Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced third
quarter results for 2016 including the following Q3 highlights:
- Reduced lease operating expenses, excluding ad valorem taxes,
to $40.1 million representing a 3% decrease compared to Q2 2016 and
a 17% decrease compared to Q4 2015
- Closed an additional $8.0 million of asset sales, bringing our
year-to-date as of September 30, 2016 total divestitures to $95.5
million
- Closed on $6.6 million of acquisitions of Permian acreage with
horizontal potential and infrastructure assets to improve our
operational efficiencies in our development program
- Further reduced debt outstanding by $17.0 million
Operational Update
Through Q3 2016, we have spent $18.5 million of
our $37 million 2016 capital budget representing a year to date
spend of 50% of the budgeted total. Approximately 17% was spent on
recompletions and workovers in our East Texas region. The majority
of the balance was deployed in the Permian on workovers and on
horizontal development under our development agreement with an
affiliate of TPG Special Situations Partners (“TSSP”) under which
we operate all wells and fund 5% of the parties' development
capital. Since September 2015, we have drilled and completed 13
horizontal wells under the program: 6 in Lea County, NM, 1 in
Southern Reagan County, TX and 6 in Howard County, TX. In addition,
we are currently in process with another 8 wells under the program
which we expect will be online sometime in late 2016 and early
2017.
2016 Asset Sales Update
Through Q3 2016, we have closed 23 divestitures
generating net proceeds of $95.5 million. Below are the summary
statistics of such sales:
Transaction Statistics:
Total
Sales Price |
$ |
95,485,454 |
|
Transaction Count |
23 |
|
County
Count |
67 |
|
Total Net
Acreage |
72,000 |
|
Midland
Basin Net Acreage |
9,930 |
|
Average
Gross Midland Basin Tract Size (acres) |
184 |
|
Production (Boe/d) (1) |
1,207 |
|
Cash Flow
(1) |
$ |
(588,750 |
) |
Total
Gross Well Count (2) |
914 |
|
YE 2015
PUDs |
3 |
|
$ / Net
Midland Basin Acre (3) |
$ |
7,982 |
|
_______________ |
|
|
|
(1) Estimate based on last twelve months prior to closing each
transaction. |
|
(2) Includes producing, injecting and shut-in wells and PUD
locations. |
|
(3) Calculated as sales price received attributable to Midland
Basin acreage divided by Midland Basin acreage. |
|
|
|
In October, we completed two additional divestments of
properties for approximately $0.6 million, bringing our
year-to-date total to $96.1 million. We do not anticipate any
additional significant asset sales under this initiative.
Capital Structure Update
As announced on October 25, 2016, we recently
drew $60 million of new second lien term loans under a second lien
term loan credit facility with GSO Capital Partners L.P. ("GSO")
providing for term loans up to an aggregate principal amount of
$300.0 million. Proceeds (net of transaction fees and expenses)
from such draw were utilized to repay borrowings under our
revolving credit facility. We may use the remaining $240 million
balance within twelve months of closing for general corporate
purposes and for the repayment of outstanding indebtedness. The
second lien term loan will be issued with an upfront fee of 2% and
bear interest at a rate of 12.00% per annum with a maturity date,
subject to certain conditions, of August 31, 2021.
Through October 31, 2016, we have reduced
our year-end 2015 total debt outstanding by $284.4 million. Our
debt balances as of each of the respective dates are as
follows:
|
12/31/2015 |
9/30/2016 |
10/31/2016 |
|
(In thousands) |
Credit Facility due
2019 (1) |
$ |
608,000 |
|
$ |
516,000 |
|
$ |
448,000 |
|
Second Lien Term Loan
due 2021 (1) (2) |
— |
|
— |
|
60,000 |
|
8% Senior Notes (1)
(2) |
300,000 |
|
232,989 |
|
232,989 |
|
6.625% Senior Notes (1)
(2) |
550,000 |
|
432,656 |
|
432,656 |
|
Total Debt Outstanding
(1) (2) |
$ |
1,458,000 |
|
$ |
1,181,645 |
|
$ |
1,173,645 |
|
_______________ |
(1)
Excludes unamortized financing costs. |
(2)
Excludes unamortized discount. |
|
Given our recently redetermined borrowing base of $600 million,
outstanding borrowings of $448 million and $1.4 million of
outstanding letters of credit, we currently have $150.6 million of
availability under our revolving credit facility.
