DELAWARE | 001-33756 | 61-1521161 | ||
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
EXHIBIT NUMBER | DESCRIPTION | |
Exhibit 99.1 | Press Release dated March 4, 2016 |
VANGUARD NATURAL RESOURCES, LLC | ||||||
By: | /s/ Richard A. Robert | |||||
Name: | Richard A. Robert | |||||
Title: | Executive Vice President and Chief Financial Officer | |||||
March 4, 2016 | (Principal Financial Officer and Principal Accounting Officer) |
EXHIBIT NUMBER | DESCRIPTION | |
Exhibit 99.1 | Press Release dated March 4, 2016 |
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
($ in thousands, except per unit data) | ||||||||||||||||
Production (Mcfe/d) | 511,119 | 402,164 | 415,343 | 327,109 | ||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 111,665 | $ | 156,727 | $ | 397,227 | $ | 624,613 | ||||||||
Net gains on commodity derivative contracts | $ | 66,855 | $ | 174,576 | $ | 169,416 | $ | 163,452 | ||||||||
Operating expenses | $ | 54,721 | $ | 51,970 | $ | 187,230 | $ | 194,389 | ||||||||
Selling, general and administrative expenses | $ | 28,837 | $ | 7,797 | $ | 55,076 | $ | 30,839 | ||||||||
Depreciation, depletion, amortization, and accretion | $ | 64,676 | $ | 76,139 | $ | 247,119 | $ | 226,937 | ||||||||
Impairment of oil and natural gas properties | $ | 484,855 | $ | 234,434 | $ | 1,842,317 | $ | 234,434 | ||||||||
Goodwill impairment loss | $ | 71,425 | $ | — | $ | 71,425 | $ | — | ||||||||
Net income (loss) attributable to Common and Class B Unitholders | $ | (515,111 | ) | $ | (66,828 | ) | $ | (1,909,933 | ) | $ | 46,148 | |||||
Adjusted Net Income Available to Common and Class B Unitholders (1) | $ | 62,982 | $ | 16,109 | $ | 75,977 | $ | 90,593 | ||||||||
Adjusted Net Income Available to Common and Class B Unitholders, per unit (1) | $ | 0.49 | $ | 0.19 | $ | 0.78 | $ | 1.10 | ||||||||
Adjusted EBITDA(1) | $ | 132,707 | $ | 125,647 | $ | 396,829 | $ | 421,445 | ||||||||
Interest expense, including settlements paid on interest rate derivatives | $ | 28,139 | $ | 21,245 | $ | 92,800 | $ | 73,800 | ||||||||
Estimated maintenance capital expenditures | $ | 32,426 | $ | 23,811 | $ | 112,639 | $ | 116,528 | ||||||||
Distributions to Preferred Unitholders | $ | 6,689 | $ | 6,690 | $ | 26,759 | $ | 18,197 | ||||||||
Distributable Cash Flow Available to Common and Class B Unitholders (1) | $ | 65,453 | $ | 73,901 | $ | 164,631 | $ | 214,870 | ||||||||
Distributable Cash Flow per Common and Class B unit (1) | $ | 0.50 | $ | 0.88 | $ | 1.78 | $ | 2.61 | ||||||||
Common and Class B units distribution coverage (1) | 2.82x | 1.40x | 1.44x | 1.04x | ||||||||||||
Weighted average Common and Class B units outstanding at record date attributable to distribution period | 130,896 | 83,962 | 92,461 | 82,238 |
(1) | Non-GAAP financial measures. Please see Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. Supplemental information on Vanguard's financial and operations results, including Adjusted Net Income Available to Common and Class B Unitholders, can be found under "Presentations" on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com. |
• | Successfully closed the LRR Energy, L.P. and the Eagle Rock Energy Partners, L.P. mergers during the fourth quarter of 2015. |
• | Reported average production of 511,119 Mcfe per day in the fourth quarter of 2015 was up 27% compared to 402,164 Mcfe per day produced in the fourth quarter of 2014 and a 32% increase compared to the third quarter of 2015. On a Mcfe basis, crude oil, natural gas and NGLs accounted for 18%, 64%, and 18% of our production, respectively. |
