Rex Energy Corporation (Nasdaq:REXX) today announced its second
quarter 2017 financial and operational results.
Financial Update
Marketing Agreement with BP Energy Company
The company recently entered into a comprehensive
marketing arrangement with BP Energy Company, an indirect
wholly-owned subsidiary of BP plc (NYSE:BP), pursuant to which BP
Energy Company will market the majority of Rex’s liquid C3+
products stream, and provide credit support on behalf of Rex
Energy. The arrangement also enhances several of the company’s
existing marketing initiatives in the Butler and Warrior North
operating areas.
Beginning January 1, 2018, BP Energy Company will
purchase the majority of the company’s C3+ products stream for an
extended term. The pricing structure compares favorably to actual
2016 and projected 2017 prices. The new pricing structure will help
to mitigate the historical fluctuations between summer and winter
pricing and stabilize the company’s quarterly cash flows. As part
of the new marketing arrangement, Rex Energy has reduced
outstanding letters of credit by approximately $14.1 million,
immediately increasing liquidity on the company’s $300 million
delayed draw term loan facility. Also, as part of the broader
marketing initiatives, BP Energy Company will market a portion of
Rex Energy’s Warrior North gas at an improved differential to the
current Dom South pricing.
“I’m very excited to expand our existing
relationship with BP,” said Tom Stabley, Rex Energy’s President and
Chief Executive Officer. “The relationship we have developed and
grown with BP over the past several years has been a major key to
Rex Energy’s success. This is another testament to the confidence
placed in the company’s reserves and development capabilities. I
look forward to this new, deeper relationship, and to continuing to
expand it in the years to come.”
Sale of Salineville Waterline
In July, the company sold its Salineville, OH
waterline and related assets to Keystone Clearwater Services (KCS)
for a total consideration of approximately $8.0 million. The
Salineville waterline provided water for completions in the Warrior
North area. In connection with the sale of the waterline, Rex
Energy entered into a lease agreement with KCS to secure water
services for future completions in the Warrior North area.
Warrior North Area Condensate
Rex Energy has entered into a new term condensate
agreement with Marathon Petroleum Corporation pursuant to which the
company will receive an improved condensate differential on all of
its production in the Warrior North Area beginning September 1,
2017.
Improving Natural Gas Basis Differentials
During the first half of 2017, the company’s
realized natural gas prices improved due to tightening
differentials in the northeast markets and the full realization of
its Gulf Coast transport contracts. The unhedged realized natural
gas price for the first half of 2017 was $2.94 and the natural gas
basis differential was ($0.24) off of NYMEX. As a result, the
company expects its full-year 2017 natural gas basis differential,
including the effects of basis hedging, to improve to ($0.35) –
($0.45) off of NYMEX as compared to the previous estimate of
($0.58) – ($0.68) off of NYMEX.
Second Quarter Financial
Results
Operating revenue from continuing operations for
the three and six months ended June 30, 2017 was $47.5 million and
$99.5 million, respectively, which represents an increase of 52%
and 75% over the same periods in 2016. Commodity revenues,
including settlements from derivatives, for the three and six
months ended June 30, 2017 were $45.4 million and $94.0 million,
respectively, a decrease of 7% and an increase of 7% from the same
periods in 2016. Commodity revenues from natural gas liquids (NGLs)
and condensate, including settlements from derivatives, represented
39% of total commodity revenues for the three months ended June 30,
2017.
Lease operating expense (LOE) from continuing
operations was $29.4 million, or $1.82 per Mcfe for the quarter.
For the six months ended June 30, 2017, LOE was approximately $58.3
million, or $1.84 per Mcfe. General and administrative (G&A)
expenses from continuing operations were $4.3 million for the
second quarter of 2017, or $0.27 per Mcfe. For the six months ended
June 30, 2017, G&A expenses from continuing operations were
$8.8 million, or $0.28 per Mcfe. Cash G&A expenses from
continuing operations (a non-GAAP measure) for the three months
ended June 30, 2017 were $3.8 million, or $0.23 per Mcfe, a 16%
increase on a per unit basis as compared to the same period in
2016. For the six months ended June 30, 2017, cash G&A expenses
from continuing operations (a non-GAAP measure) were $8.3 million,
or $0.26 per Mcfe, consistent on a per unit basis when compared to
the same period in 2016.
Net loss attributable to common shareholders for
the three months ended June 30, 2017 was $10.2 million, or $1.03
per basic share. Net loss attributable to common shareholders for
the six months ended June 30, 2017 was $8.1 million, or $0.83 per
basic share. Adjusted net loss, a non-GAAP measure, for the three
months ended June 30, 2017 was $9.2 million, or $0.93 per share.
Adjusted net loss for the six months ended June 30, 2017 was $14.7
million, or $1.50 per share.
EBITDAX from continuing operations, a non-GAAP
measure, was $12.4 million for the second quarter of 2017 and $28.0
million for the six months ended June 30, 2017.
Reconciliations of adjusted net loss to GAAP net
loss, EBITDAX to GAAP net loss and G&A to cash G&A for the
three and six months ended June 30, 2017, as well as a discussion
of the uses of each measure, are presented in the appendix of this
release.
Production Results and Price
Realizations
Second quarter 2017 production volumes from
continuing operations were 177.1 MMcfe/d, consisting of 108.7
MMcf/d of natural gas, 4.8 Mbbls/d of C3+ NGLs, 5.8 Mbbls/d of
ethane and 0.8 Mbbls/d of condensate. NGLs (including ethane) and
condensate accounted for 39% of net production for the second
quarter of 2017. Second quarter production was constrained during
the quarter due to unplanned maintenance downtime in the company’s
midstream services. The unplanned maintenance downtime adversely
effected production during the second quarter by approximately 3.5
MMcfe/d.