Near-Term Outlook and
Commentary
Paul T. Horne, Chairman, President and Chief
Executive Officer of Legacy's general partner commented, “Legacy
has continued to take steps to improve our positioning in this
difficult downturn. Our development program with TSSP continues to
deliver strong asset-level results. Despite our minimal capital
spend this year, our employees have been engineering, operating and
supporting a $180 million gross capital program. Their remarkable
execution and ability to drive down costs have sustained us and the
work being done today should bear fruit tomorrow. With the new
addition of GSO’s second lien term loan, we look forward to finding
and taking additional steps to take to enhance equity value.”
|
LEGACY RESERVES LPSELECTED FINANCIAL
AND OPERATING DATA |
|
|
Three Months Ended September
30, |
|
Nine Months Ended September
30, |
|
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
Oil
sales |
$ |
38,751 |
|
|
$ |
49,779 |
|
|
$ |
110,343 |
|
|
$ |
159,188 |
|
Natural
gas liquids sales |
3,457 |
|
|
2,946 |
|
|
9,832 |
|
|
12,867 |
|
Natural
gas sales |
41,332 |
|
|
36,773 |
|
|
102,591 |
|
|
86,783 |
|
Total
revenue |
$ |
83,540 |
|
|
$ |
89,498 |
|
|
$ |
222,766 |
|
|
$ |
258,838 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
$ |
40,118 |
|
|
$ |
45,954 |
|
|
$ |
128,299 |
|
|
$ |
134,726 |
|
Ad
valorem taxes |
$ |
3,003 |
|
|
$ |
2,492 |
|
|
$ |
9,406 |
|
|
$ |
8,160 |
|
Total oil
and natural gas production |
$ |
43,121 |
|
|
$ |
48,446 |
|
|
$ |
137,705 |
|
|
$ |
142,886 |
|
Production and other taxes |
$ |
3,986 |
|
|
$ |
4,834 |
|
|
$ |
9,949 |
|
|
$ |
13,038 |
|
General
and administrative, excluding trans. related costs and LTIP |
$ |
7,490 |
|
|
$ |
8,040 |
|
|
$ |
22,959 |
|
|
$ |
22,345 |
|
Transaction related costs |
$ |
296 |
|
|
$ |
6,502 |
|
|
$ |
1,087 |
|
|
$ |
8,176 |
|
LTIP
expense |
$ |
1,445 |
|
|
$ |
1,704 |
|
|
$ |
5,612 |
|
|
$ |
4,985 |
|
Total
general and administrative |
$ |
9,231 |
|
|
$ |
16,246 |
|
|
$ |
29,658 |
|
|
$ |
35,506 |
|
Depletion, depreciation, amortization and accretion |
$ |
36,068 |
|
|
$ |
45,041 |
|
|
$ |
110,695 |
|
|
$ |
122,306 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
Oil
derivative cash settlements received |
$ |
8,089 |
|
|
$ |
17,092 |
|
|
$ |
30,434 |
|
|
$ |
76,656 |
|
Natural
gas derivative cash settlements received |
$ |
3,524 |
|
|
$ |
9,696 |
|
|
$ |
26,049 |
|
|
$ |
27,658 |
|
Production: |
|
|
|
|
|
|
|
Oil
(MBbls) |
962 |
|
|
1,149 |
|
|
3,070 |
|
|
3,520 |
|
Natural
gas liquids (MGal) |
9,742 |
|
|
10,084 |
|
|
27,646 |
|
|
31,336 |
|
Natural
gas (MMcf) |
16,572 |
|
|
14,383 |
|
|
50,581 |
|
|
33,689 |
|
Total
(MBoe) |
3,956 |
|
|
3,786 |
|
|
12,158 |
|
|
9,881 |
|
Average
daily production (Boe/d) |
43,000 |
|
|
41,152 |
|
|
44,372 |
|
|
36,194 |
|
Average sales price per
unit (excluding derivative cash settlements): |
|
|
|
|
|
|
|
Oil price
(per Bbl) |
$ |
40.28 |
|
|
$ |
43.32 |
|
|
$ |
35.94 |
|
|
$ |
45.22 |
|
Natural
gas liquids price (per Gal) |
$ |
0.35 |
|
|
$ |
0.29 |
|
|
$ |
0.36 |
|
|
$ |
0.41 |
|
Natural
gas price (per Mcf) |
$ |
2.49 |
|
|
$ |
2.56 |
|
|
$ |
2.03 |
|
|
$ |
2.58 |
|
Combined
(per Boe) |
$ |
21.12 |
|
|
$ |
23.64 |
|
|
$ |
18.32 |
|
|
$ |
26.20 |
|
Average sales price per
unit (including derivative cash settlements): |
|
|
|
|
|
|
|
Oil price
(per Bbl) |
$ |
48.69 |
|
|
$ |
58.20 |
|
|
$ |
45.86 |
|
|
$ |
67.00 |
|
Natural
gas liquids price (per Gal) |
$ |
0.35 |
|
|
$ |
0.29 |
|
|
$ |
0.36 |
|
|
$ |
0.41 |
|
Natural
gas price (per Mcf) |
$ |
2.71 |
|
|
$ |
3.23 |
|
|
$ |
2.54 |
|
|
$ |
3.40 |
|
Combined
(per Boe) |
$ |
24.05 |
|
|
$ |
30.71 |
|
|
$ |
22.97 |
|
|
$ |
36.75 |
|
Average WTI oil spot
price (per Bbl) |
$ |
44.85 |
|
|
$ |
46.49 |
|
|
$ |
41.35 |
|
|
$ |
50.94 |
|
Average Henry Hub
natural gas index price (per MMbtu) |
$ |
2.88 |
|
|
$ |
2.76 |
|
|
$ |
2.34 |
|
|
$ |
2.80 |
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
$ |
10.14 |
|
|
$ |
12.14 |
|
|
$ |
10.55 |
|
|
$ |
13.63 |
|
Ad
valorem taxes |
$ |
0.76 |
|
|
$ |
0.66 |
|
|
$ |
0.77 |
|
|
$ |
0.83 |
|
Production and other taxes |
$ |
1.01 |
|
|
$ |
1.28 |
|
|
$ |
0.82 |
|
|
$ |
1.32 |
|
General
and administrative excluding trans. related costs and LTIP |
