e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR
THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005 |
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO |
Commission file number 0-29370
ULTRA PETROLEUM CORP.
(Exact name of registrant as specified in its charter)
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Yukon Territory, Canada
(State or other jurisdiction of
incorporation or organization)
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N/A
(I.R.S. employer
identification number) |
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363 North Sam Houston Parkway, Suite 1200, Houston, Texas
(Address of principal executive offices)
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77060
(Zip code) |
(281) 876-0120
(Registrants telephone number,
including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
YES þ NO o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2
of the Exchange Act)
YES þ NO o
The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of October
28, 2005 was 154,564,636.
TABLE OF CONTENTS
PART 1 FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
(Expressed in U.S. Dollars)
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
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For the Three Months Ended |
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For the Nine Months Ended |
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September 30, |
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September 30, |
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2005 |
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2004 |
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2005 |
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2004 |
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Revenues: |
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Natural gas sales |
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$ |
110,665,181 |
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$ |
54,786,316 |
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$ |
266,692,797 |
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$ |
144,037,747 |
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Oil sales |
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22,930,586 |
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11,655,129 |
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65,242,557 |
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17,132,761 |
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Total operating revenues |
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133,595,767 |
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66,441,445 |
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331,935,354 |
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161,170,508 |
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Expenses: |
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Production expenses and taxes |
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21,935,202 |
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12,598,587 |
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56,516,402 |
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31,747,884 |
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Depletion and depreciation |
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13,270,825 |
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7,708,282 |
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37,166,738 |
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18,604,987 |
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General and administrative |
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2,758,533 |
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1,562,379 |
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8,440,487 |
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4,306,767 |
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General and administrative stock compensation |
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1,261,173 |
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150,050 |
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2,271,832 |
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773,573 |
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Total operating expenses |
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39,225,733 |
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22,019,298 |
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104,395,459 |
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55,433,211 |
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Operating income |
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94,370,034 |
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44,422,147 |
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227,539,895 |
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105,737,297 |
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Other income (expense): |
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Interest expense |
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(787,604 |
) |
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(853,469 |
) |
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(2,856,011 |
) |
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(2,802,381 |
) |
Interest income |
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177,463 |
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20,054 |
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371,020 |
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42,698 |
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Total other income (expense) |
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(610,141 |
) |
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(833,415 |
) |
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(2,484,991 |
) |
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(2,759,683 |
) |
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Income, before income tax provision |
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93,759,893 |
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43,588,732 |
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225,054,904 |
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102,977,614 |
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Income tax provision |
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32,909,724 |
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15,713,358 |
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78,994,271 |
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36,796,518 |
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Net income |
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60,850,169 |
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27,875,374 |
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146,060,633 |
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66,181,096 |
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Retained earnings, beginning of period |
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250,498,775 |
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94,444,238 |
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165,288,311 |
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56,138,516 |
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Retained earnings, end of period |
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$ |
311,348,944 |
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$ |
122,319,612 |
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$ |
311,348,944 |
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$ |
122,319,612 |
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Income per common share basic |
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$ |
0.40 |
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$ |
0.19 |
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$ |
0.96 |
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$ |
0.44 |
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Income per common share fully diluted |
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$ |
0.38 |
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$ |
0.17 |
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$ |
0.90 |
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$ |
0.41 |
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Weighted average common shares outstanding basic |
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153,719,760 |
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150,127,868 |
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152,515,660 |
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149,858,392 |
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Weighted average common shares outstanding fully diluted |
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162,231,248 |
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160,181,814 |
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161,538,906 |
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159,914,880 |
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2
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Expressed in U.S. Dollars)
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Nine Months Ended |
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September 30, |
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2005 |
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2004 |
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Cash provided by (used in): |
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Operating activities: |
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Net income |
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$ |
146,060,633 |
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$ |
66,181,096 |
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Add (deduct) items not involving cash: |
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Depletion and depreciation |
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37,166,738 |
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18,604,987 |
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Deferred income taxes |
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78,994,271 |
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36,796,518 |
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Stock compensation |
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2,271,832 |
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773,573 |