Including the effects of cash-settled derivatives,
realized prices for the three months ended June 30, 2017 were $2.78
per Mcf for natural gas, $21.62 per barrel for C3+ NGLs, $9.93 per
barrel for ethane and $44.35 per barrel for condensate. Before the
effects of hedging, realized prices for the three months ended June
30, 2017 were $2.94 per Mcf for natural gas, $23.03 per barrel for
C3+ NGLs, $9.96 per barrel for ethane and $42.35 per barrel for
condensate.
Including the effects of cash-settled derivatives,
realized prices for the six months ended June 30, 2017 were $2.91
per Mcf for natural gas, $23.37 per barrel for C3+ NGLs, $9.84 per
barrel for ethane and $45.26 per barrel for condensate. Before the
effects of hedging, realized prices for the six months ended June
30, 2017 were $3.05 per Mcf for natural gas, $26.86 per barrel for
C3+ NGLs, $9.74 per barrel for ethane and $44.25 per barrel for
condensate.
Second Quarter 2017 Capital
Investments
For the second quarter of 2017, net operational
capital investments were approximately $29.1 million. The company
expects to be reimbursed by joint development partners for
approximately $13.4 million of previously incurred costs that were
not billed until the third quarter of 2017. Capital investments in
the second quarter of 2017 funded the drilling of six gross (4.8
net) wells, fracture stimulation of six gross (3.1 net) wells and
other projects related to drilling and completing wells in the
Appalachian Basin. Net operated capital expenditures for the
full-year 2017 are still expected to be within the range of the
company’s previously issued guidance of $115.0 million - $130.0
million.
Operational Update
Moraine East Area
In the Moraine East Area, the company drilled two
gross (two net) wells, completed six gross (3.1 net) wells and
placed into sales four gross (1.4 net) wells in the second quarter
of 2017. In addition, the company had nine gross (4.9) net wells
awaiting completion at the end of the second quarter.
The company has begun initial sales from its
six-well Shields pad. The six wells were drilled to an average
lateral length of approximately 8,800 feet and completed in an
average of 49 stages. In addition, the company has completed two of
the Shields wells with engineered spacing designs as compared to
its standard spacing design. The company expects to provide an
update on the performance of the pad in the coming weeks.
The company recently finished completing the four
wells on the Mackrell pad, which were drilled to an average lateral
length of 7,630 feet. The wells are expected to be placed into
sales in early September 2017 as scheduled. Lastly, the company
recently finished drilling the two-wells on the Frye pad, which
were drilled to an average lateral length of approximately 6,300
feet. The two-well Frye pad is currently being completed and is
expected to be placed into sales in the third quarter of 2017.
The twelve wells discussed above are all on the
eastern side of the Moraine East Area and will be the final
delineation of the field. The company now expects to place
additional compression for the Moraine East Area into service in
early January 2018, a delay compared to previous estimates of early
fourth quarter service, which, in turn, will defer peak production
from the area until January 2018.
Legacy Butler Operated Area
In the Legacy Butler Operated Area, the company
has begun completing the four-well Wilson pad. The four wells
were drilled to an average lateral length of approximately 9,300
feet and are expected to be placed into sales in the fourth quarter
of 2017.
Warrior North Area
In the Warrior North Area, the company has finished
drilling the three-well Jenkins pad. The three wells were drilled
to an average lateral length of approximately 6,500 feet and in an
average of 13.2 drilling days, the best average the company has
achieved in the Warrior North Area. The three wells are expected to
be completed at the end of the fourth quarter of 2017.
Third Quarter and Full Year 2017
Guidance
Rex Energy is providing guidance for the third
quarter of 2017 and adjusted full-year 2017. Full-year 2017
production guidance has been reduced to 180.0 –
190.0 MMcfe/d due to midstream restrictions and delays in
placing the Vaughn and Baird pads into sales in the first half of
2017. The company still expects to achieve its year-end 2017 exit
rate production growth rate guidance of 15% - 20% upon the
commissioning of its fourth compressor in the Moraine East Area,
which is scheduled for January 5, 2018. This will allow the company
to remain on target to meet its full-year 2018 production guidance
of 255.0 – 265.0 MMcfe/d.
|
|
3Q2017 |
Full Year 2017 |
|
Production |
171.0 – 181.0 MMcfe/d |
180.0 – 190.0 MMcfe/d |
|
LOE ($/Mcfe) |
$1.80 - $1.90 |
$1.70 - $1.80 |
|
Cash G&A ($/Mcfe) |
$0.22 - $0.27 |
$0.20 - $0.25 |
|
Operational Capital Expenditures(1) |
-- |
$115.0 - $125.0 MMcfe/d |
| (1) Land acquisition expense and capitalized interest are not
included in the operational capital expenditures budget |
Conference Call
InformationManagement will host a live conference call and
webcast on Wednesday, August 9, 2017 at 10:00 a.m. Eastern to
review second quarter 2017 financial results and operational
highlights. The telephone number to access the conference call is
(866) 437-1772.
About Rex Energy Corporation
Headquartered in State College, Pennsylvania, Rex
Energy is an independent oil and gas exploration and production
company with its core operations in the Appalachian Basin. The
company’s strategy is to pursue its higher potential exploration
drilling prospects while acquiring oil and natural gas properties
complementary to its portfolio.