$ |
1.89 |
|
|
$ |
2.12 |
|
|
$ |
1.89 |
|
|
$ |
2.26 |
|
Total
general and administrative |
$ |
2.33 |
|
|
$ |
4.29 |
|
|
$ |
2.44 |
|
|
$ |
3.59 |
|
Depletion, depreciation, amortization and accretion |
$ |
9.12 |
|
|
$ |
11.90 |
|
|
$ |
9.10 |
|
|
$ |
12.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial and Operating Results - Three-Month Period
Ended September 30, 2016 Compared to Three-Month Period Ended
September 30, 2015
- Production increased 4% to 43,000 Boe/d from 41,152 Boe/d
primarily due to our East Texas acquisitions that only had a
partial quarter contribution to Q3 2015. These increases were
partially offset by declines in our oil production driven by asset
divestitures and natural production declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 11% to $21.12 per Boe in 2016 from
$23.64 per Boe in 2015 driven by the significant decline in
commodity prices as well as the increase of natural gas production
as a percentage of total production. Average realized oil price
decreased 7% to $40.28 in 2016 from $43.32 in 2015 driven by a
decrease in the average West Texas Intermediate ("WTI") crude oil
price of $1.64 per Bbl and worsening regional differentials.
Average realized natural gas price decreased 3% to $2.49 per Mcf in
2016 from $2.56 per Mcf in 2015. This decrease is primarily a
result of the decrease in realized price in our Piceance Basin
properties partially offset by the increase in average Henry Hub
natural gas index price of $0.12 per Mcf and improvements in
regional differentials. Finally, our average realized NGL price
increased 21% to $0.35 per gallon in 2016 from $0.29 per gallon in
2015.
- Production expenses, excluding ad valorem taxes, decreased 13%
to $40.1 million in 2016 from $46.0 million in 2015, primarily due
to cost reduction efforts on historical properties and asset
divestitures, partially offset by production expenses related to
our acquisition of East Texas properties ($5.0 million). On an
average cost per Boe basis, production expenses excluding ad
valorem taxes decreased 16% to $10.14 per Boe in 2016 from $12.14
per Boe in 2015, driven primarily by cost reduction efforts in our
historical properties.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan compensation expense decreased to $7.8
million in 2016 from $14.5 million in 2015, reflecting a reduction
in transaction related costs.
- Cash settlements received on our commodity derivatives during
2016 were $11.6 million compared to $26.8 million in 2015. While
commodity prices were lower in 2016, the decline in cash
settlements received is a result of the reduced nominal volumes
hedges in Q3 2016 compared to Q3 2015 and a lower weighted average
hedge price.
- Total development capital expenditures decreased to $6.9
million in 2016 from $7.9 million in 2015. The 2016 activity was
comprised mainly of the drilling and completion of joint
development agreement wells, East Texas recompletions and workovers
and capital costs related to CO2 properties.
Financial and Operating Results - Nine-Month Period
Ended September 30, 2016 Compared to Nine-Month Period Ended
September 30, 2015
- Production increased 23% to 44,372 Boe/d from 36,194 Boe/d
primarily due to acquisitions in the second half of 2015 including
the acquisition of East Texas properties. These increases were
partially offset by declines in our oil production driven by asset
divestitures and natural production declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 30% to $18.32 per Boe in 2016 from
$26.20 per Boe in 2015 driven by the significant decline in
commodity prices as well as the increase in NGL and natural gas
production as a percentage of total production. Average realized
oil price decreased 21% to $35.94 in 2016 from $45.22 in 2015
driven by a decrease in the average WTI crude oil price of $9.59
per Bbl. Average realized natural gas price decreased 21% to $2.03
per Mcf in 2016 from $2.58 per Mcf in 2015. This decrease is a
result of the decrease in the average Henry Hub natural gas index
price of approximately $0.46 per Mcf. Finally, our average realized
NGL price decreased 12% to $0.36 per gallon in 2016 from $0.41 per
gallon in 2015. This decrease is due to lower commodity
prices.