• | Adjusted EBITDA (a non-GAAP financial measure defined below) increased 6% to $132.7 million from $125.6 million in the fourth quarter of 2014 and increased 50% compared to the $88.2 million recorded in the third quarter of 2015. |
• | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 11% to $65.5 million compared to the $73.9 million generated in the fourth quarter of 2014 and increased 109% from the $31.3 million generated in the third quarter of 2015. |
• | We reported a net loss attributable to Common and Class B Unitholders for the quarter of $515.1 million or $(4.02) per basic unit after deducting distributions to Preferred Unitholders compared to a net loss of $66.8 million or $(0.80) per basic unit in the fourth quarter of 2014. |
• | Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $63.0 million in the fourth quarter of 2015, or $0.49 per basic unit, as compared to $16.1 million, or $0.19 per basic unit, in the fourth quarter of 2014. The recent quarter includes net non-cash expenses of $566.4 million that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders. The 2015 adjustments include a $484.9 million impairment charge on our oil and natural gas properties, a $71.4 million goodwill impairment loss and a $43.6 million loss from the change in fair value of commodity derivative contracts, offset by a $40.8 million net gain from our acquisitions and mergers. The fourth quarter of 2014 results include net non-cash expenses of $82.5 million. |
Three Months Ended December 31,(a) | Percentage Increase / (Decrease) | Three Months Ended September 30,(a) | Percentage Increase / (Decrease) | |||||||||||||||
2015 | 2014 | 2015 | ||||||||||||||||
Average realized prices, excluding hedges: | ||||||||||||||||||
Oil (Price/Bbl) | $ | 34.85 | $ | 63.39 | (45 | )% | $ | 40.10 | (13 | )% | ||||||||
Natural Gas (Price/Mcf) | $ | 1.57 | $ | 3.19 | (51 | )% | $ | 1.94 | (19 | )% | ||||||||
NGLs (Price/Bbl) | $ | 10.08 | $ | 17.37 | (42 | )% | $ | 8.86 | 14 | % | ||||||||
Average realized prices, including hedges (b): | ||||||||||||||||||
Oil (Price/Bbl) | $ | 59.35 | $ | 78.97 | (25 | )% | $ | 53.66 | 11 | % | ||||||||
Natural Gas (Price/Mcf) | $ | 3.12 | $ | 3.52 | (11 | )% | $ | 3.17 | (2 | )% | ||||||||
NGLs (Price/Bbl) | $ | 12.62 | $ | 18.22 | (31 | )% | $ | 11.23 | 12 | % | ||||||||
Average NYMEX prices: | ||||||||||||||||||
Oil (Price/Bbl) | $ | 42.08 | $ | 72.68 | (42 | )% | $ | 46.39 | (9 | )% | ||||||||
Natural Gas (Price/Mcf) | $ | 2.23 | $ | 3.99 | (44 | )% | $ | 2.77 | (19 | )% | ||||||||
Total production volumes: | ||||||||||||||||||
Oil (MBbls) | 1,454 | 907 | 60 | % | 839 | 73 | % | |||||||||||
Natural Gas (MMcf) | 29,970 | 26,386 | 14 | % | 26,242 | 14 | % | |||||||||||
NGLs (MBbls) | 1,387 | 862 | 61 | % | 717 | 93 | % | |||||||||||
Combined (MMcfe) | 47,023 | 36,999 | 27 | % | 35,574 | 32 | % | |||||||||||
Average daily production volumes: | ||||||||||||||||||
Oil (Bbls/day) | 15,810 | 9,857 | 60 | % | 9,115 | 73 | % | |||||||||||
Natural Gas (Mcf/day) | 325,754 | 286,805 | 14 | % | 285,236 | 14 | % | |||||||||||
NGLs (Bbls/day) | 15,084 | 9,369 | 61 | % | 7,792 | 93 | % | |||||||||||
Combined (Mcfe/day) | 511,119 | 402,164 | 27 | % | 386,679 | 32 | % |
(a) | During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
(b) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
• | Implemented a successful cost reduction initiative in which we reduced the lease operating expenses on our operated properties by approximately $20.6 million, or 20%, during 2015. |