Forward-Looking Statements
Except for historical information, all statements
made in this release, including those relating to the timing and
nature of development plans; drilling and completion schedules;
anticipated fracture stimulation activities; expected dates for
placement of wells into sales; and our financial guidance for third
quarter and full year 2017 are forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. Forward-looking statements may contain words such as
"expected", "expects", "scheduled", "planned", "plans",
"anticipates" or similar words, and are based on management's
experience and perception of historical trends, current conditions,
and anticipated future developments, as well as other factors
believed to be appropriate. We believe these statements and the
assumptions and estimates contained in this release are reasonable
based on information that is currently available to us. However,
management's assumptions and the company's future performance are
subject to a wide range of business risks and uncertainties, both
known and unknown, and we cannot assure that the company can or
will meet the goals, expectations, and projections included in this
release. Any number of factors could cause our actual results to be
materially different from those expressed or implied in our forward
looking statements, including (without limitation):
- economic conditions in the United States and globally;
- domestic and global demand for oil, NGLs and natural gas;
- volatility in oil, NGL, and natural gas pricing;
- conditions in the domestic and global capital and credit
markets and their effect on us;
- the adequacy and availability of capital resources, credit, and
liquidity including, but not limited to, access to additional
borrowing capacity;
- the success of our business, operational, financial, and
hedging strategies;
- new or changing government regulations, including those
relating to environmental matters, permitting, or other aspects of
our operations;
- the geologic quality of our properties with regard to, among
other things, the existence of hydrocarbons in economic
quantities;
- uncertainties inherent in the estimates of our oil and natural
gas reserves;
- our ability to increase oil and natural gas production and
income through exploration and development;
- drilling and operating risks;
- the success of our drilling and completion techniques in
unconventional reservoirs;
- the number of potential well locations to be drilled, the cost
to drill them, and the time frame within which they will be
drilled;
- the ability of contractors to timely and adequately perform
their drilling, construction, well stimulation, completion and
production services;
- the availability of equipment, such as drilling rigs, and
infrastructure, such as transportation, pipelines, processing and
midstream services;
- the effects of adverse weather or other natural disasters on
our operations;
- competition in the oil and gas industry in general, and
specifically in our areas of operations;
- changes in our drilling plans and related budgets;
- the success of prospect development and property acquisition;
and
- uncertainties related to the legal and regulatory environment
for our industry, and our own legal proceedings and their
outcome.
We undertake no obligation to publicly update or
revise any forward-looking statements. Further information on the
company's risks and uncertainties is available in our filings with
the Securities and Exchange Commission and we strongly encourage
investors to review those filings.
| REX ENERGY CORPORATION |
| CONSOLIDATED BALANCE SHEETS |
| ($ in Thousands, Except Share and Per Share
Data) |
|
|
|
|
|
|
ASSETS |
June 30,
2017(Unaudited) |
|
December 31, 2016 |
|
Current Assets |
|
|
|
| Cash and
Cash Equivalents |
$ |
12,855 |
|
|
$ |
3,697 |
|
| Accounts
Receivable |
23,762 |
|
|
25,448 |
|
| Taxes
Receivable |
48 |
|
|
211 |
|
|
Short-Term Derivative Instruments |
7,317 |
|
|
1,873 |
|
|
Inventory, Prepaid Expenses and Other |
2,002 |
|
|
2,546 |
|
|
Total Current Assets |
45,984 |
|
|
33,775 |
|
|
Property and Equipment (Successful Efforts
Method) |
|
|
|
| Evaluated
Oil and Gas Properties |
977,665 |
|
|
1,053,461 |
|
|
Unevaluated Oil and Gas Properties |
205,691 |
|
|
215,794 |
|
| Other
Property and Equipment |
22,309 |
|
|
21,401 |
|
| Wells and
Facilities in Progress |
59,807 |
|
|
21,964 |
|
|
Pipelines |
21,289 |
|
|
18,029 |
|
|
Total Property and Equipment |
1,286,761 |
|
|
1,330,649 |
|
| Less:
Accumulated Depreciation , Depletion and Amortization |
(434,483 |
) |
|
(475,205 |
