The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the “Explanatory Note”, financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K/A for the year ended December 31, 2016.
In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. Certain amounts in the prior year financial statements have been reclassified to conform to the 2017 financial statement presentation.
Use of Estimates
Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies.
Oil and Gas Well Equipment and Supplies
Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. An analysis of our oil and gas well equipment and supplies was performed as of June 30, 2017, and no impairment was required. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.
Oil and Gas Properties
We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
At June 30, 2017 and March 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the six months ended June 30, 2017. During the three and six months ended June 30, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $652.1 million ($414.3 million, net of tax), respectively. These impairments resulted primarily from decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation is not intended to be indicative of the fair market
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
S
OVERVIEW
Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, Texas, and New Mexico. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent region. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.
Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders through a balanced and abundant drilling inventory. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development activities. We consider property acquisitions, dispositions, and occasional mergers to enhance our competitive position.
We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position us to achieve profitable increases in proved reserves and production. Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility.
Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and occasional public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand fluctuations in commodity prices.
Market Conditions
The oil and gas industry is cyclical and commodity prices can be volatile. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, inventory storage levels, weather conditions, and other factors.
Oil prices have improved from early 2016; however, they continue to be unstable due to growing U.S. supply, large inventory balances, and concern over demand. Further, local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. The Permian Basin and Mid-Continent region natural gas production growth has resulted in higher differentials and if pipeline constraints remain, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and natural gas production. See
Revenues
below for further information regarding our realized commodity prices.
The U.S. oil and gas industry continues to confront weak commodity prices, which has had adverse effects on our business and financial position. Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, oversupply and high oil and natural gas inventory storage levels could put downward pressure on commodity prices and have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.
See “
Risk Factors
” in Item 1A of our Annual Report on Form 10-K/A for the year ended December 31, 2016, for a discussion of risk factors that affect our business, financial condition, and results of operations. Also see
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
in this report for important information about these types of statements.
Summary of Operating and Financial Results for the Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016:
|
·
|
|
Production increased 14% to 1,110.0 MMcfe per day.
|
|
·
|
|
Oil volumes increased 22% to 55,042 barrels per day, gas volumes increased 7% to 502.0 MMcf per day, and NGL volumes increased 18% to 46,281 barrels per day.
|
|
·
|
|
Production revenues rose 68% to $882.3 million.
|
|
·
|
|
Cash flow provided by operating activities increased 132% to $504.8 million.
|
|
·
|
|
Net income was $228.2 million, or $2.40 per diluted share, for the first six months of 2017, as compared to a net loss of $445.9 million, or $(4.79) per diluted share, for the first six months of 2016.
|
|
·
|
|
In response to improved commodity prices, we increased our exploration and development expenditures to $491.0 million for the first six months of 2017, as compared to $285.7 million for the first six months of 2016.
|
|
·
|
|
Total debt at both June 30, 2017 and 2016 consisted of $1.5 billion of senior notes. During the second quarter 2017, we repaid our $750 million notes due 2022 and issued $750 million notes due 2027. Our other $750 million notes are due 2024.
|
RESULTS OF OPERATIONS
Three and Six Months Ended June 30, 2017 vs. Three and Six Months Ended June 30, 2016
Revenues
Almost all our revenues are derived from sales of our oil, natural gas, and NGL production. Increases or decreases in our revenue, profitability, and future production growth are highly dependent on the commodity prices we receive. Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors.
Both commodity prices and production volumes have increased during the three and six months ended June 30, 2017 as compared to the three and six months ended June 30, 2016, contributing to the increase in revenue seen in the 2017 periods. The following tables show our production revenues for the periods as well as the change in revenues due to changes in volumes and prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Change
|
|
|
|
|
|
|
|
|
|
Production Revenue
|
June 30,
|
|
Between
|
|
Price/Volume Change
|
(in thousands)
|
2017
|
|
2016
|
|
2017 / 2016
|
|
Price
|
|
Volume
|
|
Total
|
Oil sales
|
$
|
232,453
|
|
$
|
162,005
|
|
43
|
%
|
|
$
|
21,433
|
|
$
|
49,015
|
|
$
|
70,448
|
Gas sales
|
|
132,474
|
|
|
76,615
|
|
73
|
%
|
|
|
47,021
|
|
|
8,838
|
|
|
55,859
|
NGL sales
|
|
80,886
|
|
|
51,939
|
|
56
|
%
|
|
|
19,111
|
|
|
9,836
|
|
|
28,947
|
|
$
|
445,813
|
|
$
|
290,559
|
|
53
|
%
|
|
$
|
87,565
|
|
$
|
67,689
|
|
$
|
155,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
Change
|
|
|
|
|
|
|
|
|
|
Production Revenue
|
|
June 30,
|
Between
|
|
Price/Volume Change
|
(in thousands)
|
2017
|
|
2016
|
|
2017 / 2016
|
|
Price
|
|
Volume
|
|
Total
|
Oil sales
|
$
|
456,519
|
|
$
|
279,578
|
|
63
|
%
|
|
$
|
118,360
|
|
$
|
58,581
|
|
$
|
176,941
|
Gas sales
|
|
264,419
|
|
|
159,223
|
|
66
|
%
|
|
|
94,506
|
|
|
10,690
|
|
|
105,196
|
NGL sales
|
|
161,312
|
|
|
85,291
|
|
89
|
%
|
|
|
60,985
|
|
|
15,036
|
|
|
76,021
|
|
$
|
882,250
|
|
$
|
524,092
|
|
68
|
%
|
|
$
|
273,851
|
|
$
|
84,307
|
|
$
|
358,158
|
For the three and six months ended June 30, 2017, oil sales, gas sales, and NGL sales accounted for 52%, 30%, and 18% of our total production revenue, respectively. For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized oil price would have resulted in a ±$5.3 million and ±$10.0 million change in revenues, respectively. For the three and six months ended June 30, 2017, a ±$0.10 per Mcf change in our realized gas price would have resulted in a ±$4.7 million and ±$9.1 million change in revenues, respectively. For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized NGL price would have resulted in a ±$4.4 million and ±$8.4 million change in revenues, respectively.