- Despite additional expenses from our acquisition of East Texas
properties of approximately $19.8 million, our production expenses,
excluding ad valorem taxes, decreased 5% to $128.3 million in 2016
from $134.7 million in 2015. On an average cost per Boe basis,
production expenses decreased 23% to $10.55 per Boe in 2016 from
$13.63 per Boe in 2015. These significant savings were driven
primarily by expense reduction efforts across our historical
property set ($26.2 million) as well as the inclusion of lower cost
natural gas properties acquired in East Texas.
- Non-cash impairment expense totaled $20.1 million driven by the
continued decline in commodities futures prices during 2016 and
well performance.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $24.0 million in 2016 compared to
$30.5 million in 2015, reflecting a reduction in transaction
related costs partially offset by increases in salaries and wages
commensurate with a larger asset base following our acquisition of
East Texas properties.
- Cash settlements received on our commodity derivatives during
2016 were $56.5 million compared to $104.3 million in 2015. While
commodity prices were lower in 2016, the decline in cash
settlements received is a result of the reduced nominal volumes
hedged in Q3 2016 compared to Q3 2015 and a lower weighted average
hedge price.
- Total development capital expenditures decreased to $18.5
million in 2016 from $29.7 million in 2015. The 2016 activity was
comprised mainly of the drilling and completion of joint
development agreement wells, East Texas recompletions and workovers
and capital costs related to CO2 properties.
Commodity Derivative Contracts
We enter into oil and natural gas derivative
contracts to help mitigate the risk of changing commodity prices.
As of October 31, 2016, we had entered into derivative
agreements to receive average NYMEX WTI crude oil prices and NYMEX
Henry Hub, NWPL, SoCal and San Juan natural gas prices as
summarized below.
WTI Crude Oil Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
October-December
2016 |
|
496,800 |
|
|
$ |
54.91 |
|
|
$ |
50.15 |
|
- |
$ |
86.30 |
|
2017 |
|
182,500 |
|
|
$ |
84.75 |
|
|
$ |
84.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil Costless Collars. At an average
WTI market price of $40.00, $50.00 and $60.00, the summary position
below would result in a net price of $45.00, $50.00 and $59.02,
respectively.
|
|
|
|
Average Long |
|
Average Short |
Time Period |
|
Volumes (Bbls) |
|
Put Price per Bbl |
|
Call Price per Bbl |
2017 |
|
2,190,000 |
|
$ |
45.00 |
|
|
$ |
59.02 |
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil 3-Way Collars. At an average WTI market price of
$40.00, the summary positions below would result in a net price of
$65.00 for the remainder of 2016 and 2017:
|
|
|
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
October-December
2016 |
|
115,000 |
|
|
$ |
60.00 |
|
|
$ |
85.00 |
|
|
$ |
102.46 |
|
2017 |
|
72,400 |
|
|
$ |
60.00 |
|
|
$ |
85.00 |
|
|
$ |
104.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil Enhanced Swaps. At an average WTI market price of
$40.00, the summary positions below would result in a net price of
$66.70, $65.85 and $65.50 for the remainder of 2016, 2017 and 2018,
respectively:
|
|
|
|
Average Long Put |
|
Average Short Put |
|
Average Swap |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
October-December
2016 |
|
46,000 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
91.70 |
|
2017 |
|
182,500 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
90.85 |
|
2018 |
|
127,750 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
90.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midland-to-Cushing WTI Crude Oil Differential Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
October-December
2016 |
|
736,000 |
|
|
$ |
(1.60 |
) |
|
$ |
(1.75 |
) |
- |
$ |
(1.50 |
) |
2017 |
|
2,190,000 |
|
|
$ |
(0.30 |
) |
|
$ |
(0.75 |
) |
- |
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps (Henry Hub):
|
|
|
|
Average |
|
Price Range per |
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
MMBtu |
October-December
2016 |
|
12,450,000 |
|
|
$ |
3.00 |
|
|
$ |
2.42 |
|
- |
$ |
4.12 |
|
2017 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2018 |
|
42,200,000 |
|
|
$ |
3.25 |
|
|
$ |
3.04 |
|
- |
$ |
3.39 |
|
2019 |
|
25,800,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Costless Collars (Henry Hub). At an
average Henry Hub market price of $2.50, $3.00 and $3.50, the
summary position below would result in a net price of $2.90, $3.00
and $3.44, respectively.
|
|
|
|
Average Long Put |
|
Average Short Call |
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
2017 |
|
14,600,000 |
|
$ |
2.90 |
|
|
$ |
3.44 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas 3-Way Collars (Henry Hub). At an annual average
Henry Hub market price of $2.50, the summary positions below would
result in a net price of $3.00 for the remainder of 2016 and
2017:
|
|
Volumes |
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
October-December
2016 |
|
1,395,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.08 |
|
2017 |
|
5,040,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps (NWPL, SoCal and San Juan):
|
|
October-December 2016 |
|
2017 |
|
|
|
|
Average |
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
3,764,916 |
|
$ |
(0.19 |
) |
|
7,300,000 |
|
$ |
(0.16 |
) |
SoCal |
|
— |
|
$ |
— |
|
|
2,500,250 |
|
$ |
0.11 |
|
San Juan |
|
628,360 |
|
$ |
(0.16 |
) |
|
2,500,250 |
|
$ |
(0.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Location and quality differentials attributable
to our properties are not reflected in the above prices. The
agreements provide for monthly settlement based on the difference
between the agreement fixed price and the actual reference oil and
natural gas index prices.