• | Reported average production of 415,343 Mcfe per day in 2015 was up 27% compared to 327,109 Mcfe per day produced in 2014. On a Mcfe basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 16%, 70% and 14% of our production, respectively. |
• | Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 6% to $396.8 million from the $421.4 million generated in 2014. |
• | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 23% to $164.6 million from the $214.9 million generated in 2014. |
• | We reported a net loss attributable to Common and Class B unitholders for the year ended December 31, 2015 of $1.9 billion or $(19.80) per basic unit compared to a net income of $46.1 million or $0.56 per basic unit in the year ended December 31, 2014. |
• | Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $76.0 million in 2015, or $0.78 per unit, compared to $90.6 million, or $1.10 per unit, in 2014. The 2015 results include net non-cash losses of $2.0 billion that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders. The 2015 adjustments include a $1.8 billion impairment charge on our oil and natural gas properties, a $71.4 million goodwill impairment loss and a $61.6 million loss from the change in fair value of commodity derivative contracts, offset by a $40.5 million net gain on acquisitions and mergers. The 2014 results include non-cash losses of $43.7 million. |
Year Ended December 31, (a) | Percentage Increase (Decrease) | ||||||||||
2015 | 2014 | ||||||||||
Average realized prices, excluding hedging: | |||||||||||
Oil (Price/Bbl) | $ | 40.94 | $ | 81.40 | (50 | )% | |||||
Natural Gas (Price/Mcf) | $ | 1.81 | $ | 3.44 | (47 | )% | |||||
NGLs (Price/Bbl) | $ | 11.35 | $ | 25.55 | (56 | )% | |||||
Average realized prices, including hedging (b): | |||||||||||
Oil (Price/Bbl) | $ | 56.89 | $ | 82.88 | (31 | )% | |||||
Natural Gas (Price/Mcf) | $ | 3.13 | $ | 3.50 | (11 | )% | |||||
NGLs (Price/Bbl) | $ | 13.68 | $ | 25.62 | (47 | )% | |||||
Average NYMEX prices: | |||||||||||
Oil (Price/Bbl) | $ | 47.79 | $ | 92.21 | (48 | )% | |||||
Natural Gas (Price/Mcf) | $ | 2.64 | $ | 4.39 | (40 | )% | |||||
Total production volumes: | |||||||||||
Oil (MBbls) | 4,008 | 3,301 | 21 | % | |||||||
Natural Gas (MMcf) | 106,615 | 83,037 | 28 | % | |||||||
NGLs (MBbls) | 3,489 | 2,759 | 26 | % | |||||||
Combined (MMcfe) | 151,600 | 119,395 | 27 | % | |||||||
Average daily production volumes: | |||||||||||
Oil (Bbls/day) | 10,982 | 9,043 | 21 | % | |||||||
Natural Gas (Mcf/day) | 292,095 | 227,498 | 28 | % | |||||||
NGLs (Bbls/day) | 9,560 | 7,559 | 26 | % | |||||||
Combined (Mcfe/day) | 415,343 | 327,109 | 27 | % |
(a) | During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
(b) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
Bcfe | |||
Reserves at December 31, 2014 | 2,031.3 | ||
Performance revisions | 415.9 | ||
Revisions of previous estimates due to price | (587.3 | ) | |
Extensions, discoveries and other | 54.5 | ||
Purchases of reserves in place | 527.5 | ||
Sales of reserves-in-place | (1.4 | ) | |
Production | (151.6 | ) | |
Reserves at December 31, 2015 | 2,288.9 |
Year 2016 | Year 2017 | |||||||
Gas Production Hedged: | ||||||||
% Anticipated Production Hedged | 78 | % | 49 | % | ||||
Weighted Average Price ($/MMBtu) | $ | 4.15 | $ | 3.84 | ||||
Oil Production Hedged: | ||||||||
% Anticipated Production Hedged | 67 | % | 21 | % | ||||
Weighted Average Price ($/Bbl) | $ | 67.52 | $ | 84.13 | ||||
NGLs Production Hedged: | ||||||||
% Anticipated Production Hedged | 22 | % | — | |||||
Weighted Average Price ($/Bbl) | $ | 30.31 | $ | — |
FY 2016E | FY 2015 | |||||||||||
Net Production: | ||||||||||||