The table below presents our regional production volumes.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Oil (Bbls per day)
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
45,828
|
|
35,338
|
|
43,446
|
|
35,944
|
Mid-Continent
|
|
11,893
|
|
8,933
|
|
11,475
|
|
9,093
|
Other
|
|
150
|
|
153
|
|
121
|
|
230
|
|
|
57,871
|
|
44,424
|
|
55,042
|
|
45,267
|
Gas (MMcf per day)
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
219.8
|
|
181.2
|
|
210.4
|
|
177.4
|
Mid-Continent
|
|
295.4
|
|
279.1
|
|
290.2
|
|
288.7
|
Other
|
|
1.5
|
|
1.6
|
|
1.4
|
|
1.3
|
|
|
516.7
|
|
461.9
|
|
502.0
|
|
467.4
|
NGL (Bbls per day)
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
24,996
|
|
19,219
|
|
23,319
|
|
16,639
|
Mid-Continent
|
|
23,693
|
|
21,716
|
|
22,926
|
|
22,432
|
Other
|
|
42
|
|
26
|
|
36
|
|
41
|
|
|
48,731
|
|
40,961
|
|
46,281
|
|
39,112
|
Total (MMcfe per day)
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
644.7
|
|
508.5
|
|
611.0
|
|
492.9
|
Mid-Continent
|
|
509.0
|
|
463.0
|
|
496.6
|
|
477.9
|
Other
|
|
2.6
|
|
2.7
|
|
2.4
|
|
2.9
|
|
|
1,156.3
|
|
974.2
|
|
1,110.0
|
|
973.7
|
During the three and six months ended June 30, 2017, approximately 55% of our total production was in the Permian Basin. This has increased from the three and six months ended June 30, 2016, when approximately 51% of our total production was in the Permian Basin. The increase is due to increased drilling and completion activity. During each of the periods presented, approximately 79% of our oil production was in the Permian Basin.
The table below presents our production volumes by commodity, average realized commodity prices, and certain major U.S. index prices. The sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. Our realized prices do not include settlements of commodity derivative contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Change
|
|
Six Months Ended
|
|
Change
|
|
|
June 30,
|
|
Between
|
|
June 30,
|
|
Between
|
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
|
2017 / 2016
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total volume — MBbls
|
|
|
5,266
|
|
|
4,043
|
|
30
|
%
|
|
|
9,963
|
|
|
8,239
|
|
21
|
%
|
Total volume — barrels per day
|
|
|
57,871
|
|
|
44,424
|
|
30
|
%
|
|
|
55,042
|
|
|
45,267
|
|
22
|
%
|
Percentage of total production
|
|
|
30
|
%
|
|
28
|
%
|
|
|
|
|
30
|
%
|
|
28
|
%
|
|
|
Average realized price — per barrel
|
|
$
|
44.14
|
|
$
|
40.07
|
|
10
|
%
|
|
$
|
45.82
|
|
$
|
33.94
|
|
35
|
%
|
Average WTI Midland price — per barrel
|
|
$
|
47.44
|
|
$
|
45.42
|
|
4
|
%
|
|
$
|
50.00
|
|
$
|
39.83
|
|
26
|
%
|
Average WTI Cushing price — per barrel
|
|
$
|
48.29
|
|
$
|
45.59
|
|
6
|
%
|
|
$
|
50.10
|
|
$
|
39.52
|
|
27
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total volume — MMcf
|
|
|
47,021
|
|
|
42,034
|
|
12
|
%
|
|
|
90,871
|
|
|
85,068
|
|
7
|
%
|
Total volume — MMcf per day
|
|
|
516.7
|
|
|
461.9
|
|
12
|
%
|
|
|
502.0
|
|
|
467.4
|
|
7
|
%
|
Percentage of total production
|
|
|
45
|
%
|
|
47
|
%
|
|
|
|
|
45
|
%
|
|
48
|
%
|
|
|
Average realized price — per Mcf
|
|
$
|
2.82
|
|
$
|
1.82
|
|
55
|
%
|
|
$
|
2.91
|
|
$
|
1.87
|
|
56
|
%
|
Average Henry Hub price — per Mcf
|
|
$
|
3.19
|
|
$
|
1.95
|
|
64
|
%
|
|
$
|
3.25
|
|
$
|
2.02
|
|
61
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total volume — MBbls
|
|
|
4,434
|
|
|
3,727
|
|
19
|
%
|
|
|
8,377
|
|
|
7,118
|
|
18
|
%
|
Total volume — barrels per day
|
|
|
48,731
|
|
|
40,961
|
|
19
|
%
|
|
|
46,281
|
|
|
39,112
|
|
18
|
%
|
Percentage of total production
|
|
|
25
|
%
|
|
25
|
%
|
|
|
|
|
25
|
%
|
|
24
|
%
|
|
|
Average realized price — per barrel
|
|
$
|
18.24
|
|
$
|
13.93
|
|
31
|
%
|
|
$
|
19.26
|
|
$
|
11.98
|
|
61
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production — MMcfe
|
|
|
105,225
|
|
|
88,654
|
|
19
|
%
|
|
|
200,907
|
|
|
177,210
|
|
13
|
%
|
Total production — MMcfe per day
|
|
|
1,156.3
|
|
|
974.2
|
|
19
|
%
|
|
|
1,110.0
|
|
|
973.7
|
|
14
|
%
|
Other revenues
We transport, process, and market some third-party gas that is associated with our equity gas. We market and sell natural gas for other working interest owners under short-term sales and supply agreements and may earn a fee for such services. The table below reflects income from third-party gas gathering and processing and our net marketing margin (revenues less purchases) for marketing third-party gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Gas Gathering and Marketing
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas gathering and other revenues
|
|
$
|
10,735
|
|
$
|
8,211
|
|
$
|
21,360
|
|
$
|
15,452
|
Gas marketing revenues, net of related costs
|
|
$
|
(96)
|
|
$
|
103
|
|
$
|
18
|
|
$
|
(71)
|
Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, and gathering rate charges.
Operating Costs and Expenses
Costs associated with producing oil and natural gas are substantial. Some of these costs vary with commodity prices, some trend with the volume of production, others are a function of the number of wells we own, and some depend on the prices charged by service companies.