Quarterly Report on Form
10-Q
Financial results contained herein are
preliminary and subject to the final, unaudited financial
statements and related footnotes included in Legacy's Form 10-Q
which will be filed on or about November 2, 2016.
Conference Call
As announced on October 25, 2016, Legacy will
host an investor conference call to discuss Legacy's results on
Thursday, November 3, 2016 at 9:00 a.m. (Central Time). Those
wishing to participate in the conference call should dial
877-266-0479. A replay of the call will be available through
Thursday, November 10, 2016, by dialing 855-859-2056 or
404-537-3406 and entering replay code 98590760. Those wishing to
listen to the live or archived web cast via the Internet should go
to the Investor Relations tab of our website at www.LegacyLP.com.
Following our prepared remarks, we will be pleased to answer
questions from securities analysts and institutional portfolio
managers and analysts; the complete call is open to all other
interested parties on a listen-only basis.
Additional Information for Holders of
Legacy Units
Although Legacy has suspended distributions to
both the 8% Series A and Series B Fixed-to-Floating Rate Cumulative
Redeemable Perpetual Preferred Units (the "Preferred Units"), such
distributions continue to accrue. Pursuant to the terms of Legacy's
partnership agreement, Legacy is required to pay or set aside for
payment all accrued but unpaid distributions with respect to the
Preferred Units prior to or contemporaneously with making any
distribution with respect to Legacy's units. Accruals of
distributions on the Preferred Units are treated for tax purposes
as guaranteed payments for the use of capital that will generally
be taxable to the holders of such Preferred Units as ordinary
income even in the absence of contemporaneous distributions.
In addition, Legacy’s unitholders, just like
unitholders of other master limited partnerships, are allocated
taxable income irrespective of cash distributions paid. Because
Legacy’s unitholders are treated as partners that are allocated a
share of Legacy’s taxable income irrespective of the amount of
cash, if any, distributed by Legacy, unitholders will be required
to pay federal income taxes and, in some cases, state and local
income taxes on their share of Legacy’s taxable income, including
its taxable income associated with cancellation of debt ("COD
income") or a disposition of property by Legacy, even if they
receive no cash distributions from Legacy. As of January 21, 2016,
Legacy has suspended all cash distributions to unitholders and
holders of the Preferred Units. Legacy may engage in transactions
to de-lever the Partnership and manage its liquidity that may
result in the allocation of income and gain to its unitholders
without a corresponding cash distribution. For example, during the
nine month period ended September 30, 2016, Legacy closed 23
divestitures generating net proceeds of $95.5 million, and Legacy
may sell additional assets and use the proceeds to repay existing
debt or fund capital expenditure, in which case Legacy’s
unitholders may be allocated taxable income and gain resulting from
the sale, all or a portion of which may be subject to recapture
rules and taxed as ordinary income rather than capital gain,
without receiving a cash distribution. Further, Legacy may pursue
other opportunities to reduce its existing debt, such as debt
exchanges, debt repurchases, or modifications that would result in
COD income being allocated to its unitholders as ordinary taxable
income. The ultimate effect of any income allocations will depend
on the unitholder's individual tax position with respect to its
units, including the availability of any current or suspended
passive losses that may offset some portion of the COD income
allocable to a unitholder. Unitholders are encouraged to consult
their tax advisors with respect to the consequences of potential
transactions that may result in income and gain to unitholders.
Additionally, if Legacy’s unitholders, just like
unitholders of other master limited partnerships, sell any of their
units, they will recognize gain or loss equal to the difference
between the amount realized and their tax basis in those units.
Prior distributions to unitholders that in the aggregate exceeded
the cumulative net taxable income they were allocated for a unit
decreased the tax basis in that unit, and will, in effect, become
taxable income to Legacy’s unitholders if the unit is sold at a
price greater than their tax basis in that unit, even if the price
received is less than original cost. A substantial portion of the
amount realized, whether or not representing gain, may be ordinary
income to Legacy’s unitholders due to the potential recapture
items, including depreciation, depletion and intangible
drilling.
About Legacy Reserves LP
Legacy Reserves LP is a master limited
partnership headquartered in Midland, Texas, focused on the
acquisition and development of oil and natural gas properties
primarily located in the Permian Basin, East Texas, Rocky Mountain
and Mid-Continent regions of the United States. Additional
information is available at www.LegacyLP.com.
