
|
|
|
|
13.43
|
|
|
|
6.80
|
|
Oil ($/Bbl)
|
|
|
45.11
|
|
|
|
43.52
|
|
|
|
1.59
|
|
Total average prices ($/Mcfe)
|
|
|
3.42
|
|
|
|
2.96
|
|
|
|
0.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including firm transportation,
excluding cash settled derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.56
|
|
|
$
|
1.35
|
|
|
$
|
1.21
|
|
NGLs ($/Bbl)
|
|
|
21.26
|
|
|
|
13.22
|
|
|
|
8.04
|
|
Oil ($/Bbl)
|
|
|
45.02
|
|
|
|
30.99
|
|
|
|
14.03
|
|
Total average prices ($/Mcfe)
|
|
|
3.16
|
|
|
|
1.85
|
|
|
|
1.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price (including cash settled derivatives
and firm transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf)
|
|
$
|
2.43
|
|
|
$
|
2.16
|
|
|
$
|
0.27
|
|
NGLs ($/Bbl)
|
|
|
20.23
|
|
|
|
13.43
|
|
|
|
6.80
|
|
Oil ($/Bbl)
|
|
|
45.11
|
|
|
|
43.52
|
|
|
|
1.59
|
|
Total average prices ($/Mcfe)
|
|
|
3.04
|
|
|
|
2.63
|
|
|
|
0.41
|
|
During the six months ended June 30, 2016, the Company was affected by revisions of prior estimates related to one of its non-operated partners that decreased natural gas realized prices by approximately $0.13 per Mcf and increased NGL prices by $0.37 per Bbl for such period.
Brokered natural gas and marketing revenue
was $2.4 million and $10.3 million for the six months ended June 30, 2017 and 2016, respectively. 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. The decrease from the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during the six months ended June 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.
35
Costs and Expenses
We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the six months ended June 30, 2017 and 2016:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Operating Expenses (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
6,911
|
|
|
$
|
4,925
|
|
|
$
|
1,986
|
|
Transportation, gathering and compression
|
|
|
61,846
|
|
|
|
51,391
|
|
|
|
10,455
|
|
Production and ad valorem taxes
|
|
|
3,964
|
|
|
|
4,766
|
|
|
|
(802
|
)
|
Depreciation, depletion and amortization
|
|
|
51,341
|
|
|
|
36,062
|
|
|
|
15,279
|
|
General and administrative
|
|
|
20,862
|
|
|
|
21,676
|
|
|
|
(814
|
)
|
Operating Expenses per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
0.13
|
|
|
$
|
0.12
|
|
|
$
|
0.01
|
|
Transportation, gathering and compression
|
|
|
1.19
|
|
|
|
1.29
|
|
|
|
(0.10
|
)
|
Production and ad valorem taxes
|
|
|
0.08
|
|
|
|
0.12
|
|
|
|
(0.04
|
)
|
Depreciation, depletion and amortization
|
|
|
0.98
|
|
|
|
0.91
|
|
|
|
0.07
|
|
General and administrative
|
|
|
0.40
|
|
|
|
0.54
|
|
|
|
(0.14
|
)
|
Lease operating
expense was $6.9 million in the six months ended June 30, 2017 compared to $4.9 million in the six months ended June 30, 2016. Lease operating expense per Mcfe was $0.13 in the six months ended June 30, 2017 compared to $0.12 in the six months ended June 30, 2016. The increase of $2.0 million and $0.01 per Mcfe is attributable to an increase in the number of producing wells as well as workover expenses during the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. 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 $61.8 million during the six months ended June 30, 2017 compared to $51.4 million in the six months ended June 30, 2016. Transportation, gathering and compression expense per Mcfe was $1.19 in the six months ended June 30, 2017 compared to $1.29 in the six months ended June 30, 2016. The following table details our transportation, gathering and compression expenses for the six months ended June 30, 2017 and 2016:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Transportation, gathering and compression (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, compression and fuel
|
|
$
|
21,912
|
|
|
$
|
19,312
|
|
|
$
|
2,600
|
|
Processing and fractionation
|
|
|
15,761
|
|
|
|
15,862
|
|
|
|
(101
|
)
|
Liquids transportation and stabilization
|
|
|
4,006
|
|
|
|
3,338
|
|
|
|
668
|
|
Marketing
|
|
|
18
|
|
|
|
—
|
|
|
|
18
|
|
Firm transportation
|
|
|
20,149
|
|
|
|
12,879
|
|
|
|
7,270
|
|
|
|
$
|
61,846
|
|
|
$
|
51,391
|
|
|
$
|
10,455
|
|
Transportation, gathering and compression per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, compression and fuel
|
|
$
|
0.42
|
|
|
$
|
0.49
|
|
|
$
|
(0.07
|
)
|
Processing and fractionation
|
|
|
0.30
|
|
|
|
0.40
|
|
|
|
(0.10
|
)
|
Liquids transportation and stabilization
|
|
|
0.08
|
|
|
|
0.08
|
|
|
|
—
|
|
Marketing
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Firm transportation
|
|
|
0.39
|
|
|
|
0.32
|
|
|
|
0.07
|
|
|
|
$
|
1.19
|
|
|
$
|
1.29
|
|
|
$
|
(0.10
|
)
|
The increase to expenses in the six months ended June 30, 2017 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the fourth quarter of 2016. The decrease on a per unit basis was primarily related to our increased production and updated third party contracts.