Total operating costs and expenses for the three months ended June 30, 2017 were lower by 58% compared to the three months ended June 30, 2016. The primary reasons for the decrease are: (i) the $333.3 million ($211.8 million, net of tax) ceiling test impairment recorded in the 2016 period and (ii) increased net gains on derivative instruments in 2017, partially offset by (iii) increased transportation, processing, and other operating costs in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Operating Costs and Expenses
(in thousands, except per Mcfe)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of oil and gas properties
|
$
|
—
|
|
$
|
333,291
|
|
$
|
(333,291)
|
|
|
N/A
|
|
|
N/A
|
Depreciation, depletion, and amortization
|
|
107,884
|
|
|
102,086
|
|
|
5,798
|
|
$
|
1.03
|
|
$
|
1.15
|
Asset retirement obligation
|
|
960
|
|
|
1,750
|
|
|
(790)
|
|
$
|
0.01
|
|
$
|
0.02
|
Production
|
|
62,578
|
|
|
57,213
|
|
|
5,365
|
|
$
|
0.59
|
|
$
|
0.65
|
Transportation, processing, and other operating
|
|
58,624
|
|
|
44,436
|
|
|
14,188
|
|
$
|
0.56
|
|
$
|
0.50
|
Gas gathering and other
|
|
8,647
|
|
|
7,492
|
|
|
1,155
|
|
$
|
0.08
|
|
$
|
0.09
|
Taxes other than income
|
|
17,477
|
|
|
14,066
|
|
|
3,411
|
|
$
|
0.17
|
|
$
|
0.16
|
General and administrative
|
|
19,762
|
|
|
21,424
|
|
|
(1,662)
|
|
$
|
0.19
|
|
$
|
0.24
|
Stock compensation
|
|
6,293
|
|
|
7,490
|
|
|
(1,197)
|
|
$
|
0.06
|
|
$
|
0.08
|
(Gain) loss on derivative instruments, net
|
|
(22,509)
|
|
|
33,236
|
|
|
(55,745)
|
|
|
N/A
|
|
|
N/A
|
Other operating expense, net
|
|
266
|
|
|
24
|
|
|
242
|
|
|
N/A
|
|
|
N/A
|
|
$
|
259,982
|
|
$
|
622,508
|
|
$
|
(362,526)
|
|
|
|
|
|
|
Total operating costs and expenses for the six months ended June 30, 2017 were lower by 60% compared to the six months ended June 30, 2016. The primary reasons for the decrease are: (i) the $652.1 million ($414.3 million, net of tax) ceiling test impairment recorded in the 2016 period and (ii) increased net gains on derivative instruments in 2017, partially offset by (iii) increased transportation, processing, and other operating costs in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Operating Costs and Expenses
(in thousands, except per Mcfe)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of oil and gas properties
|
$
|
—
|
|
$
|
652,077
|
|
$
|
(652,077)
|
|
|
N/A
|
|
|
N/A
|
Depreciation, depletion, and amortization
|
|
203,700
|
|
|
212,722
|
|
|
(9,022)
|
|
$
|
1.01
|
|
$
|
1.20
|
Asset retirement obligation
|
|
2,580
|
|
|
4,048
|
|
|
(1,468)
|
|
$
|
0.01
|
|
$
|
0.02
|
Production
|
|
124,999
|
|
|
127,915
|
|
|
(2,916)
|
|
$
|
0.62
|
|
$
|
0.72
|
Transportation, processing and other operating
|
|
113,647
|
|
|
90,879
|
|
|
22,768
|
|
$
|
0.57
|
|
$
|
0.51
|
Gas gathering and other
|
|
17,074
|
|
|
15,572
|
|
|
1,502
|
|
$
|
0.08
|
|
$
|
0.09
|
Taxes other than income
|
|
38,790
|
|
|
27,905
|
|
|
10,885
|
|
$
|
0.19
|
|
$
|
0.16
|
General and administrative
|
|
37,796
|
|
|
35,321
|
|
|
2,475
|
|
$
|
0.19
|
|
$
|
0.20
|
Stock compensation
|
|
12,581
|
|
|
13,018
|
|
|
(437)
|
|
$
|
0.06
|
|
$
|
0.07
|
(Gain) loss on derivative instruments, net
|
|
(66,370)
|
|
|
32,808
|
|
|
(99,178)
|
|
|
N/A
|
|
|
N/A
|
Other operating expense, net
|
|
882
|
|
|
114
|
|
|
768
|
|
|
N/A
|
|
|
N/A
|
|
$
|
485,679
|
|
$
|
1,212,379
|
|
$
|
(726,700)
|
|
|
|
|
|
|
Ceiling Test Impairment
We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly ceiling test calculation to test our capitalized oil and gas property costs for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
At June 30, 2017 and March 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the six months ended June 30, 2017. At June 30, 2016 and March 31, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $318.8 million ($202.6 million, net of tax), respectively, for a total impairment of $652.1 million ($414.3 million, net of tax) recognized during the six months ended June 30, 2016. These impairments were primarily the result of decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. The commodity prices used in the June 30, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $3.01 per Mcf of gas and $48.95 per barrel of oil. A decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment at June 30, 2017. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects. Depending on fluctuations in these factors, including a decline in prices, we may incur full cost ceiling test impairments in future quarters.
The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.
Depreciation, Depletion, and Amortization
Depletion of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the estimated proved reserves for that well, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved, and impairments of oil and gas properties will also impact depletion expense. Depletion is calculated quarterly before the ceiling test impairment calculation.
Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years. Depreciation, depletion, and amortization (“DD&A”) consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
DD&A Expense
(in thousands, except per Mcfe)
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Depletion
|
|
$
|
95,735
|
|
$
|
90,577
|
|
$
|
5,158
|
|
$
|
0.91
|
|
$
|
1.02
|
Depreciation
|
|
|
12,149
|
|
|
11,509
|
|
|
640
|
|
|
0.12
|
|
|
0.13
|
|
|
$
|
107,884
|
|
$
|
102,086
|
|
$
|
5,798
|
|
$
|
1.03
|
|
$
|
1.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
DD&A Expense
(in thousands, except per Mcfe)
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Depletion
|
|
$
|
180,746
|
|
$
|
189,484
|
|
$
|
(8,738)
|
|
$
|
0.90
|
|
$
|
1.07
|
Depreciation
|
|
|
22,954
|
|
|
23,238
|
|
|
(284)
|
|
|
0.11
|
|
|
0.13
|
|
|
$
|
203,700
|
|
$
|
212,722
|
|
$
|
(9,022)
|
|
$
|
1.01
|
|
$
|
1.20
|
Production
Production expense generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating, and miscellaneous other costs (lease operating expense). Production expense also includes well workover activity necessary to maintain production from existing wells. Production expense consists of lease operating expense and workover expense as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
Production Expense
(in thousands, except per Mcfe)
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Lease operating expense
|
|
$
|
55,812
|
|
$
|
46,952
|
|
$
|
8,860
|
|
$
|
0.53
|
|
$
|
0.53
|
Workover expense
|
|
|
6,766
|
|
|
10,261
|
|
|
(3,495)
|
|
|
0.06
|
|
|
0.12
|
|
|
$
|
62,578
|
|
$
|
57,213
|
|
$
|
5,365
|
|
$
|
0.59
|
|
$
|
0.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
Variance
|
|
|
|
|
|
|
|
|
June 30,
|
|
Between
|
|
Per Mcfe
|
Production Expense
(in thousands, except per Mcfe)
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
Lease operating expense
|
|
$
|
101,347
|
|
$
|
102,646
|
|
$
|
(1,299)
|
|
$
|
0.50
|
|
$
|
0.58
|
Workover expense
|
|
|
23,652
|
|
|
25,269
|
|
|
(1,617)
|
|
|
0.12
|
|
|
0.14
|
|
|
$
|
124,999
|
|
$
|
127,915
|
|
$
|
(2,916)
|
|
$
|
0.62
|
|
$
|
0.72
|
Lease operating expense in the second quarter 2017 increased 19%, or $8.9 million, compared to the second quarter of 2016. The increase was primarily caused by: (i) increased labor costs due to increased salaries, bonuses, and number of employees, (ii) increased saltwater disposal costs due to increased trucked water related to new and recompleted wells and various issues (e.g., capacity and power) at third-party disposal wells, and (iii) increased gas lift compression and fuel costs. Higher lease operating expense in the second quarter 2017 combined with a 19% increase in production volumes during the quarter resulted in holding per unit lease operating expenses flat at $0.53 per Mcfe. Lease operating expense for the six months ended June 30, 2017 decreased 1%, or $1.3 million, compared to the six months ended June 30, 2016. In 2017, we have had less rental equipment expense including compressor rentals due to adding wells on central compression and, therefore, releasing rented wellhead compressors, downsizing some compressors, and converting some wells from gas lift compression to plunger lift. We have also reduced the usage of roustabout crews in some areas, which has decreased maintenance and equipment costs. These decreases in expense were mostly offset by increases in expense due to the same reasons discussed above for the quarterly period. Lower lease operating expense in the first six months of 2017 combined with a 14% increase in production volumes during the period resulted in a decrease in per unit lease operating expenses to $0.50 per Mcfe in the 2017 period from $0.58 per Mcfe in the 2016 period.
Workover expense during the three and six months ended June 30, 2017 decreased 34%, or $3.5 million, and 6%, or $1.6 million, respectively, compared to the three and six months ended June 30, 2016. During the 2017 periods, we had more workover projects underway than during the 2016 periods, which actually increased expense; however, these increases were offset by the receipt of partial insurance proceeds in the second quarter 2017 related to a flooding event in 2015 and subsequent remediation and repairs. During the first four months of 2016, water was still being pumped out of the flooded area, which further increased the workover expense for the six months ended June 30, 2016. Generally, workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.
Transportation, Processing, and Other Operating
Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, together with gas processing costs and costs to transport production to a specified sales point. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.
Transportation, processing, and other operating costs in the three months ended June 30, 2017 were 32% or $14.2 million higher than transportation, processing, and other operating costs in the three months ended June 30, 2016. Transportation, processing, and other operating costs in the six months ended June 30, 2017 were 25% or $22.8 million higher than transportation, processing, and other operating costs in the six months ended June 30, 2016. The increases are due to increased production volumes, rates, and gas and NGL prices in the 2017 periods as compared to the 2016 periods.
Gas Gathering and Other
Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. Gas gathering and other in the three months ended June 30, 2017 was 15%, or $1.2 million, higher than gas gathering and other in the three months ended June 30, 2016. Gas gathering and other in the six months ended June 30, 2017 was 10%, or $1.5 million, higher than gas gathering and other in the six months ended June 30, 2016. The increases from 2016 are primarily due to increases in product costs due to increased gas and NGL prices.
Taxes Other than Income
Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties. Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes. Taxes other than income increased $3.4 million, or 24%, in the second quarter of 2017 as compared to the second quarter of 2016. Taxes other than income increased $10.9 million, or 39%, in the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. These increases are due to the increase in revenue seen between the comparable periods. Taxes other than income was 3.9% and 4.8% of production revenues for the three months ended June 30, 2017 and 2016, respectively, and was 4.4% and 5.3% of production revenues for the six months ended June 30, 2017 and 2016, respectively. The decrease in the percentages in the 2017 periods as compared to the 2016 periods is due to refunds received for, and reduced tax rates approved on, certain of our Texas high cost gas wells in 2017.
General and Administrative
General and administrative (“G&A”) expenses consist primarily of salaries and related benefits, office rent, legal and consultant fees, systems costs, and other administrative costs incurred in our offices that are not directly associated with exploration, development, or production activities. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. G&A costs were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
Six Months Ended
|
|
Variance
|
|
|
June 30,
|
|
Between
|
|
June 30,
|
|
Between
|
General and Administrative Expense
(in thousands):
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
|
2017 / 2016
|
Gross G&A
|
|
$
|
38,541
|
|
$
|
39,397
|
|
$
|
(856)
|
|
$
|
72,631
|
|
$
|
69,456
|
|
$
|
3,175
|
Less amounts capitalized to oil and gas properties
|
|
|
(18,779)
|
|
|
(17,973)
|
|
|
(806)
|
|
|
(34,835)
|
|
|
(34,135)
|
|
|
(700)
|
G&A expense
|
|
$
|
19,762
|
|
$
|
21,424
|
|
$
|
(1,662)
|
|
$
|
37,796
|
|
$
|
35,321
|
|
$
|
2,475
|
G&A expense for the second quarter of 2017 was 8%, or $1.7 million, lower than for the second quarter of 2016. This decrease is primarily due to the severance paid out in the second quarter of 2016 associated with the voluntary Early Retirement Incentive Program that was offered to certain employees at that time. This decrease was partially offset by increased bonus accruals and salaries in 2017. G&A expense for the six months ended June 30, 2017 was 7%, or $2.5 million, higher than for the six months ended June 30, 2016. This increase is primarily due to increased bonus accruals and various office-related expenses in 2017, partially offset by decreased severance. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities.