Oil (Bbls/d) | 12,800 | - | 14,200 | 10,982 | ||||||||
Natural gas (Mcf/d) | 280,000 | - | 310,000 | 292,095 | ||||||||
Natural gas liquids (Bbls/d) | 10,800 | - | 12,000 | 9,560 | ||||||||
Total (Mcfe/d) | 421,600 | 467,200 | 415,343 | |||||||||
Costs: | ||||||||||||
Lease operating expenses | $ | 162,500 | - | $ | 179,000 | $146,654 | ||||||
Production taxes | $ | 35,000 | - | $ | 38,000 | $40,576 | ||||||
G&A expenses (excluding non-cash compensation) | $ | 40,000 | - | $ | 42,000 | $36,554 | ||||||
Depreciation, depletion, amortization and accretion | $ | 210,000 | - | $ | 245,000 | $247,119 | ||||||
Costs per Mcfe: | ||||||||||||
Lease operating expenses | $ | 1.00 | - | $ | 1.10 | $0.97 | ||||||
Production taxes (% of revenue) | 11.0 | % | - | 12.0 | % | 10.2% | ||||||
G&A expenses (excluding non-cash compensation) | $ | 0.24 | - | $ | 0.26 | $0.24 | ||||||
Depreciation, depletion, amortization and accretion | $ | 1.30 | - | $ | 1.50 | $1.63 | ||||||
Cash Flow Calculation (in thousands): | ||||||||||||
Adjusted EBITDA (1) | $360,000 | $396,829 | ||||||||||
Interest expense, including settlements paid on interest rate derivatives | $(105,000) | $(92,800) | ||||||||||
Capital expenditures (2) | $(63,000) | $(112,638) | ||||||||||
Distributions to Preferred Unitholders (3) | $(2,230) | $(26,759) | ||||||||||
Distributable cash flow | $189,770 | $164,632 | ||||||||||
Excess of net cash after distributions to unitholders (4) | $145,000 | $50,443 | ||||||||||
Mid-point adjusted net income per unit (1) | $0.10 | $0.78 | ||||||||||
Units outstanding (millions) | 131.1 | 92.5 | ||||||||||
Assumed NYMEX Pricing (February 29, 2016) (5): | Q1 2016 | Q2 2016 | Q3 2016 | Q4 2016 | ||||||||
Oil ($/Bbl) | $31.20 | $35.48 | $38.48 | $40.08 | ||||||||
Natural gas ($/MMBtu) | $2.09 | $1.80 | $2.02 | $2.26 | ||||||||
Average NYMEX Differentials: | ||||||||||||
Oil ($/Bbl) | $(7.50) | $(7.50) | $(7.50) | $(7.50) | ||||||||
Natural gas ($/MMBtu) | $(0.80) | $(0.80) | $(0.80) | $(0.80) | ||||||||
NGL realization as a percentage of crude oil NYMEX price (6) | 24% | 22% | 22% | 22% | ||||||||
Capital Expenditures Details (in thousands): | Q1 2016 | Q2 2016 | Q3 2016 | Q4 2016 | ||||||||
Operated | $(4,000) | $(7,500) | $(6,500) | $(5,500) | ||||||||
Non-Operated | $(15,500) | $(12,500) | $(6,000) | $(5,500) | ||||||||
Total Capital Expenditures | $(19,500) | $(20,000) | $(12,500) | $(11,000) |
(1) | Adjusted EBITDA and adjusted net income exclude the amortization of value on derivative contracts acquired (approximately $16.7 million for the FY 2016). |
(2) | Additional detail regarding the capital breakout by quarter is listed below. |
(3) | Reflects current monthly preferred distributions are suspended effective with the February 2016 distribution, which would have been paid in April 2016. |
(4) | Excess of net cash after distributions is net of any expected working capital adjustments and cash reserves and does not consider the payment of any accrued preferred distributions. |
(5) | NYMEX pricing includes actual settlements for January and February 2016. |
(6) | Assumes a weighted average product breakout of 24% ethane, 35% propane, 14% isobutane, 10% n-butane and 17% pentane. |
• | Net interest expense; |
• | Depreciation, depletion, amortization, and accretion; |
• | Impairment of oil and natural gas properties; |
• | Goodwill impairment loss; |
• | Net gains or losses on commodity derivative contracts; |
• | Cash settlements on matured commodity derivative contracts; |
• | Net gains or losses on interest rate derivative contracts; |
• | Net gains and losses on acquisitions of oil and natural gas properties; |