) |
|
Net Property and Equipment |
852,278 |
|
|
855,444 |
|
| Other
Assets |
2,488 |
|
|
2,492 |
|
| Long-Term
Derivative Instruments |
4,820 |
|
|
2,212 |
|
|
Total Assets |
$ |
905,570 |
|
|
$ |
893,923 |
|
|
LIABILITIES AND EQUITY |
|
|
|
|
Current Liabilities |
|
|
|
| Accounts
Payable |
$ |
46,235 |
|
|
$ |
40,712 |
|
| Current
Maturities of Long-Term Debt |
834 |
|
|
764 |
|
| Accrued
Liabilities |
32,791 |
|
|
37,207 |
|
|
Short-Term Derivative Instruments |
6,563 |
|
|
25,025 |
|
|
Total Current Liabilities |
86,423 |
|
|
103,708 |
|
| Long-Term
Derivative Instruments |
9,450 |
|
|
7,227 |
|
| Senior
Secured Line of Credit and Long-Term Debt, Net of Issuance
Costs |
-- |
|
|
113,785 |
|
| Term
Loans, Net |
136,163 |
|
|
-- |
|
| Senior
Notes, Net |
648,820 |
|
|
638,161 |
|
| Other
Long-Term Debt |
3,627 |
|
|
3,409 |
|
| Other
Deposits and Liabilities |
7,731 |
|
|
8,671 |
|
| Future
Abandonment Cost |
9,658 |
|
|
8,736 |
|
|
Total Liabilities |
$ |
901,872 |
|
|
$ |
883,697 |
|
|
|
|
|
|
|
Stockholder Equity |
|
|
|
| Preferred
Stock, $.001 par value per share, 100,000 shares authorized and
3,987 issued and outstanding on June 30, 2017 and December 31,
2016 |
$ |
1 |
|
|
$ |
1 |
|
| Common
Stock, $.001 par value per share, 100,000,000 shares authorized and
9,952,861 shares issued and outstanding on June 30, 2017 and
9,787,146 shares issued and outstanding on December 31, 2016 |
10 |
|
|
10 |
|
|
Additional Paid-In Capital |
651,659 |
|
|
650,669 |
|
|
Accumulated Deficit |
(647,972 |
) |
|
(640,454 |
) |
|
Total Stockholders’ Equity |
3,698 |
|
|
10,226 |
|
|
Total Liabilities and Owners’ Equity |
$ |
905,570 |
|
|
$ |
893,923 |
|
| REX ENERGY CORPORATION |
| CONSOLIDATED STATEMENTS OF
OPERATIONS |
| (Unaudited, in Thousands, Except per Share
Data) |
|
|
|
|
|
|
|
For the Three Months Ended June
30, |
|
For the Six Months EndedJune
30, |
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
OPERATING REVENUE |
|
|
|
|
|
|
|
|
Natural Gas, NGL and Condensate Sales |
$ |
47,457 |
|
|
$ |
31,271 |
|
|
$ |
99,522 |
|
|
$ |
56,944 |
|
|
Other Operating Revenue |
5 |
|
|
(6 |
) |
|
11 |
|
|
7 |
|
|
TOTAL OPERATING REVENUE |
47,462 |
|
|
31,265 |
|
|
99,533 |
|
|
56,951 |
|
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
29,374 |
|
|
25,221 |
|
|
58,308 |
|
|
49,672 |
|
|
General and Administrative Expense |
4,294 |
|
|
4,837 |
|
|
8,828 |
|
|
10,121 |
|
|
Gain on Disposal of Assets |
(124 |
) |
|
(4,307 |
) |
|
(1,959 |
) |
|
(4,295 |
) |
|
Impairment Expense |
3,032 |
|
|
25,139 |
|
|
4,577 |
|
|
35,780 |
|
|
Exploration Expense |
99 |
|
|
803 |
|
|
319 |
|
|
1,738 |
|
|
Depreciation, Depletion, Amortization and Accretion |
15,501 |
|
|
14,750 |
|
|
30,969 |
|
|
31,262 |
|
|
Other Operating Expense |
(98 |
) |
|
704 |
|
|
(118 |
) |
|
1,030 |
|
|
TOTAL OPERATING EXPENSES |
52,078 |
|
|
67,147 |
|
|
100,924 |
|
|
125,308 |
|
|
LOSS FROM OPERATIONS |
(4,616 |
) |
|
(35,882 |
) |
|
(1,391 |
) |
|
(68,357 |
) |
|
OTHER EXPENSE (EXPENSE) |
|
|
|
|
|
|
|
|
Interest Expense |
(12,122 |
) |
|
(11,439 |
) |
|
(21,266 |
) |
|
(24,469 |
) |
|
Gain (Loss) on Derivatives, Net |
10,386 |
|
|
(29,169 |
) |
|
18,766 |
|
|
(25,120 |
) |
|
Other Income |
20 |
|
|
12 |
|
|
(7 |
) |
|
12 |
|
|
Debt Exchange Expense |
-- |
|
|
(533 |
) |
|
-- |
|
|
(9,014 |
) |
|
Gain on Extinguishment of Debt |
(3,271 |
) |
|
23,707 |
|
|
(3,022 |
) |
|
23,707 |
|
|
TOTAL OTHER INCOME (EXPENSE) |
(4,987 |
) |
|
(17,422 |
) |
|
(5,529 |
) |
|
(34,884 |
) |
|
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME
TAX |
(9,603 |
) |
|
(53,304 |
) |
|
(6,920 |
) |
|
(103,241 |
) |
|
Income Tax Benefit |
-- |
|
|
393 |
|
|
-- |
|
|
(2,321 |
) |
|
NET LOSS FROM CONTINUING OPERATIONS |
(9,603 |
) |
|
(52,911 |
) |
|
(6,920 |
) |
|
(105,562 |
) |
| Loss
From Discontinued Operations, Net of Income Taxes |
-- |
|
|
(1,683 |
) |
|
-- |
|
|
(9,173 |
) |
|
NET LOSS |
(9,603 |
) |
|
(54,594 |
) |
|
(6,920 |
) |
|
(114,735 |
) |
|
Preferred Stock Dividends |
(598 |
) |
|
(1,723 |
) |
|
(1,196 |
) |
|
(3,828 |
) |
| Effect
of Preferred Stock Conversion |
-- |
|
|
72,316 |
|
|
-- |
|
|
72,316 |
|
|
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
SHAREHOLDERS |
$ |
(10,201 |
) |
|
$ |
15,999 |
|
|
$ |
(8,116 |
) |
|
$ |
(46,247 |
) |
| Earnings
per common share: |
|
|
|
|
|
|
|
|
Basic – Net Income (Loss) From Continuing Operations Attributable
to Rex Energy Common Shareholders |
$ |
(1.03 |
) |
|
$ |
2.45 |
|
|
$ |
(0.83 |
) |
|
$ |
(5.79 |
) |
|
Basic – Net Loss From Discontinued Operations Attributable to Rex
Energy Common Shareholders |
-- |
|