Stock Compensation
Stock compensation expense consists of non-cash charges resulting from the amortization of the cost of restricted stock and stock option awards, net of amounts capitalized to oil and gas properties. We have recognized stock-based compensation expense as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
Six Months Ended
|
|
Variance
|
|
|
June 30,
|
|
Between
|
|
June 30,
|
|
Between
|
Stock Compensation Expense
(in thousands):
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
|
2017 / 2016
|
Restricted stock awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance stock awards
|
|
$
|
6,438
|
|
$
|
7,215
|
|
$
|
(777)
|
|
$
|
12,840
|
|
$
|
12,909
|
|
$
|
(69)
|
Service-based stock awards
|
|
|
4,208
|
|
|
4,751
|
|
|
(543)
|
|
|
9,132
|
|
|
8,916
|
|
|
216
|
|
|
|
10,646
|
|
|
11,966
|
|
|
(1,320)
|
|
|
21,972
|
|
|
21,825
|
|
|
147
|
Stock option awards
|
|
|
579
|
|
|
748
|
|
|
(169)
|
|
|
1,245
|
|
|
1,403
|
|
|
(158)
|
Total stock compensation cost
|
|
|
11,225
|
|
|
12,714
|
|
|
(1,489)
|
|
|
23,217
|
|
|
23,228
|
|
|
(11)
|
Less amounts capitalized to oil and gas properties
|
|
|
(4,932)
|
|
|
(5,224)
|
|
|
292
|
|
|
(10,636)
|
|
|
(10,210)
|
|
|
(426)
|
Stock compensation expense
|
|
$
|
6,293
|
|
$
|
7,490
|
|
$
|
(1,197)
|
|
$
|
12,581
|
|
$
|
13,018
|
|
$
|
(437)
|
Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The decrease in total stock compensation cost in the 2017 periods presented above as compared to 2016 periods presented above is primarily due to awards vesting prior to the 2017 periods and retirements that occurred during the second quarter of 2016 that involved the accelerated vesting of awards during that period, both of which were partially offset by awards granted either during or subsequent to the 2016 periods.
We adopted Accounting Standards Update 2016-09,
Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”) on January 1, 2017. ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-09, we made an accounting
policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the six months ended June 30, 2016 by increasing net cash provided by operating activities by $4.1 million and increasing net cash used by financing activities by $4.1 million for the payment of tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the six months ended June 30, 2017 and 2016.
(Gain) Loss on Derivative Instruments, Net
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
(Gain) Loss on Derivative Instruments, Net
(in thousands):
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Change in fair value of derivative instruments, net
|
|
$
|
(22,166)
|
|
$
|
37,095
|
|
$
|
(72,087)
|
|
$
|
41,735
|
Cash (receipts) payments on derivative instruments, net
|
|
|
(343)
|
|
|
(3,859)
|
|
|
5,717
|
|
|
(8,927)
|
(Gain) loss on derivative instruments, net
|
|
$
|
(22,509)
|
|
$
|
33,236
|
|
$
|
(66,370)
|
|
$
|
32,808
|
Other (Income) and Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Variance
|
|
Six Months Ended
|
|
Variance
|
|
|
June 30,
|
|
Between
|
|
June 30,
|
|
Between
|
Other Income and Expense
(in thousands):
|
|
2017
|
|
2016
|
|
2017 / 2016
|
|
2017
|
|
2016
|
|
2017 / 2016
|
Interest expense
|
|
$
|
20,095
|
|
$
|
20,824
|
|
$
|
(729)
|
|
$
|
41,147
|
|
$
|
41,629
|
|
$
|
(482)
|
Capitalized interest
|
|
|
(5,442)
|
|
|
(5,633)
|
|
|
191
|
|
|
(12,083)
|
|
|
(10,537)
|
|
|
(1,546)
|
Loss on early extinguishment of debt
|
|
|
28,169
|
|
|
—
|
|
|
28,169
|
|
|
28,169
|
|
|
—
|
|
|
28,169
|
Other, net
|
|
|
(2,231)
|
|
|
(2,011)
|
|
|
(220)
|
|
|
(4,441)
|
|
|
(3,661)
|
|
|
(780)
|
|
|
$
|
40,591
|
|
$
|
13,180
|
|
$
|
27,411
|
|
$
|
52,792
|
|
$
|
27,431
|
|
$
|
25,361
|
The majority of our interest expense relates to interest on our senior unsecured notes and amortization of the related debt issuance costs and discount. See
Long-term Debt
below for further information regarding our debt.
We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualified assets. Capitalized interest will fluctuate based on the rates applicable to borrowings outstanding during the period and the amount of costs on which interest is capitalized. Despite there being higher capital costs upon which to capitalize interest in 2017 than in 2016, capitalized interest was lower in the second quarter 2017 than in the second quarter 2016 due to a lower interest rate. This is because we replaced our 5.875% notes with 3.90% notes in the second quarter of 2017. Capitalized interest was higher during the six months ended June 30, 2017 as compared to during the six months ended June 30, 2016 due to higher capital costs upon which to capitalize interest, partially offset by a lower interest rate. Our capital expenditures have increased during 2017 from the 2016 periods due to improved commodity prices. See
Capital Expenditures
below for further information regarding our capital expenditures.
The $28.2 million loss on early extinguishment of debt incurred during the three and six months ended June 30, 2017 was due to the completion of a tender offer and redemption of $750 million 5.875% senior notes during the second quarter. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity of the 5.875% notes was 2022.
Components of Other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous asset sales, interest income, and income and expense associated with other non-operating activities.