36
Production and ad valorem taxes
are paid based on market prices and applicable tax rates. Productio
n and ad valorem t
axes were
$4.0
million in the
six months ended June 30, 2017
compared to
$4.8
million in the
six months ended June 30, 2016
.
Production and ad valorem taxes per Mcfe was
$0.08
in the
six months ended June 30, 2017
compared to
$0.12
in the
six months ended
June 30, 2016
.
The decrease in production and ad valorem taxes
on both a total and per unit basis
is due to the lower taxable valu
e rate for the six months ended June 30, 2017
.
Depreciation, depletion and amortization
was approximately $51.3 million in the six months ended June 30, 2017 compared to $36.1 million in the six months ended June 30, 2016. The increase in the six months ended June 30, 2017 when compared to the six months ended June 30, 2016 is due to the increase in production and proved property costs during the six months ended June 30, 2017. On a per Mcfe basis, DD&A increased to $0.98 in the six months ended June 30, 2017 from $0.91 in the six months ended June 30, 2016, which was predominantly driven by the higher depletion rate resulting from our increased proved property costs during the six months ended June 30, 2017.
General and administrative
expense was $20.9 million for the six months ended June 30, 2017 compared to $21.7 million for the six months ended June 30, 2016. General and administrative expense per Mcfe was $0.40 in the six months ended June 30, 2017 compared to $0.54 in the six months ended June 30, 2016. The decrease of $0.8 million and $0.14 per Mcfe during the six months ended June 30, 2017 when compared to six months ended June 30, 2016 was due to lower professional fees incurred and fixed costs spread across increased production as of June 30, 2017 as compared to June 30, 2016, respectively.
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the six months ended June 30, 2017 and 2016:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Other Operating Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Brokered natural gas and marketing expense
|
|
$
|
2,466
|
|
|
$
|
11,562
|
|
|
$
|
(9,096
|
)
|
Exploration
|
|
|
20,577
|
|
|
|
33,100
|
|
|
|
(12,523
|
)
|
Rig termination and standby
|
|
|
—
|
|
|
|
3,955
|
|
|
|
(3,955
|
)
|
Impairment of proved oil and natural gas properties
|
|
|
—
|
|
|
|
17,665
|
|
|
|
(17,665
|
)
|
Accretion of asset retirement obligations
|
|
|
252
|
|
|
|
175
|
|
|
|
77
|
|
(Gain) loss on sale of assets
|
|
|
1
|
|
|
|
(1,046
|
)
|
|
|
1,047
|
|
Brokered natural gas and marketing expense
was $2.5 million for the six months ended June 30, 2017 compared to $11.6 million for the six months ended June 30, 2016. Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties. The decrease from the prior year period to the current year period was due to increased utilization of our firm transport capacity for operated production during the six months ended June 30, 2017, which resulted in a decrease in the amount of firm transportation that was available for brokered gas transactions or release to third parties.
Exploration
expense was $20.6 million for the six months ended June 30, 2017 compared to $33.1 million for the six months ended June 30, 2016. The following table details our exploration-related expenses for the six months ended June 30, 2017 and 2016:
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Exploration Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
779
|
|
|
$
|
415
|
|
|
$
|
364
|
|
Delay rentals
|
|
|
10,606
|
|
|
|
13,417
|
|
|
|
(2,811
|
)
|
Impairment of unproved properties
|
|
|
8,250
|
|
|
|
18,720
|
|
|
|
(10,470
|
)
|
Dry hole and other
|
|
|
942
|
|
|
|
548
|
|
|
|
394
|
|
|
|
$
|
20,577
|
|
|
$
|
33,100
|
|
|
$
|
(12,523
|
)
|
Delay rentals
were $10.6 million for the six months ended June 30, 2017 compared to $13.4 million for the six months ended June 30, 2016. The decrease in delay rental expenses relates to the reduction of converting future lump-sum extension payments into annual delay rentals during the current year period.