Cautionary Statement Relevant to
Forward-Looking Information
This press release contains forward-looking
statements relating to our operations that are based on
management's current expectations, estimates and projections about
its operations. Words such as "anticipates," "expects," "intends,"
"plans," "targets," "projects," "believes," "seeks," "schedules,"
"estimated," and similar expressions are intended to identify such
forward-looking statements. These statements are not guarantees of
future performance and are subject to certain risks, uncertainties
and other factors, some of which are beyond our control and are
difficult to predict. Among the important factors that could cause
actual results to differ materially from those in the
forward-looking statements are: realized oil and natural gas
prices; production volumes, lease operating expenses, general and
administrative costs and finding and development costs; future
operating results and the factors set forth under the heading "Risk
Factors" in our annual and quarterly reports filed with the SEC.
Therefore, actual outcomes and results may differ materially from
what is expressed or forecasted in such forward-looking statements.
The reader should not place undue reliance on these forward-looking
statements, which speak only as of the date of this press release.
Unless legally required, Legacy undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new
information, future events or otherwise.
LEGACY RESERVES LPCONDENSED
CONSOLIDATED STATEMENTS OF
OPERATIONS(UNAUDITED) |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
|
Oil
sales |
|
$ |
38,751 |
|
|
$ |
49,779 |
|
|
$ |
110,343 |
|
|
$ |
159,188 |
|
Natural
gas liquids (NGL) sales |
|
3,457 |
|
|
2,946 |
|
|
9,832 |
|
|
12,867 |
|
Natural
gas sales |
|
41,332 |
|
|
36,773 |
|
|
102,591 |
|
|
86,783 |
|
Total
revenues |
|
83,540 |
|
|
89,498 |
|
|
222,766 |
|
|
258,838 |
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and
natural gas production |
|
43,121 |
|
|
48,446 |
|
|
137,705 |
|
|
142,886 |
|
Production and other taxes |
|
3,986 |
|
|
4,834 |
|
|
9,949 |
|
|
13,038 |
|
General
and administrative |
|
9,231 |
|
|
16,246 |
|
|
29,658 |
|
|
35,506 |
|
Depletion, depreciation, amortization and accretion |
|
36,068 |
|
|
45,041 |
|
|
110,695 |
|
|
122,306 |
|
Impairment of long-lived assets |
|
4,618 |
|
|
98,054 |
|
|
20,065 |
|
|
307,455 |
|
(Gain)
loss on disposal of assets |
|
(8,447 |
) |
|
560 |
|
|
(49,289 |
) |
|
1,567 |
|
Total
expenses |
|
88,577 |
|
|
213,181 |
|
|
258,783 |
|
|
622,758 |
|
|
|
|
|
|
|
|
|
|
Operating
loss |
|
(5,037 |
) |
|
(123,683 |
) |
|
(36,017 |
) |
|
(363,920 |
) |
|
|
|
|
|
|
|
|
|
Other income
(expense): |
|
|
|
|
|
|
|
|
Interest
income |
|
— |
|
|
(55 |
) |
|
54 |
|
|
326 |
|
Interest
expense |
|
(17,080 |
) |
|
(23,351 |
) |
|
(62,558 |
) |
|
(58,903 |
) |
Gain on
extinguishment of debt |
|
— |
|
|
— |
|
|
150,802 |
|
|
— |
|
Equity in
income (loss) of equity method investees |
|
7 |
|
|
(6 |
) |
|
(7 |
) |
|
97 |
|
Net gains
(losses) on commodity derivatives |
|
18,326 |
|
|
57,000 |
|
|
(2,311 |
) |
|
63,982 |
|
Other |
|
(296 |
) |
|
19 |
|
|
(487 |
) |
|
723 |
|
Incomes
(loss) before income taxes |
|
(4,080 |
) |
|
(90,076 |
) |
|
49,476 |
|
|
(357,695 |
) |
Income tax (expense)
benefit |
|
(223 |
) |
|
(1 |
) |
|
(710 |
) |
|
290 |
|
Net
income (loss) |
|
$ |
(4,303 |
) |
|
$ |
(90,077 |
) |
|
$ |
48,766 |
|
|
$ |
(357,405 |
) |
Distributions to Preferred unitholders |
|
(4,750 |
) |
|
(4,750 |
) |
|
(13,458 |
) |
|
(14,250 |
) |
Net
income (loss) attributable to unitholders |
|
$ |
(9,053 |
) |
|
$ |
(94,827 |
) |
|
$ |
35,308 |
|
|
$ |
(371,655 |
) |
|
|
|
|
|
|
|
|
|
Income
(loss) per unit - basic and diluted |
|
$ |
(0.13 |
) |
|
$ |
(1.38 |
) |
|
$ |
0.50 |
|
|
$ |
(5.39 |
) |
Weighted
average number of units used in computing net income (loss) per
unit - |
|
|
|
|
|
|
|
|
Basic and
diluted |
|
72,056 |
|
|
68,945 |
|
|
70,370 |
|
|
68,921 |
|
LEGACY RESERVES LPCONDENSED