Income Tax Expense (Benefit)
The components of our provision for income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
June 30,
|
|
Income Tax Expense (Benefit)
(in thousands):
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Current tax benefit
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(6)
|
|
$
|
—
|
|
Deferred tax expense (benefit)
|
|
|
58,617
|
|
|
(122,361)
|
|
|
136,929
|
|
|
(254,424)
|
|
|
|
$
|
58,617
|
|
$
|
(122,361)
|
|
$
|
136,923
|
|
$
|
(254,424)
|
|
Combined federal and state effective income tax rate
|
|
|
37.6
|
%
|
|
36.3
|
%
|
|
37.5
|
%
|
|
36.3
|
%
|
Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35% primarily due to state income taxes and non-deductible expenses. See Note 9 to the Condensed Consolidated Financial Statements for additional information regarding our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We strive to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, proceeds from sales of non-core assets and occasional public financings based on our monitoring of capital markets and our balance sheet.
Our liquidity is highly dependent on prices we receive for the oil, natural gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital, and future rate of growth. See
RESULTS OF OPERATIONS—
Revenues
above for further information and analysis of the impact realized prices have had on our 2017 earnings.
We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program. We have a balanced and abundant drilling inventory and limited long-term commitments, which enables us to respond quickly to industry volatility. Based on current economic conditions, our 2017 exploration and development expenditures are projected to range from $1.1 – $1.2 billion. Investments in gathering and processing infrastructure and other fixed assets are expected to approximate an additional $60 million for the year. See
Capital Expenditures
below for information regarding our exploration and development (“E&D”) activities for the three and six months ended June 30, 2017 and 2016.
We periodically use derivative instruments to mitigate volatility in commodity prices. At June 30, 2017, we had derivative contracts covering a portion of our 2017 and 2018 production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may hedge up to 50% of our oil and natural gas production on a forward five-quarter basis. See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.
We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices. Cash and cash equivalents at June 30, 2017 were $519.6 million. At June 30, 2017, our long-term debt consisted of $1.5 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024 and $750 million 3.90% notes due in 2027. During the second quarter of 2017, we completed a tender offer and redemption of $750 million 5.875% notes due 2022 and issued the aforementioned 3.90% notes. At June 30, 2017, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $997.5 million. See
Long-term Debt
below for more information regarding our debt.
Our debt to total capitalization ratio at June 30, 2017 was 39%, down from 42% at December 31, 2016. This ratio is calculated by dividing the principal amount of long-term debt by the sum of (i) the principal amount of long-term debt and (ii) total stockholders’ equity, with all numbers coming directly from the Condensed Consolidated Balance Sheet. At June 30, 2017, the ratio calculation is $1.5 billion ÷ ($1.5 billion + $2.31 billion). Management uses this ratio as one indicator of our financial condition and believes professional research analysts and rating agencies use this ratio for this purpose and to compare our financial condition
to other companies’ financial conditions. Additionally, our credit facility includes a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.
We expect our operating cash flow and other capital resources to be adequate to meet our needs for planned capital expenditures, working capital, debt service, and dividends declared in 2017 and beyond.
Analysis of Cash Flow Changes
The following table presents the totals of the major cash flow classification categories from our
Condensed
Consolidated Statements of Cash Flows for the periods indicated.
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
June 30,
|
(in thousands)
|
|
2017
|
|
2016
|
Net cash provided by operating activities
|
|
$
|
504,800
|
|
$
|
217,786
|
Net cash used by investing activities
|
|
$
|
(590,824)
|
|
$
|
(329,978)
|
Net cash used by financing activities
|
|
$
|
(47,257)
|
|
$
|
(25,451)
|
Net cash provided by operating activities for the first six months of 2017 was $504.8 million, up $287.0 million or 132% from $217.8 million for the first six months of 2016. The $287.0 million increase resulted primarily from a period-over-period increase in production revenue, which increased due to increased realized commodity prices and production volumes. This increase was partially offset by net increases in certain operating costs and expenses, increased cash outflows for settlements of derivative instruments, and an increase in our investment in working capital. See
RESULTS OF OPERATIONS
above for information regarding the changes in revenue and operating expenses.
Net cash used by investing activities for the first six months of 2017 was $590.8 million, up $260.8 million or 79% from $330.0 million for the first six months of 2016. The majority of our cash flows used by investing activities are E&D expenditures. In response to improved commodity prices, we have increased our 2017 capital spending over 2016 levels.
Net cash used by financing activities for the first six months of 2017 was $47.3 million, up $21.8 million or 86% from $25.5 million for the first six months of 2016. Net cash used by financing activities for the first six months of 2017 includes $772.8 million used for the early extinguishment of the $750 million 5.875% senior notes due 2022, which included $22.6 million in tender and redemption premiums. Additionally, the 2017 period includes $741.9 million proceeds, net of underwriters’ fees, discount, and issuance costs, that we received for the issuance of $750 million 3.90% senior notes due 2027. The other primary components of net cash used by financing activities are the payment of dividends and the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards. During each of the first two quarters of 2017, we paid an $0.08 per share dividend, totaling $15.2 million in dividends paid during the six months ended June 30, 2017. We paid a $0.16 per share dividend in the first quarter of 2016 and an $0.08 per share dividend in the second quarter of 2016, totaling $22.7 million in dividends paid during the six months ended June 30, 2016.
Adjusted Cash Flow from Operations
Adjusted cash flow from operations is a non-GAAP financial measure. Management uses the non-GAAP financial measure of adjusted cash flow from operations as a means of measuring our ability to fund our capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of net cash provided by operating activities. Management believes this non-GAAP financial measure provides useful information to investors for the same reason, and that it is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. The following table presents adjusted cash flow from operations and a reconciliation to the most directly comparable GAAP financial measure, net cash provided by operating activities.