37
Impairment of unproved properties
was
$8.3
million for the
six months ended June 30, 2017
compared to
$18.7
million for the
six months ended June 30, 2016
.
The decrease in impairment charges during the six months ended June 30, 2017 is the result of a decrease in expected lease expirations due to the increase in our planned future drilling activity.
As we continue to review our acreage positions and high grad
e our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.
Rig termination and standby
expense for the six months ended June 30, 2016 were $4.0 million related primarily to standby costs that we incurred from temporarily suspending our drilling operations for a portion of such period. There were no rig termination and standby expenses for the six months ended June 30, 2017.
Impairment of proved oil and gas properties
was $17.7 million for the six months ended June 30, 2016. There was no impairment of proved oil and gas properties recognized for the six months ended June 30, 2017.
Accretion of asset retirement obligations
was $0.3 million for the six months ended June 30, 2017 compared to $0.2 million for six months ended June 30, 2016. The accretion expense primarily relates to the asset retirement obligations associated with the number of producing wells.
Other Income (Expense)
Gain (loss) on derivative instruments
was $43.3 million for the six months ended June 30, 2017 compared to ($19.0) million for the six months ended June 30, 2016, driven by changes in commodity prices during each year. Cash payments were approximately $6.6 million and cash receipts were approximately $31.3 million for derivative instruments that settled during the six months ended June 30, 2017 and June 30, 2016, respectively.
Interest expense, net
was $24.7 million for the six months ended June 30, 2017 compared to $25.9 million for six months ended June 30, 2016. The decrease in interest expense was primarily due to the early extinguishment of debt during the first half of 2016.
Gain on early extinguishment of debt
was $14.5 million for the six months ended June 30, 2016 resulting from the repurchase of $39.5 million of our outstanding senior unsecured notes on the open market for $23.4 million during such period. The outstanding senior unsecured notes principal repurchased less cash proceeds and unamortized debt discount and deferred financing costs of $1.6 million were charged to gain on early extinguishment of debt. No gain or loss on early extinguishment of debt was recognized for the six months ended June 30, 2017.
Income tax benefit (expense)
was ($0.5) million for the six months ended June 30, 2016 related to the write-off of certain state deferred tax assets. No income tax expense was recorded for the six months ended June 30, 2017 due to the Company reducing the valuation allowance to the extent of the tax effect of recorded pre-tax income.
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, borrowings under our revolving credit facility and proceeds from issuances of debt and equity securities.
Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016
Net cash provided by (used in) operations
in the six months ended June 30, 2017 was $65.4 million compared to ($17.3) million in the six months ended June 30, 2016. The increase in cash provided from operating activities reflects the increase in commodity prices over year-over-year comparative periods, working capital changes, and the timing of cash receipts and disbursements.
Net cash used in investing activities
in the six months ended June 30, 2017 was $166.0 million compared to $29.2 million in the six months ended June 30, 2016.
38
During the
six months ended June 30, 2017
, we:
|
•
|
spent $166.0 million on capital expenditures for oil and natural gas properties;
|
|
•
|
spent $0.5 million on property and equipment; and
|
|
•
|
received $0.5 million of proceeds relating to the sale of assets.
|
During the six months ended June 30, 2016, we:
|
•
|
spent $42.9 million on capital expenditures for oil and gas properties;
|
|
•
|
spent $0.4 million on property and equipment; and
|
|
•
|
received $14.1 million of proceeds relating to the sale of assets.
|
Net cash used in financing activities
in the six months ended June 30, 2017 was $3.6 million compared to $23.9 million in the six months ended June 30, 2016.
During the six months ended June 30, 2017, we:
|
•
|
paid $1.3 million in financing costs associated with our amendment that increased our borrowing base capacity on our revolving credit facility;
|
|
•
|
paid $2.0 million to repurchase stock in relation to tax withholding for settlement of equity compensation awards.
|
During the six months ended June 30, 2016, we:
|
•
|
purchased outstanding senior unsecured notes with aggregate principal amount of $39.5 million for $23.4 million.
|
Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility 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 require 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 borrowings under our revolving credit facility will be adequate to meet our capital and operating requirements for 2017.