|
(0.23 |
) |
|
-- |
|
|
(1.43 |
) |
|
Basic – Net Income (Loss) Attributable to Rex Energy Common
Shareholders |
$ |
(1.03) |
|
$ |
2.22 |
|
|
$ |
(0.83 |
) |
|
$ |
(7.22 |
) |
|
Basic – Weighted Average Shares of Common Stock Outstanding |
9,881 |
|
|
7,180 |
|
|
9,825 |
|
|
6,404 |
|
|
Diluted – Net Income (Loss) From Continuing Operations Attributable
to Rex Energy Common Shareholders |
$ |
(1.03 |
) |
|
$ |
2.45 |
|
|
$ |
(0.83 |
) |
|
$ |
(5.79 |
) |
|
Diluted – Net Loss From Discontinued Operations Attributable to Rex
Energy Common Shareholders |
-- |
|
|
(0.23 |
) |
|
-- |
|
|
(1.43 |
) |
|
Diluted – Net Income (Loss) Attributable to Rex Energy Common
Shareholders |
$ |
(1.03 |
) |
|
$ |
2.22 |
|
|
$ |
(0.83 |
) |
|
$ |
(7.22 |
) |
|
Diluted – Weighted Average Shares of Common Stock Outstanding |
9,881 |
|
|
7,180 |
|
|
9,825 |
|
|
6,404 |
|
| REX ENERGY CORPORATION |
| CONSOLIDATED OPERATIONAL
HIGHLIGHTS |
|
|
|
|
|
|
|
|
|
Three Months Ending |
|
Six Months Ending |
|
|
|
June 30, |
|
June 30, |
|
|
|
2017 |
|
|
2016 |
|
2017 |
|
|
2016 |
| Oil,
Natural Gas, NGL and Ethane sales (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
29,097 |
|
|
$ |
16,044 |
|
$ |
60,442 |
|
|
$ |
31,560 |
|
Condensate sales |
|
|
2,993 |
|
|
|
3,369 |
|
|
6,414 |
|
|
|
4,902 |
|
Natural gas liquids (C3+) sales |
|
|
10,119 |
|
|
|
7,867 |
|
|
23,127 |
|
|
|
13,843 |
|
Ethane sales |
|
|
5,247 |
|
|
|
3,991 |
|
|
9,540 |
|
|
|
6,639 |
|
Cash-settled derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
(1,594 |
) |
|
|
14,857 |
|
|
(2,766 |
) |
|
|
23,080 |
|
Condensate |
|
|
141 |
|
|
|
310 |
|
|
146 |
|
|
|
2,098 |
|
Natural gas liquids (C3+) |
|
|
(616 |
) |
|
|
2,255 |
|
|
(3,001 |
) |
|
|
5,211 |
|
Ethane |
|
|
(12 |
) |
|
|
-- |
|
|
96 |
|
|
|
144 |
| Total
oil, gas, NGL and Ethane sales including cash settled
derivatives |
|
$ |
45,375 |
|
|
$ |
48,693 |
|
$ |
93,998 |
|
|
$ |
87,477 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf) |
|
|
9,889,888 |
|
|
|
11,327,101 |
|
|
19,801,630 |
|
|
|
22,631,620 |
|
Condensate (Bbls) |
|
|
70,687 |
|
|
|
90,565 |
|
|
144,927 |
|
|
|
153,628 |
|
Natural gas liquids (C3+) (Bbls) |
|
|
439,441 |
|
|
|
507,990 |
|
|
861,146 |
|
|
|
997,744 |
|
Ethane (Bbls) |
|
|
526,893 |
|
|
|
532,928 |
|
|
979,580 |
|
|
|
971,140 |
|
Total (Mcfe)1 |
|
|
16,112,014 |
|
|
|
18,115,999 |
|
|
31,715,548 |
|
|
|
35,366,692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production – average per day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf) |
|
|
108,680 |
|
|
|
124,474 |
|
|
109,401 |
|
|
|
124,350 |
|
Condensate (Bbls) |
|
|
777 |
|
|
|
995 |
|
|
801 |
|
|
|
844 |
|
Natural gas liquids (C3+) (Bbls) |
|
|
4,829 |
|
|
|
5,582 |
|
|
4,758 |
|
|
|
5,482 |
|
Ethane (Bbls) |
|
|
5,790 |
|
|
|
5,856 |
|
|
5,412 |
|
|
|
5,336 |
|
Total (Mcfe)1 |
|
|
177,055 |
|
|
|
199,077 |
|
|
175,224 |
|
|
|
194,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average
price per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
| Realized
natural gas price per Mcf – as reported |
|
$ |
2.94 |
|
|
$ |
1.42 |
|
$ |
3.05 |
|
|
$ |
1.39 |
| Realized
impact from cash settled derivatives per Mcf |
|
|
(0.16 |
) |
|
|
1.31 |
|
|
(0.14 |
) |
|
|
1.02 |
| Net
realized price per Mcf |
|
$ |
2.78 |
|
|
$ |
2.73 |
|
$ |
2.91 |
|
|
$ |
2.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized
condensate price per Bbl – as reported |
|
$ |
42.35 |
|
|
$ |
37.20 |
|
$ |
44.25 |
|
|
$ |
31.91 |
| Realized
impact from cash settled derivatives per Bbl2 |
|
|
2.00 |
|
|
|
3.42 |
|
|
1.01 |
|
|
|
13.66 |
| Net
realized price per Bbl |
|
$ |
44.35 |
|
|
$ |
40.62 |
|
$ |
45.26 |
|
|
$ |
45.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized
natural gas liquids (C3+) price per Bbl – as reported |
|
$ |
23.03 |
|
|
$ |
15.49 |
|
$ |
26.86 |
|
|
$ |
13.87 |
| Realized
impact from cash settled derivatives per Bbl |
|
|
(1.41 |
) |
|
|
4.44 |
|
|
(3.49 |
) |
|
|
5.23 |
| Net
realized price per Bbl |
|
$ |
21.62 |
|
|
$ |
19.93 |
|
$ |
23.37 |
|
|
$ |
19.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Realized
ethane price per Bbl – as reported |
|
$ |
9.96 |
|
|
$ |
7.49 |
|
$ |
9.74 |
|
|
$ |
6.84 |
| Realized
impact from cash settled derivatives per Bbl |
|
|
0.03 |
|
|
|
-- |
|
|
0.10 |
|
|
|
0.14 |
| Net
realized price per Bbl |
|
$ |
9.93 |
|
|
$ |
7.49 |
|
$ |
9.84 |
|
|
$ |
6.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE/Mcfe |
|
$ |
1.82 |
|
|
$ |
1.39 |
|
$ |
1.84 |
|
|
$ |
1.40 |
| Cash
G&A/Mcfe |
|
$ |
0.24 |
|
|
$ |
0.20 |
|
$ |
0.26 |
|
|
$ |
0.26 |