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
June 30,
|
(in thousands)
|
|
2017
|
|
2016
|
Net cash provided by operating activities
|
|
$
|
504,800
|
|
$
|
217,786
|
Change in operating assets and liabilities
|
|
|
39,827
|
|
|
10,669
|
Adjusted cash flow from operations
|
|
$
|
544,627
|
|
$
|
228,455
|
Capital Expenditures
The following table presents capitalized expenditures for oil and gas property acquisitions and exploration and development (“E&D”) activities, as well as sales proceeds for property sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
250
|
|
$
|
—
|
|
$
|
250
|
|
$
|
3,324
|
Unproved
|
|
|
792
|
|
|
—
|
|
|
3,825
|
|
|
10,568
|
Net purchase price adjustments
|
|
|
5
|
|
|
34
|
|
|
10
|
|
|
(2,928)
|
|
|
|
1,047
|
|
|
34
|
|
|
4,085
|
|
|
10,964
|
Exploration and development:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land and seismic
|
|
|
33,302
|
|
|
17,474
|
|
|
110,487
|
|
|
28,636
|
Exploration and development
|
|
|
262,575
|
|
|
138,686
|
|
|
491,042
|
|
|
285,708
|
|
|
|
295,877
|
|
|
156,160
|
|
|
601,529
|
|
|
314,344
|
Sales proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
(2,000)
|
|
|
—
|
|
|
(2,000)
|
|
|
(12,500)
|
Unproved
|
|
|
(2,305)
|
|
|
(16)
|
|
|
(7,271)
|
|
|
(16)
|
Net purchase price adjustments
|
|
|
43
|
|
|
357
|
|
|
108
|
|
|
(114)
|
|
|
|
(4,262)
|
|
|
341
|
|
|
(9,163)
|
|
|
(12,630)
|
|
|
$
|
292,662
|
|
$
|
156,535
|
|
$
|
596,451
|
|
$
|
312,678
|
Amounts in the table above are presented on an accrual basis. The Condensed Consolidated Statements of Cash Flows in this report reflect activities on a cash basis, when payments are made or received.
Our 2017 E&D capital investment is expected to approximate $1.1 - $1.2 billion. Approximately 62% of our 2017 capital investment is projected to be in the Permian Basin with most of the remainder in the Mid-Continent region.
As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.
We intend to continue to fund our capital investment program with cash on hand and cash flow from our operating activities. Sales of non-core assets and borrowings under our credit facility may also be used to supplement funding of capital expenditures. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our credit facility from time-to-time. See
Long-term Debt
—
Bank Debt
below for further information regarding our credit facility.
The following table reflects wells brought on production by region during the periods indicated.
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
June 30,
|
|
June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Gross wells
|
|
|
|
|
|
|
|
Permian Basin
|
11
|
|
13
|
|
36
|
|
20
|
Mid-Continent
|
40
|
|
21
|
|
85
|
|
36
|
|
51
|
|
34
|
|
121
|
|
56
|
Net wells
|
|
|
|
|
|
|
|
Permian Basin
|
10
|
|
9
|
|
26
|
|
12
|
Mid-Continent
|
8
|
|
5
|
|
18
|
|
7
|
|
18
|
|
14
|
|
44
|
|
19
|
As of June 30, 2017, we had 98 gross (29 net) wells awaiting completion: 27 gross (13 net) in the Permian Basin and 71 gross (16 net) in the Mid-Continent region. We also had 15 operated rigs running: nine in the Permian Basin and six in the Mid-Continent region.
We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect current pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations.
Long-term Debt
Long-term debt at June 30, 2017 and December 31, 2016, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
|
|
|
Unamortized Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance Costs
|
|
Long-term
|
|
|
|
|
Unamortized Debt
|
|
Long-term
|
(in thousands)
|
Principal
|
|
and Discount
(1)
|
|
Debt, net
|
|
Principal
|
|
Issuance Costs
|
|
Debt, net
|
5.875% Senior Notes
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
750,000
|
|
$
|
(5,691)
|
|
$
|
744,309
|
4.375% Senior Notes
|
|
750,000
|
|
|
(5,872)
|
|
|
744,128
|
|
|
750,000
|
|
|
(6,370)
|
|
|
743,630
|
3.90% Senior Notes
|
|
750,000
|
|
|
(8,031)
|
|
|
741,969
|
|
|
—
|
|
|
—
|
|
|
—
|
Total long-term debt
|
$
|
1,500,000
|
|
$
|
(13,903)
|
|
$
|
1,486,097
|
|
$
|
1,500,000
|
|
$
|
(12,061)
|
|
$
|
1,487,939
|
|
(1)
|
|
At June 30, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $6.2 million and $1.9 million, respectively. The 4.375% notes were issued at par.
|
Bank Debt
We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion, with an option for us to increase aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of June 30, 2017, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $997.5 million.
At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.
The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of June 30, 2017, we were in compliance with all of the financial and non-financial covenants.
At June 30, 2017 and December 31, 2016, we had $3.9 million and $4.
5
million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in Other assets on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility.
Senior Notes
On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered. We settled these tendered notes for $268.1 million, including accrued interest. On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest. During the three months ended June 30, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity of the 5.875% notes was 2022.
On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum. We have received $741.9 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs as of June 30, 2017. The notes bear an interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment to be made November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes.
Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2017. The 4.375% notes are due in 2024. Interest on each of the senior notes is payable semiannually. The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.
Working Capital Analysis
Our working capital fluctuates primarily as a result of changes in our cash and cash equivalents, increases or decreases in our realized commodity prices and production volumes, changes in our oil and gas well equipment and supplies, and changes in receivables and payables related to our operating and E&D activities.
At June 30, 2017, we had working capital of $401.7 million, a decrease of $45.3 million or 10% compared to working capital of $447.0 million at December 31, 2016.
Working capital decreases consisted primarily of the following:
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Cash and cash equivalents decreased by $133.3 million.
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Operations-related accounts payable and accrued liabilities increased by $40.4 million.
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Accrued liabilities related to our E&D expenditures increased by $12.7 million.
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Decreases in working capital were partially offset by the following primary increases:
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Operations-related accounts receivable increased by $61.0 million.
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Current derivative instruments increased by $69.1 million to a net asset.
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Oil and gas well equipment and supplies increased by $12.1 million.
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Cash on hand was used during the six months ended June 30, 2017, along with cash flow from operations, primarily to fund our capital expenditures. Accounts receivable are a major component of our working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. Historically, losses associated with uncollectible receivables have not been significant. The fair value of derivative instruments fluctuates based on changes in the underlying price indices as compared to the contracted prices.
Dividends
A quarterly cash dividend has been paid to stockholders every quarter since the first quarter of 2006. In May 2017, an $0.08 per share dividend was declared, which is payable on September 1, 2017 to stockholders of record on August 15, 2017. Future dividend payments will depend on our level of earnings, financing requirements, and other factors considered relevant by our Board of Directors. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2017, our material off-balance sheet arrangements consisted of operating lease agreements, which are customary in the oil and gas industry and are included in the table below.