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Net changes in non-cash working capital: |
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Restricted cash |
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(1,399 |
) |
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(948 |
) |
Accounts receivable |
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(7,127,575 |
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(11,882,168 |
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Inventory |
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(292,776 |
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(457,656 |
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Prepaid expenses and other current assets |
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644,321 |
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(2,795,440 |
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Accounts payable and accrued liabilities |
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16,708,441 |
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1,783,174 |
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Other long-term obligations |
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4,474,803 |
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7,318,786 |
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Deferred revenue |
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137,500 |
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3,436,624 |
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Taxation payable |
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(195,000 |
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Cash provided by operating activities |
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278,841,789 |
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119,758,546 |
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Investing activities: |
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Oil and gas property expenditures |
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(188,197,911 |
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(130,371,223 |
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Oil and gas property expenditures in accounts payable |
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(3,604,699 |
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11,331,477 |
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Inventory |
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(18,938,712 |
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6,280,929 |
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Purchase of capital assets |
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(881,165 |
) |
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(672,524 |
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Cash used in investing activities |
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(211,622,487 |
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(113,431,341 |
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Financing activities: |
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Borrowings on long-term debt, gross |
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22,000,000 |
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32,000,000 |
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Payments on long-term debt, gross |
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(99,000,000 |
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(29,000,000 |
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Proceeds from exercise of options |
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16,051,102 |
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1,333,683 |
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Cash provided by (used in) financing activities |
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(60,948,898 |
) |
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4,333,683 |
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Increase in cash during the period |
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6,270,404 |
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10,660,888 |
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Cash and cash equivalents, beginning of period |
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16,932,661 |
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1,834,112 |
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Cash and cash equivalents, end of period |
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$ |
23,203,065 |
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$ |
12,495,000 |
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Supplemental disclosures of cash flow information
Non-cash tax benefit of stock options exercised |
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$ |
39,352,436 |
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$ |
1,782,866 |
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3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Expressed in U.S. Dollars)
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September 30, |
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December 31, |
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2005 |
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2004 |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
23,203,065 |
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$ |
16,932,661 |
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Restricted cash |
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213,360 |
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211,961 |
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Accounts receivable |
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42,876,862 |
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35,749,287 |
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Deferred tax asset |
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2,076,737 |
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1,327,489 |
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Inventory |
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24,646,125 |
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5,180,024 |
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Prepaid expenses and other current assets |
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1,081,522 |
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1,725,843 |
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Total current assets |
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94,097,671 |
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61,127,265 |
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Oil and gas properties, using the full cost method of accounting |
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Proved |
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526,042,611 |
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385,794,926 |
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Unproved |
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100,376,478 |
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88,839,460 |
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Capital assets |
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1,741,047 |
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1,424,367 |
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Total assets |
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$ |
722,257,807 |
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$ |
537,186,018 |
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Liabilities and shareholders equity: |
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
31,931,913 |
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$ |
14,238,836 |
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Deferred revenue |
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|
137,500 |
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Fair value of derivative instrument liability |
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5,916,630 |
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3,739,406 |
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Capital costs accrual |
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49,493,686 |
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53,118,385 |
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Total current liabilities |
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87,479,729 |
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|
71,096,627 |
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Bank indebtedness |
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|
25,000,000 |
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|
102,000,000 |
|
Deferred income taxes |
|
|
125,922,323 |
|
|
|
86,362,741 |
|
Other long-term obligations |
|
|
14,633,365 |
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|
9,734,904 |
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Shareholders equity: |
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Share capital |
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162,906,990 |
|
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|
106,513,852 |
|
Treasury stock |
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|
(1,193,650 |
) |
|
|
(1,193,650 |
) |
Accumulated other comprehensive loss fair value of
derivative instruments |
|
|
(3,839,894 |
) |
|
|
(2,616,767 |
) |
Retained earnings |
|
|
311,348,944 |
|
|
|
165,288,311 |
|
|
|
|
|
|
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|
Total shareholders equity |
|
|
469,222,390 |
|
|
|
267,991,746 |
|
|
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|
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|
|
|
|
|
|
|
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|
Total liabilities and shareholders equity |
|
$ |
722,257,807 |
|
|
$ |
537,186,018 |
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4
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All dollar amounts in this Quarterly Report on Form 10-Q are
expressed in U.S. dollars unless otherwise noted)
DESCRIPTION OF THE BUSINESS:
Ultra Petroleum Corp. (the Company) is an independent oil and gas company engaged in the
acquisition, exploration, development, and production of oil and gas properties. The Company is
incorporated under the laws of the Yukon Territory, Canada. The Companys principal business
activities are in the Green River Basin of Southwest Wyoming and Bohai Bay, China.