| 1 Oil and natural gas liquids are converted at the rate of one
barrel of oil equivalent to six Mcfe. |
| 2 Includes the effect of derivatives not classified as
discontinued operations. When including the effect of Illinois
Basin production, derivatives realized increased prices by 1.15/bbl
and $6.73/bbl for the three and six month periods ended June 30,
2017 and 2016. |
| |
| |
| REX ENERGY CORPORATION |
|
| COMMODITY DERIVATIVES – HEDGE POSITION AS OF
8/8/2017 |
|
| |
|
|
|
2017 |
|
2018 |
|
|
Oil Derivatives (Bbls) |
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
Volume |
|
25,000 |
|
|
60,000 |
|
|
Price |
$ |
54.00 |
|
$ |
54.00 |
|
|
Collar Contracts |
|
|
|
|
|
Volume |
|
-- |
|
|
18,000 |
|
|
Ceiling |
$ |
-- |
|
$ |
60.00 |
|
|
Floor |
$ |
-- |
|
$ |
53.00 |
|
|
Collar Contracts with Short Puts |
|
|
|
|
|
Volume |
|
65,000 |
|
|
66,000 |
|
|
Ceiling |
$ |
61.35 |
|
$ |
61.55 |
|
|
Floor |
$ |
49.23 |
|
$ |
51.59 |
|
|
Short Put |
$ |
39.62 |
|
$ |
42.50 |
|
|
Natural Gas Derivatives (Mcf) |
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
Volume |
|
6,330,000 |
|
|
15,335,000 |
|
|
Price |
$ |
3.03 |
|
$ |
3.10 |
|
|
Swaption Contracts |
|
|
|
|
|
Volume |
|
1,000,000 |
|
|
-- |
|
|
Price |
$ |
3.33 |
|
$ |
-- |
|
|
Put Spreads |
|
|
|
|
|
Volume |
|
-- |
|
|
-- |
|
|
Floor |
$ |
-- |
|
$ |
-- |
|
|
Short Put |
$ |
-- |
|
$ |
-- |
|
|
Collar Contracts |
|
|
|
|
|
Volume |
|
900,000 |
|
|
450,000 |
|
|
Ceiling |
$ |
3.32 |
|
$ |
3.65 |
|
|
Floor |
$ |
2.72 |
|
$ |
3.20 |
|
|
Collar Contracts with Short Puts |
|
|
|
|
|
Volume |
|
7,170,000 |
|
|
8,775,000 |
|
|
Ceiling |
$ |
3.87 |
|
$ |
3.58 |
|
|
Floor |
$ |
2.98 |
|
$ |
2.89 |
|
|
Short Put |
$ |
2.29 |
|
$ |
2.30 |
|
|
Call Contracts |
|
|
|
|
|
Volume |
|
3,505,220 |
|
|
16,489,900 |
|
|
Ceiling |
$ |
4.51 |
|
$ |
4.64 |
|
|
Natural Gas Liquids
(Bbls) |
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
Propane (C3) |
|
|
|
|
|
Volume |
|
405,000 |
|
|
630,000 |
|
|
Price |
$ |
23.30 |
|
$ |
25.62 |
|
|
Butane (C4) |
|
|
|
|
|
Volume |
|
100,000 |
|
|
186,000 |
|
|
Price |
$ |
28.54 |
|
$ |
32.94 |
|
|
Isobutane (IC4) |
|
|
|
|
|
Volume |
|
53,000 |
|
|
102,000 |
|
|
Price |
$ |
29.55 |
|
$ |
33.62 |
|
|
Natural Gasoline (C5+) |
|
|
|
|
|
Volume |
|
140,000 |
|
|
207,072 |
|
|
Price |
$ |
48.43 |
|
$ |
49.42 |
|
|
Ethane |
|
|
|
|
|
Volume |
|
375,000 |
|
|
750,000 |
|
|
Price |
$ |
10.58 |
|
$ |
13.02 |
|
|
Natural Gas Basis (Mcf) |
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
Dominion Appalachia |
|
|
|
|
|
Volume |
|
7,471,000 |
|
|
18,980,000 |
|
|
Price |
$ |
(0.78 |
) |
$ |
(0.81 |
) |
|
Texas Gas Zone 1 |
|
|
|
|
|
Volume |
|
6,120,000 |
|
|
14,600,000 |
|
|
Price |
$ |
(0.13 |
) |
$ |
(0.13 |
) |
|
NYMEX Heating Oil (Gal) |
|
|
|
|
|
Swap Contracts |
|
|
|
|
|
Volume |
|
-- |
|
|
-- |
|
|
Price |
$ |
-- |
|
$ |
-- |
|
APPENDIX REX
ENERGY CORPORATIONNON-GAAP MEASURES
EBITDAX
“EBITDAX” means, for any period, the sum of net
income for such period plus the following expenses, charges or
income to the extent deducted from or added to net income in such
period: interest, income taxes, DD&A, unrealized losses from
financial derivatives, non-recurring gains and losses, exploration
expenses and other similar non-cash charges, minus all non-cash
income, including but not limited to, income from unrealized
financial derivatives and gains on asset dispositions, added to net
income. EBITDAX, as defined above, is used as a financial
measure by our management team and by other users of its financial
statements, such as our commercial bank lenders to analyze such
things as:
- Our operating performance and return on capital in comparison
to those of other companies in our industry, without regard to
financial or capital structure;
- The financial performance of our assets and valuation of the
entity without regard to financing methods, capital structure or
historical cost basis;
- Our ability to generate cash sufficient to pay interest costs,
support our indebtedness and make cash distributions to our
stockholders; and
- The viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
EBITDAX is not a calculation based on GAAP
financial measures and should not be considered as an alternative
to net income (loss) (the most directly comparable GAAP financial
measure) in measuring our performance, nor should it be used as an
exclusive measure of cash flows, because it does not consider the
impact of working capital growth, capital expenditures, debt
principal reductions, and other sources and uses of cash, which are
disclosed in our consolidated statements of cash flows.