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 borrowings 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 June 30, 2017, we were in compliance with all of our debt covenants under the credit agreement governing our revolving credit facility and the indenture governing our 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 decrease 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 June 30, 2017 and December 31, 2016, excluding discount, totaled $510.5 million. (See Note 7—
Debt
).
39
On July 6, 2015, we issued $550 million in aggregate principal amount of 8.875% senior
unsecured
notes due
2023 at an issue price of 97.903%
of the principal amount of the n
otes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers.
In this private offering, the senior unsecured n
otes were sold for cash to qual
ified 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 millio
n, 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
use
d
the re
maining net proceeds to fund our capital expenditure plan and for general corporate purposes. (See Note 7—
Debt
).
During the six months ended June 30, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The outstanding principal of the senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs of $1.6 million were charged to gain on early extinguishment of debt, totaling $14.5 million.
The indenture governing our senior unsecured notes 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 senior unsecured 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 senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. We were in compliance with all applicable covenants in the indenture at June 30, 2017.
We have also entered into a $500 million revolving credit facility, which is governed by a Credit Agreement that includes customary affirmative and negative covenants. In February 2017, we entered into an amendment to our revolving credit facility that increased the borrowing base under such facility from $125 million to $175 million and extended the maturity date from January 2018 to February 2020. As of June 30, 2017, the borrowing base was $175 million and we had no outstanding borrowings. After giving effect to our outstanding letters of credit, totaling $33.6 million, we had available borrowing capacity under the revolving credit facility of $141.4 million. In August 2017, the borrowing base was redetermined, which increased the borrowing base from $175 million to $225 million. The Company’s available borrowing capacity under the revolving credit facility is now $191.4 million. Our next scheduled borrowing base redetermination is expected to be completed by April 2018. We were in compliance with all applicable covenants in the Credit Agreement at June 30, 2017.
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 and the WTI price for oil.
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 June 30, 2017, we had entered into the following derivative contracts:
40
Natural Gas Derivatives
Description
|
|
Volume
(MMBtu/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/MMBtu)
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
|
July 2017 – December 2017
|
|
$
|
2.98
|
|
|
|
|
10,000
|
|
|
July 2017 – December 2017
|
|
$
|
3.21
|
|
|
|
|
30,000
|
|
|
October 2017 – March 2018
|
|
$
|
3.46
|
|
Natural Gas Three-way Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
160,000
|
|
|
July 2017 – December 2017
|
|
$
|
2.83
|
|
Ceiling sold price (call)
|
|
|
160,000
|
|
|
July 2017 – December 2017
|
|
$
|
3.37
|
|
Floor sold price (put)
|
|
|
160,000
|
|
|
July 2017 – December 2017
|
|
$
|
2.31
|
|
Floor purchase price (put)
|
|
|
30,000
|
|
|
July 2017 – March 2019
|
|
$
|
3.00
|
|
Ceiling sold price (call)
|
|
|
30,000
|
|
|
July 2017 – March 2019
|
|
$
|
3.40
|
|
Floor sold price (put)
|
|
|
20,000
|
|
|
July 2017 – March 2019
|
|
$
|
2.40
|
|
Floor sold price (put)
|
|
|
10,000
|
|
|
July 2017 – March 2019
|
|
$
|
2.20
|
|
Floor purchase price (put)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
3.50
|
|
Floor sold price (put)
|
|
|
20,000
|
|
|
October 2017 – December 2018
|
|
$
|
2.20
|
|
Floor purchase price (put)
|
|
|
60,000
|
|
|
January 2018 – March 2018
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
60,000
|
|
|
January 2018 – March 2018
|
|
$
|
3.75
|
|
Floor sold price (put)
|
|
|
60,000
|
|
|
January 2018 – March 2018
|
|
$
|
2.40
|
|
Floor purchase price (put)
|
|
|
60,000
|
|
|
April 2018 – December 2018
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
60,000
|
|
|
April 2018 – December 2018
|
|
$
|
3.25
|
|
Floor sold price (put)
|
|
|
60,000
|