• | Texas margin taxes; |
• | Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and |
• | Transaction costs incurred on acquisitions. |
• | Depreciation, depletion, amortization, and accretion; |
• | Impairment of oil and natural gas properties; |
• | Goodwill impairment loss; |
• | Net gains or losses on commodity derivative contracts; |
• | Cash settlements on matured commodity derivative contracts; |
• | Texas margin taxes; |
• | Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and |
• | Transaction costs incurred on acquisitions; |
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) | $ | (508,422 | ) | $ | (60,138 | ) | $ | (1,883,174 | ) | $ | 64,345 | |||||
Plus: | ||||||||||||||||
Interest expense | 25,880 | 20,236 | 87,573 | 69,765 | ||||||||||||
Depreciation, depletion, amortization and accretion | 64,676 | 76,139 | 247,119 | 226,937 | ||||||||||||
Impairment of oil and natural gas properties | 484,855 | 234,434 | 1,842,317 | 234,434 | ||||||||||||
Goodwill impairment loss | 71,425 | — | 71,425 | — | ||||||||||||
Net gains on commodity derivative contracts | (66,855 | ) | (174,577 | ) | (169,416 | ) | (163,452 | ) | ||||||||
Net cash settlements paid on matured commodity derivative contracts (b)(c) | 85,735 | 23,534 | 211,723 | 10,187 | ||||||||||||
Net (gains) losses on interest rate derivative contracts (d) | (2,444 | ) | 865 | (153 | ) | 1,933 | ||||||||||
Net gains on acquisitions of oil and natural gas properties | (40,817 | ) | — | (40,533 | ) | (34,523 | ) | |||||||||
Texas margin taxes | 114 | (505 | ) | (266 | ) | (630 | ) | |||||||||
Compensation related items | 6,868 | 5,270 | 18,522 | 11,710 | ||||||||||||
Transaction costs incurred on acquisitions | 11,692 | 389 | 11,692 | 739 |
Adjusted EBITDA | $ | 132,707 | $ | 125,647 | $ | 396,829 | $ | 421,445 | ||||||||
Less: | ||||||||||||||||
Interest expense, including settlements paid on interest rate derivatives | (28,139 | ) | (21,245 | ) | (92,800 | ) | (73,800 | ) | ||||||||
Estimated maintenance capital expenditures (e) | (32,426 | ) | (23,811 | ) | (112,639 | ) | (116,528 | ) | ||||||||
Distributions to Preferred Unitholders | (6,689 | ) | (6,690 | ) | (26,759 | ) | (18,197 | ) | ||||||||
Proceeds from sale of leasehold interests | — | — | — | 1,950 | ||||||||||||
Distributable Cash Flow Available to Common and Class B Unitholders | $ | 65,453 | $ | 73,901 | $ | 164,631 | $ | 214,870 | ||||||||
Distributions to Common and Class B Unitholders | 23,234 | 52,896 | 114,189 | 207,035 | ||||||||||||
Excess of distributable cash flow after distributions to Unitholders | $ | 42,219 | $ | 21,005 | $ | 50,442 | $ | 7,835 | ||||||||
Distributable Cash Flow per Common and Class B unit | $ | 0.50 | $ | 0.88 | $ | 1.78 | $ | 2.61 | ||||||||
Common and Class B unit Distribution Coverage | 2.82x | 1.40x | 1.44x | 1.04x | ||||||||||||
(a) Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. | ||||||||||||||||
(b) Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties. | $ | 810 | $ | — | $ | 5,434 | $ | — | ||||||||
(c) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties. | $ | 12,027 | $ | 4,834 | $ | 44,761 | $ | 21,306 | ||||||||
(d) Includes settlements paid on interest rate derivatives | $ | 2,259 | $ | 1,009 | $ | 5,227 | $ | 4,035 | ||||||||
(e) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in production from the prior year due to the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production on both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all. |
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