CONSOLIDATED BALANCE SHEETS(UNAUDITED) |
|
ASSETS |
|
|
September 30, 2016 |
|
December 31, 2015 |
|
|
(In thousands) |
Current assets: |
|
|
|
|
Cash and
cash equivalents |
|
$ |
2,030 |
|
|
$ |
2,006 |
|
Accounts
receivable, net: |
|
|
|
|
Oil and
natural gas |
|
38,138 |
|
|
33,944 |
|
Joint
interest owners |
|
21,669 |
|
|
25,378 |
|
Other |
|
2 |
|
|
86 |
|
Fair
value of derivatives |
|
26,383 |
|
|
63,711 |
|
Prepaid
expenses and other current assets |
|
8,662 |
|
|
4,334 |
|
Total
current assets |
|
96,884 |
|
|
129,459 |
|
Oil and natural gas
properties using the successful efforts method, at cost: |
|
|
|
|
Proved
properties |
|
3,296,942 |
|
|
3,485,634 |
|
Unproved
properties |
|
13,412 |
|
|
13,424 |
|
Accumulated depletion, depreciation, amortization and
impairment |
|
(2,064,054 |
) |
|
(2,090,102 |
) |
|
|
1,246,300 |
|
|
1,408,956 |
|
Other property and
equipment, net of accumulated depreciation and amortization of
$10,048 and $8,915, respectively |
|
3,751 |
|
|
4,575 |
|
Operating rights, net
of amortization of $5,265 and $4,953, respectively |
|
1,752 |
|
|
2,064 |
|
Fair value of
derivatives |
|
33,250 |
|
|
56,373 |
|
Other assets |
|
9,869 |
|
|
11,047 |
|
Investments in equity
method investees |
|
640 |
|
|
646 |
|
Total assets |
|
$ |
1,392,446 |
|
|
$ |
1,613,120 |
|
LIABILITIES AND PARTNERS' DEFICIT |
Current
liabilities: |
|
|
|
|
Accounts
payable |
|
$ |
5,391 |
|
|
$ |
13,581 |
|
Accrued
oil and natural gas liabilities |
|
53,590 |
|
|
50,573 |
|
Fair
value of derivatives |
|
1,892 |
|
|
2,019 |
|
Asset
retirement obligation |
|
3,496 |
|
|
3,496 |
|
Other |
|
20,662 |
|
|
11,424 |
|
Total
current liabilities |
|
85,031 |
|
|
81,093 |
|
Long-term debt |
|
1,157,490 |
|
|
1,427,614 |
|
Asset retirement
obligation |
|
266,173 |
|
|
282,909 |
|
Fair value of
derivatives |
|
2,059 |
|
|
— |
|
Other long-term
liabilities |
|
643 |
|
|
1,181 |
|
Total liabilities |
|
1,511,396 |
|
|
1,792,797 |
|
Commitments and
contingencies |
|
|
|
|
Partners' equity |
|
|
|
|
Series A
Preferred equity - 2,300,000 units issued and outstanding at
September 30, 2016 and December 31, 2015 |
|
55,192 |
|
|
55,192 |
|
Series B
Preferred equity - 7,200,000 units issued and outstanding at
September 30, 2016 and December 31, 2015 |
|
174,261 |
|
|
174,261 |
|
Incentive
distribution equity - 100,000 units issued and outstanding at
September 30, 2016 and December 31, 2015 |
|
30,814 |
|
|
30,814 |
|
Limited
partners' deficit - 72,055,697 and 68,949,961 units issued and
outstanding at September 30, 2016 and December 31, 2015,
respectively |
|
(379,098 |
) |
|
(439,811 |
) |
General
partner's deficit (approximately 0.03%) |
|
(119 |
) |
|
(133 |
) |
Total
partners' deficit |
|
(118,950 |
) |
|
(179,677 |
) |
Total liabilities and
partners' deficit |
|
$ |
1,392,446 |
|
|
$ |
1,613,120 |
|
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
This press release, the financial tables and
other supplemental information include "Adjusted EBITDA" and
"Distributable Cash Flow", both of which are non-generally accepted
accounting principles ("non-GAAP") measures which may be used
periodically by management when discussing our financial results
with investors and analysts. The following presents a
reconciliation of each of these non-GAAP financial measures to
their nearest comparable generally accepted accounting principles
("GAAP") measure.
Adjusted EBITDA and Distributable Cash Flow are
presented as management believes they provide additional
information concerning the performance of our business and are used
by investors and financial analysts to analyze and compare our
current operating and financial performance relative to past
performance and such performances relative to that of other
publicly traded partnerships in the industry. Adjusted EBITDA and
Distributable Cash Flow may not be comparable to similarly titled
measures of other publicly traded limited partnerships or limited
liability companies because all companies may not calculate such
measures in the same manner.