|
|
April 2018 – December 2018
|
|
$
|
2.40
|
|
Floor purchase price (put)
|
|
|
60,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.80
|
|
Ceiling sold price (call)
|
|
|
60,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.35
|
|
Floor sold price (put)
|
|
|
60,000
|
|
|
January 2018 – December 2018
|
|
$
|
2.33
|
|
Floor purchase price (put)
|
|
|
20,000
|
|
|
July 2017 – December 2018
|
|
$
|
2.90
|
|
Ceiling sold price (call)
|
|
|
20,000
|
|
|
July 2017 – December 2018
|
|
$
|
3.25
|
|
Floor sold price (put)
|
|
|
20,000
|
|
|
July 2017 – December 2018
|
|
$
|
2.40
|
|
Natural Gas Call/Put Options:
|
|
|
|
|
|
|
|
|
|
|
Call sold
|
|
|
40,000
|
|
|
January 2018 – December 2018
|
|
$
|
3.75
|
|
Call sold
|
|
|
10,000
|
|
|
January 2019 – December 2019
|
|
$
|
4.75
|
|
Basis Swaps:
|
|
|
|
|
|
|
|
|
|
|
TCO - Columbia
|
|
|
20,000
|
|
|
July 2017 – December 2017
|
|
$
|
(0.19
|
)
|
Appalachia - Dominion
|
|
|
40,000
|
|
|
July 2017 – November 2017
|
|
$
|
(1.01
|
)
|
Appalachia - Dominion
|
|
|
40,000
|
|
|
July 2017 – November 2017
|
|
$
|
(1.04
|
)
|
Oil Derivatives
Description
|
|
Volume
(Bbls/d)
|
|
|
Production Period
|
|
Weighted
Average
Price
($/Bbl)
|
|
Oil Three-way Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
July 2017 – September 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
July 2017 – September 2017
|
|
$
|
59.50
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
July 2017 – September 2017
|
|
$
|
38.00
|
|
Floor purchase price (put)
|
|
|
2,000
|
|
|
July 2017 – December 2017
|
|
$
|
46.00
|
|
Ceiling sold price (call)
|
|
|
2,000
|
|
|
July 2017 – December 2017
|
|
$
|
60.00
|
|
Floor sold price (put)
|
|
|
2,000
|
|
|
July 2017 – December 2017
|
|
$
|
38.00
|
|
41
NGL Derivatives
Description
|
|
Volume
(Gal/d)
|
|
|
Production Period
|
|
Weighted Average
Price ($/Gal)
|
|
Propane Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,000
|
|
|
July 2017 – December 2017
|
|
$
|
0.60
|
|
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, Goldman Sachs, Morgan Stanley and Key Bank N.A. We believe all of such institutions currently are an acceptable credit risk. As of June 30, 2017, we did not have any past due receivables from such counterparties.
A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at June 30, 2017. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $21.3 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $23.9 million. A hypothetical 10 percent decrease in future oil prices would increase future earnings related to derivatives by $1.3 million. Similarly, a hypothetical 10 percent increase in future oil prices would decrease future earnings related to derivatives by $0.8 million.
Subsequent to June 30, 2017, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:
Description
|
|
Volume
(Bbls/d)
|
|
|
Production
Period
|
|
Weighted Average
Price ($/Bbl)
|
|
Oil Three-way Collars:
|
|
|
|
|
|
|
|
|
|
|
Floor purchase price (put)
|
|
|
4,000
|
|
|
January 2018 – December 2018
|
|
$
|
45.00
|
|
Ceiling sold price (call)
|
|
|
4,000
|
|
|
January 2018 – December 2018
|
|
$
|
52.26
|
|
Floor sold price (put)
|
|
|
4,000
|
|
|
January 2018 – December 2018
|
|
$
|
35.00
|
|
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. Our board of directors approved an initial capital budget for 2017 of approximately $300 million. The budget includes approximately $261 million for drilling and completions activities, $33 million for land activities and $6 million for other capital requirements. In addition to these amounts, we expect to spend approximately $17 million during 2017 related to leases that were signed during 2016. The 2017 Capital Budget is expected to be substantially funded through internally generated cash flows and the Company’s current cash balance. 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.
42
Capitalization
As of June 30, 2017 and December 31, 2016, our total debt, excluding debt discount, and capitalization were as follows (in millions):
|
|
June 30, 2017
|
|
|
December 31, 2016
|
|
Senior unsecured notes
|
|
$
|
510.5
|
|
|
$
|
510.5
|
|
Stockholders' equity
|
|
|
597.3
|
|
|
|
556.6
|
|
Total capitalization
|
|
$
|
1,107.8
|
|
|
$
|
1,067.1
|
|
Cash Contractual Obligations
Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compressions services and asset retirement obligations. As of June 30, 2017 and December 31, 2016, we did 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. Our condensed consolidated balance sheet at June 30, 2017 reflects accrued interest payable of $21.2 million, compared to $21.1 million as of December 31, 2016.