Contractual Obligations and Material Commitments
At June 30, 2017, we had contractual obligations and material commitments as follows:
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Payments Due by Period
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Contractual obligations:
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1 Year or
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2 - 3
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4 - 5
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More than
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(in thousands)
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Total
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Less
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Years
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Years
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5 Years
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Long-term debt-principal
(1)
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$
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1,500,000
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$
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—
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—
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—
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1,500,000
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Long-term debt-interest
(1)
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525,032
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63,769
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124,125
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124,125
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213,013
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Operating leases
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92,049
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9,672
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21,458
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22,232
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38,687
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Unconditional purchase obligations
(2)
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42,570
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9,791
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10,630
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8,785
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13,364
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Derivative liabilities
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98
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98
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Asset retirement obligation
(3)
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156,589
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9,226
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—
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(3)
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—
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(3)
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—
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(3)
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Other long-term liabilities
(4)
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34,501
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1,528
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2,992
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2,040
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27,941
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$
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2,350,839
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$
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94,084
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$
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159,205
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$
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157,182
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$
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1,793,005
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(1)
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The interest payments presented above include the accrued interest payable on our long-term debt as of June 30, 2017 as well as future payments calculated using the long-term debt’s fixed rates and principal amounts outstanding as of June 30, 2017. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
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(2)
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Of the total Unconditional purchase obligations, $40.0 million represents obligations for firm transportation agreements for pipeline capacity.
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(3)
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We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.
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(4)
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Other long-term liabilities, which are included in the Other liabilities line item on the Condensed Consolidated Balance Sheet, include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities.
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The following discusses various commercial commitments that we have, which include potential future cash payments if we fail to meet various performance obligations. These are not reflected in the table above.
At June 30, 2017, we had estimated commitments of approximately: (i) $159.6 million to finish drilling and completing wells and various other infrastructure projects in progress and (ii) $13.7 million to finish gathering system construction in progress.
At June 30, 2017, we had firm sales contracts to deliver approximately 181.3 Bcf of natural gas over the next 7.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2017 index price, would be approximately $451.9 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations.
In connection with gas gathering and processing agreements, we have volume commitments over the next nine years. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $322.3 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations.
We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $13.5 million. Of this total, we have accrued a liability of $1.9 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.
All of the noted commitments were routine and made in the ordinary course of our business.
Taking into account current commodity prices and anticipated levels of production, we believe that our net cash flow generated from operations and our other capital resources will be adequate to meet future obligations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We consider accounting policies related to oil and gas reserves, full cost accounting, goodwill, contingencies, asset retirement obligations, and income taxes to be critical policies and estimates. These are summarized in “
Management’s Discussion and Analysis of Financial Condition and Results of Operations
” in Item 7 of our Annual Report on Form 10-K/A for the year ended December 31, 2016.
Recent Accounting Developments
See Note 1 to the Condensed Consolidated Financial Statements in this report for a discussion of recently issued accounting pronouncements and their anticipated effect on our financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk including the risk of loss arising from adverse changes in commodity prices and interest rates.
Price Fluctuations
Our major market risk is pricing applicable to our oil, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. For the three and six months ended June 30, 2017, oil sales, gas sales, and NGL sales accounted for 52%, 30%, and 18% of our total production revenue, respectively. For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized oil price would have resulted in a ±$5.3 million and ±$10.0 million change in revenues, respectively. For the three and six months ended June 30, 2017, a ±$0.10 per Mcf change in our realized gas price would have resulted in a ±$4.7 million and ±$9.1 million change in revenues, respectively. For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized NGL price would have resulted in a ±$4.4 million and ±$8.4 million change in revenues, respectively.
We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At June 30, 2017, we had oil and gas collars covering a portion of our 2017 and 2018 production, which were recorded as current and non-current assets and current liabilities. At June 30, 2017, our oil and gas collars had a gross asset fair value of $20.2 million and a gross liability fair value of $0.1 million. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.
While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For our oil collars outstanding at June 30, 2017, a hypothetical $1.00 decrease in the forward prices used to calculate the fair value as of June 30, 2017 would result in an increase of approximately $3.3 million to the net asset fair value of the derivatives and a hypothetical $1.00 increase in the forward prices used to calculate the fair value as of June 30, 2017 would result in a decrease of approximately $3.2 million to the net asset fair value of the derivatives. For our gas collars outstanding as of June 30, 2017, a hypothetical $0.10 decrease in the forward prices used to calculate the fair value as of June 30, 2017 would result in an increase of approximately $3.0 million to the net asset fair value of the derivatives and a hypothetical $0.10 increase in the forward prices used to calculate the fair value as of June 30, 2017 would result in a decrease of approximately $2.9 million to the net asset fair value of the derivatives.
Interest Rate Risk
At June 30, 2017, our long-term debt consisted of $750 million in 4.375% senior unsecured notes that will mature on June 1, 2024 and $750 million in 3.90% senior unsecured notes that will mature on May 15, 2027. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Cimarex management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of June 30, 2017. Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow such persons to make timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting that occurred during the fiscal quarter ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except
that we completed execution of our remediation plan and successfully remediated a material weakness in internal control surrounding the full cost ceiling test calculation previously reported in the company’s 2016 Annual Report on Form 10-K/A and our March 31, 2017 Quarterly Report on Form 10-Q
.
In response to the identified material weakness, the company developed a plan with oversight from the Audit Committee of the Board of Directors to remediate the material weakness. Our remediation plan, which was implemented during the second quarter and applied in the financial reporting for the quarters ended March 31, 2017 and June 30, 2017, included the following:
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Enhancement of the control over the preparation and review of the full cost ceiling test calculation to include examining SEC SAB Topic 12 to reinforce the understanding of the requirements associated with appropriately performing this calculation, particularly as it relates to the income tax effects in the calculation;
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Refinement of the spreadsheet template used to prepare the full cost ceiling test calculation to ensure that the appropriate application of accounting for all components of the full cost ceiling test calculation is embedded within the template; and
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Revision and communication of the accounting controls, policies, and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing the full cost ceiling test calculation.
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