We have reported EBITDAX because it is a financial
measure used by our existing commercial lenders, and because this
measure is commonly reported and widely used by investors as an
indicator of a company’s operating performance and ability to incur
and service debt. You should carefully consider the specific
items included in our computations of EBITDAX. While we have
disclosed EBITDAX to permit a more complete comparative analysis of
our operating performance and debt servicing ability relative to
other companies, you are cautioned that EBITDAX as reported by us
may not be comparable in all instances to EBITDAX as reported by
other companies. EBITDAX amounts may not be fully available
for management’s discretionary use, due to requirements to conserve
funds for capital expenditures, debt service and other
commitments.
We believe that EBITDAX assists our lenders and
investors in comparing our performance on a consistent basis
without regard to certain expenses, which can vary significantly
depending upon accounting methods. Because we may borrow money
to finance our operations, interest expense is a necessary element
of our costs. In addition, because we use capital assets,
DD&A are also necessary elements of our costs. Finally, we
are required to pay federal and state taxes, which are necessary
elements of our costs. Therefore, any measures that exclude
these elements have material limitations.
To compensate for these limitations, we believe it
is important to consider both net income determined under GAAP and
EBITDAX to evaluate our performance.
For purposes of consistency with current
calculations, we have revised certain amounts relating to prior
period EBITDAX. The following table presents a reconciliation of
our net income to EBITDAX for each of the periods presented.
|
|
|
Three Months EndedJune 30, |
|
Six Months EndedJune
30, |
|
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
| Net Loss
From Continuing Operations |
|
$ |
(9,603 |
) |
|
$ |
(52,911 |
) |
|
$ |
(6,920 |
) |
|
$ |
(105,562 |
) |
|
Add Back Non-Recurring Costs1 |
|
3,349 |
|
|
(23,174 |
) |
|
3,459 |
|
|
(14,694 |
) |
|
Add Back Depletion, Depreciation, Amortization and Accretion |
|
15,501 |
|
|
14,750 |
|
|
30,969 |
|
|
31,262 |
|
|
Add Back Non-Cash Compensation Expense |
|
511 |
|
|
1,164 |
|
|
571 |
|
|
1,016 |
|
|
Add Back Interest Expense |
|
12,123 |
|
|
11,439 |
|
|
21,271 |
|
|
24,469 |
|
|
Add Back Impairment Expense |
|
3,032 |
|
|
25,139 |
|
|
4,577 |
|
|
35,780 |
|
|
Add Back Exploration Expenses |
|
99 |
|
|
803 |
|
|
319 |
|
|
1,738 |
|
|
Less Gain on Disposal of Assets |
|
(124 |
) |
|
(4,307 |
) |
|
(1,959 |
) |
|
(4,295 |
) |
|
Less (Gain) Loss on Financial Derivatives |
|
(10,386 |
) |
|
29,169 |
|
|
(18,766 |
) |
|
25,120 |
|
|
Add Back (Less) Cash Settlement of Derivatives |
|
(2,082 |
) |
|
17,345 |
|
|
(5,525 |
) |
|
30,340 |
|
|
Less Income Tax Benefit |
|
-- |
|
|
(393 |
) |
|
-- |
|
|
2,321 |
|
| EBITDAX
From Continuing Operations |
|
$ |
12,420 |
|
|
$ |
19,024 |
|
$ |
27,996 |
|
$ |
27,495 |
|
| Net Loss
From Discontinued Operations |
|
$ |
-- |
|
|
$ |
(1,683 |
) |
$ |
-- |
|
$ |
(9,173 |
) |
|
Add Back Depletion, Depreciation, Amortization and Accretion |
|
-- |
|
|
2,186 |
|
|
-- |
|
|
5,083 |
|
|
Add Back Non-Cash Compensation Expense |
|
-- |
|
|
139 |
|
|
-- |
|
|
259 |
|
|
Add Back Interest Expense |
|
-- |
|
|
1 |
|
|
-- |
|
|
3 |
|
|
Add Back Impairment Expense |
|
-- |
|
|
-- |
|
|
-- |
|
|
3,543 |
|
|
Add Back Exploration Expense |
|
-- |
|
|
85 |
|
|
-- |
|
|
143 |
|
|
Less Gain on Disposal of Assets |
|
-- |
|
|
(2 |
) |
|
-- |
|
|
(43 |
) |
|
Add Back (Less) Income Tax Expense (Benefit) |
|
-- |
|
|
120 |
|
|
-- |
|
|
(502 |
) |
|
Add EBITDAX From Discontinued Operations |
|
$ |
-- |
|
|
$ |
846 |
|
|
$ |
-- |
|
|
$ |
(687 |
) |
| EBITDAX
(Non-GAAP) |
|
$ |
12,420 |
|
|
$ |
19,870 |
|
|
$ |
27,996 |
|
|
$ |
26,808 |
|
| |
| 1 For the three and six months ended June 30, 2017,
includes a net $0.1 million of advisory services related to joint
venture drilling programs, and $3.3 million in loss on
extinguishment of debt. For the six months ended June 30, 2017,
includes a net $0.4 million of advisory services related to joint
venture drilling programs, and $3.0 million in loss on the
extinguishment of debt. For the three months ended June 30, 2016,
includes approximately $23.7 million in gains on extinguishment of
debt and $0.5 million in debt exchange expenses. For the six months
ended June 30, 2016, includes approximately $23.7 million in gain
on extinguishment of debt and $9.0 million in debt exchange
expenses. |
| |
Adjusted Net Loss
“Adjusted Net Loss” means, for any period, the sum of net income
(loss) from continuing operations before income taxes for the
period plus the following expenses, charges or income, in each
case, to the extent deducted from or added to net income in the
period: unrealized losses from financial derivatives, non-cash
compensation expense, dry hole expenses, disposals of assets,
impairment and other one-time or non-recurring charges, minus all
gains from unrealized financial derivatives, disposal of assets and
deferred income tax benefits, added to net income. Adjusted Net
Loss is used as a financial measure by Rex Energy's management team
and by other users of its financial statements, to analyze its
financial performance without regard to non-cash deferred taxes and
non-cash unrealized losses or gains from oil and gas derivatives.