Other
We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally five years. However, 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 June 30, 2017 and December 31, 2016, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bear interest at a fixed cash rate of 8.875% and is due semi-annually from the date of issuance.
In February 2014, we entered into a $500 million senior secured revolving bank credit facility. 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 to semiannual redeterminations. In February 2017, we entered into an amendment to our revolving credit facility that increased the borrowing base under such facility from $125 million to $175 million and extended the maturity date of such facility from January 2018 to February 2020. As of June 30, 2017, the borrowing base was $175 million and we had no outstanding borrowings. After giving effect to our outstanding letters of credit, totaling $33.6 million, we had available borrowing capacity under the revolving credit facility of $141.4 million. In August 2017, the borrowing base was redetermined, which increased the borrowing base from $175 million to $225 million. The Company’s available borrowing capacity under the revolving credit facility is now $191.4 million. Our next scheduled borrowing base redetermination is expected to be completed by April 2018.
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 our costs in fiscal 2017 to continue to be a function of supply and demand. Further strengthening of commodity prices could stimulate demand for ancillary services causing services costs to increase. In the near term, the majority of our service costs are expected to remain flat in 2017 due to previously negotiated drilling, stimulation, and rentals contracts. Along with these contracts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficacies.
43
Non-GAAP Financial Measure
“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; 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 set forth in the table below. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
|
•
|
is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
|
|
•
|
helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
|
|
•
|
is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under the Credit Agreement governing the revolving credit facility and the indenture governing the senior unsecured notes.
|
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
$ thousands
|
|
2017
|
|
|
2016
|
|
|
|
2017
|
|
|
2016
|
|
Net income (loss)
|
|
$
|
11,494
|
|
|
$
|
(73,163
|
)
|
|
$
|
38,341
|
|
|
$
|
(118,697
|
)
|
Depreciation, depletion and amortization
|
|
|
25,152
|
|
|
|
20,949
|
|
|
|
51,341
|
|
|
|
36,062
|
|
Exploration expense
|
|
|
8,997
|
|
|
|
17,444
|
|
|
|
20,577
|
|
|
|
33,100
|
|
Rig termination and standby
|
|
|
—
|
|
|
|
1,292
|
|
|
|
—
|
|
|
|
3,955
|
|
Impairment of proved oil and gas properties
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
17,665
|
|
Stock-based compensation
|
|
|
2,348
|
|
|
|
2,226
|
|
|
|
4,429
|
|
|
|
3,701
|
|
Accretion of asset retirement obligations
|
|
|
128
|
|
|
|
89
|
|
|
|
252
|
|
|
|
175
|
|
(Gain) loss on derivative instruments
|
|
|
(18,177
|
)
|
|
|
29,596
|
|
|
|
(43,274
|
)
|
|
|
19,046
|
|
Net cash receipts (payments) on settled derivatives
|
|
|
(2,644
|
)
|
|
|
12,880
|
|
|
|
(6,633
|
)
|
|
|
31,258
|
|
Interest expense, net
|
|
|
12,285
|
|
|
|
12,439
|
|
|
|
24,747
|
|
|
|
25,900
|
|
(Gain) loss on sale of assets
|
|
|
6
|
|
|
|
(1,024
|
)
|
|
|
1
|
|
|
|
(1,046
|
)
|
(Gain) loss on early extinguishment of debt
|
|
|
—
|
|
|
|
(5,825
|
)
|
|
|
—
|
|
|
|
(14,489
|
)
|
Other (income) expense
|
|
|
—
|
|
|
|
2
|
|
|
|
19
|
|
|
|
141
|
|
Income tax (benefit) expense
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
540
|
|
Adjusted EBITDAX
|
|
$
|
39,589
|
|
|
$
|
16,905
|
|
|
$
|
89,800
|
|
|
$
|
37,311
|
|
Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for further discussion of our critical accounting policies.
44
Recent Accounting Pronouncements
The Company’s critical accounting policies are described in Note 3 –
Summary of Significant Accounting Policies
of the consolidated financial statements for the year ended December 31, 2016 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in Note 3 to our condensed consolidated financial statements and is incorporated herein by reference.