Distributable Cash Flow is one of the factors
used by the board of directors of our general partner (the “Board”)
to help determine the amount of Available Cash as defined in our
partnership agreement, that is to be distributed to our unitholders
for such period. Under our partnership agreement, Available Cash is
defined generally to mean, cash on hand at the end of each quarter,
plus working capital borrowings made after the end of the quarter,
less cash reserves determined by our general partner. The Board
determines whether to increase, maintain or decrease the current
level of distributions in accordance with the provisions of our
partnership agreement based on a variety of factors, including
without limitation, Distributable Cash Flow, cash reserves
established in prior periods, reserves established for future
periods, borrowing capacity for working capital, temporary,
one-time or uncharacteristic historical results, and forecasts of
future period results including the impact of pending acquisitions.
Management and the Board consider the long-term view of expected
results in determining the amount of its distributions. Certain
factors impacting Adjusted EBITDA and Distributable Cash Flow may
be viewed as temporary, one-time in nature, or being offset by
reserves from past performance or near-term future performance.
Financial results are also driven by various factors that do not
typically occur evenly throughout the year that are difficult to
predict, including rig availability, weather, well performance, the
timing of drilling and completions and near-term commodity price
changes. Consistent with practices common to publicly traded
partnerships, the Board historically has not varied the
distribution it declares based on such timing effects.
"Adjusted EBITDA" and "Distributable Cash Flow"
should not be considered as alternatives to GAAP measures, such as
net income, operating income, cash flow from operating activities,
or any other GAAP measure of financial performance.
The following table presents a reconciliation of our
consolidated net income (loss) to Adjusted EBITDA and Distributable
Cash Flow:
|
Three Months Ended |
|
Nine Months Ended |
|
September 30, |
|
September 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands) |
Net income
(loss) |
$ |
(4,303 |
) |
|
$ |
(90,077 |
) |
|
$ |
48,766 |
|
|
$ |
(357,405 |
) |
Plus: |
|
|
|
|
|
|
|
Interest
expense |
17,080 |
|
|
23,351 |
|
|
62,558 |
|
|
58,903 |
|
Gain on
extinguishment of debt |
— |
|
|
— |
|
|
(150,802 |
) |
|
— |
|
Income
tax expense (benefit) |
223 |
|
|
1 |
|
|
710 |
|
|
(290 |
) |
Depletion, depreciation, amortization and accretion |
36,068 |
|
|
45,041 |
|
|
110,695 |
|
|
122,306 |
|
Impairment of long-lived assets |
4,618 |
|
|
98,054 |
|
|
20,065 |
|
|
307,455 |
|
(Gain)
loss on disposal of assets |
(8,447 |
) |
|
560 |
|
|
(49,289 |
) |
|
1,567 |
|
Equity in
(income) loss of equity method investees |
(7 |
) |
|
6 |
|
|
7 |
|
|
(97 |
) |
Unit-based compensation expense |
1,445 |
|
|
1,704 |
|
|
5,612 |
|
|
4,985 |
|
Minimum
payments received in excess of overriding royalty interest
earned(1) |
423 |
|
|
386 |
|
|
1,225 |
|
|
1,130 |
|
Equity in
EBITDA of equity method investee(2) |
— |
|
|
— |
|
|
— |
|
|
169 |
|
Net
(gains) losses on commodity derivatives |
(18,326 |
) |
|
(57,000 |
) |
|
2,311 |
|
|
(63,983 |
) |
Net cash
settlements received on commodity derivatives |
11,613 |
|
|
26,788 |
|
|
56,483 |
|
|
104,314 |
|
Transaction related expenses |
296 |
|
|
6,502 |
|
|
1,087 |
|
|
8,175 |
|
Adjusted
EBITDA |
$ |
40,683 |
|
|
$ |
55,316 |
|
|
$ |
109,428 |
|
|
$ |
187,229 |
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
Cash
interest expense |
17,454 |
|
|
18,632 |
|
|
54,181 |
|
|
52,624 |
|
Development capital expenditures(3) |
6,866 |
|
|
7,881 |
|
|
18,542 |
|
|
29,663 |
|
Distributions on Series A and Series B preferred units |
— |
|
|
4,750 |
|
|
— |
|
|
14,250 |
|
Distributable
Cash Flow |
$ |
16,363 |
|
|
$ |
24,053 |
|
|
$ |
36,705 |
|
|
$ |
90,692 |
|
|
(1) Minimum payments received in excess of overriding
royalties earned under a contractual agreement expiring December
31, 2019. The remaining amount of the minimum payments is
recognized in net income. |
(2) Equity in EBITDA of equity method investee is defined as
the equity method investee's net income or loss plus interest
expense and depreciation. We divested our interest in this investee
in May of 2015. |
(3) Represents total capital expenditures for the development
of oil and natural gas properties as presented on an accrual basis.
For 2016, we intend to fund our total oil and natural gas
development program from net cash provided by operating
activities. |
CONTACT:
Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200
Legacy Reserves Inc. (MM) (NASDAQ:LGCY)
Historical Stock Chart
From Mar 2024 to Apr 2024
Legacy Reserves Inc. (MM) (NASDAQ:LGCY)
Historical Stock Chart
From Apr 2023 to Apr 2024