Adjusted Net Loss is not a calculation based on GAAP financial
measures and should not be considered as an alternative to net
income (loss) in measuring the company's performance.
Rex Energy reports Adjusted Net Loss because it believes that
this measure is commonly reported and widely used by investors as
an indicator of a company's operating performance. You should
carefully consider the specific items included in the company's
computation of this measure. You are cautioned that Adjusted Net
Income as reported by Rex Energy may not be comparable in all
instances to that reported by other companies.
To compensate for these limitations, the company believes it is
important to consider both net income determined under GAAP and
Adjusted Net Income.
The following table presents a reconciliation of Rex Energy’s
net income from continuing operations to its adjusted net loss for
each of the periods presented ($ in thousands):
|
|
For the Three Months Ended |
|
For the Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
|
2017 |
|
|
2016 |
|
|
|
2017 |
|
|
2016 |
|
| Loss
From Continuing Operations Before Income Taxes, as reported |
$ |
(9,603 |
) |
$ |
(53,304 |
) |
|
$ |
(6,920 |
) |
$ |
(103,241 |
) |
|
(Gain) Loss on Derivatives, Net |
|
(10,386 |
) |
|
29,169 |
|
|
|
(18,766 |
) |
|
25,120 |
|
|
Cash Settlement of Derivatives |
|
(2,082 |
) |
|
17,345 |
|
|
|
(5,525 |
) |
|
30,340 |
|
|
Add Back (Gain) Loss from Financial Derivatives |
|
(12,,468 |
) |
|
46,514 |
|
|
|
(24,291 |
) |
|
55,460 |
|
|
Add Back Non-Recurring Costs1 |
|
3,349 |
|
|
(23,174 |
) |
|
|
3,459 |
|
|
(14,694 |
) |
|
Add Back Impairment Expense |
|
3,032 |
|
|
25,139 |
|
|
|
4,577 |
|
|
35,780 |
|
|
Add Back Dry Hole Expense |
|
2 |
|
|
2 |
|
|
|
13 |
|
|
845 |
|
|
Add Back Non-Cash Compensation Expense |
|
511 |
|
|
1,164 |
|
|
|
571 |
|
|
1,016 |
|
| Less
Gain on Disposal of Assets |
|
(124 |
) |
|
(4,307 |
) |
|
|
(1,959 |
) |
|
(4,295 |
) |
|
Loss From Continuing Operations Before Income Taxes, adjusted |
$ |
(15,301 |
) |
$ |
(7,966 |
) |
|
$ |
(24,550 |
) |
$ |
(29,129 |
) |
|
Less Income Tax Benefit, adjusted2 |
|
6,120 |
|
|
3,186 |
|
|
|
9,820 |
|
|
11,652 |
|
| Adjusted
Net Loss From Continuing Operations |
$ |
(9,181 |
) |
$ |
(4,780 |
) |
|
$ |
(14,730 |
) |
$ |
(17,477 |
) |
|
|
|
|
|
|
|
|
|
|
|
| Basic –
Adjusted Net Loss Per Share |
$ |
(0.93 |
) |
$ |
(0.67 |
) |
|
$ |
(1.50 |
) |
$ |
(2.72 |
) |
| Basic –
Weighted Average Shares of Common Stock Outstanding |
|
9,881 |
|
|
7,180 |
|
|
|
9,825 |
|
|
6,404 |
|
| 1 For the three and nine months ended June 30, 2017, includes
a net $0.1 million of advisory services related to joint venture
drilling programs, and $3.3 million in loss on extinguishment of
debt. For the six months ended June 30, 2017, includes a net $0.4
million of advisory services related to joint venture drilling
programs, and $3.0 million in loss on the extinguishment of debt.
For the three months ended June 30, 2016, includes approximately
$23.7 million in gains on extinguishment of debt and $0.5 million
in debt exchange expenses. For the six months ended June 30, 2016,
includes approximately $23.7 million in gain on extinguishment of
debt and $9.0 million in debt exchange expenses. |
| 2 Assumes an effective tax rate of 40% |
Cash General and Administrative
Expenses
Cash General and Administrative Expenses (Cash
G&A) is the difference between GAAP G&A and non-Cash
G&A, which is primarily comprised of non-cash compensation
expense. Rex Energy has reported Cash G&A because it believes
that this measure is commonly reported and widely used by
management and investors as an indicator of overhead efficiency
without regard to non-cash expenditures, such as stock
compensation. Cash G&A is not a calculation based on GAAP
financial measures and should not be considered as an alternative
to GAAP G&A in measuring the company’s performance. You should
carefully consider the specific items included in the company’s
computation of this measure. You are cautioned that Cash G&A as
reported by Rex Energy may not be comparable in all instances to
that reported by other companies.
To compensate for these limitations, the company
believes it is important to consider both Cash G&A and GAAP
G&A. The following table presents a reconciliation of Rex
Energy’s GAAP G&A to its Cash G&A for each of the periods
presented (in thousands):
|
|
Three Months Ended June
30, |
|
Six Months Ended June
30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
| GAAP
G&A |
$ |
4,294 |
|
$ |
4,837 |
|
$ |
8,828 |
|
$ |
10,121 |
| Non-Cash
Compensation Expense |
514 |
|
1,164 |
|
574 |
|
1,016 |
| Cash
G&A |
$ |
3,780 |
|
$ |
3,673 |
|
$ |
8,254 |
|
$ |
9,105 |
For more information contact:
Investor Relations
(814) 278-7130
InvestorRelations@rexenergycorp.com