1. SIGNIFICANT ACCOUNTING POLICIES:
The accompanying financial statements, other than the balance sheet data as of December 31, 2004,
are unaudited and were prepared from the Companys records. Balance sheet data as of December 31,
2004 was derived from the Companys audited financial statements, but does not include all
disclosures required by U.S. generally accepted accounting principles (GAAP). The Companys
management believes that these financial statements include all adjustments necessary for a fair
presentation of the Companys financial position and results of operations. All adjustments are of
a normal and recurring nature unless specifically noted. The Company prepared these statements on
a basis consistent with the Companys annual audited statements and Regulation S-X. Regulation S-X
allows the Company to omit some of the footnote and policy disclosures required by generally
accepted accounting principles and normally included in annual reports on Form 10-K. You should
read these interim financial statements together with the financial statements, summary of
significant accounting policies and notes to the Companys most recent annual report on Form 10-K.
(a) Basis of presentation and principles of consolidation:
The consolidated financial statements include the accounts of the Company and its wholly owned
subsidiaries UP Energy Corporation, Ultra Resources, Inc. and Sino-American Energy Corporation. The
Company presents its financial statements in accordance with U.S. GAAP. All material inter-company
transactions and balances have been eliminated upon consolidation.
(b) Accounting principles:
The consolidated financial statements are prepared in accordance with accounting principles
generally accepted in the United States.
(c) Cash and cash equivalents:
We consider all highly liquid investments with an original maturity of three months or less to be
cash equivalents.
(d) Restricted cash:
Restricted cash represents cash received by the Company from production sold where the final
division of ownership of the production is unknown or in dispute. Wyoming law requires that these
funds be held in a federally insured bank in Wyoming.
(e) Capital assets:
Capital assets are recorded at cost and depreciated using the declining-balance method based on a
seven-year useful life.
(f) Oil and gas properties:
The Company uses the full cost method of accounting for exploration and development activities as
defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs
of unsuccessful, as well as successful, exploration and development activities are capitalized as
properties and equipment. This includes any internal costs that are directly related to exploration
and development activities but does not include any costs related to production, general corporate
overhead or similar activities on a country by country basis.
Effective with the adoption of Statement of Financial Accounting
Standards No. 143 Accounting for Asset Retirement
Obligations (SFAS No. 143) in 2003, the carrying amount of oil and gas properties also includes estimated asset
retirement costs recorded based on the fair value of the asset retirement obligation when incurred.
Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless
the gain or loss would significantly alter the relationship between capitalized costs and proved
reserves of oil and natural gas attributable to a country.
The sum of net capitalized costs and estimated future development costs of oil and gas properties
are amortized using the unit-of-production method based on the proven reserves as determined by
independent petroleum engineers. Oil and gas reserves and production are converted into equivalent
units based on relative energy content. Operating fees received related to the properties in which
the Company owns an interest are netted against expenses. Fees received in excess of costs incurred
are recorded as a reduction to the full cost pool. Effective with the adoption of SFAS No. 143,
asset retirement costs are included in the base costs for calculating depletion.
5
Oil and gas properties include costs that are excluded from capitalized costs being amortized.
These amounts represent investments in unproved properties and major development projects. The
Company excludes these costs on a country-by-country basis until proved reserves are found or until
it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to
determine if impairment has occurred. The amount of any impairment is transferred to the
capitalized costs being amortized (the depreciation, depletion and
amortization (DD&A) pool) or a
charge is made against earnings for those international operations where a reserve base has not yet
been established. For international operations where a reserve base has not yet been established,
an impairment requiring a charge to earnings may be indicated through evaluation of drilling
results, relinquishing drilling rights or other information.
Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost
ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test
determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The
capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related
deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas
reserves, generally using prices in effect at the end of the current period and held flat for the
life of production excluding the estimated abandonment costs for properties with asset retirement
obligations recorded on the balance sheet and including the effect of derivative contracts that
qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of
unevaluated properties and major development. The effect of
implementing SFAS No. 143 has no effect
on the ceiling test calculation as the future cash outflows associated with settling asset
retirement obligations are excluded from this calculation.
(g) Inventories:
Crude oil products and materials and supplies inventories are carried at the lower of current
market value or cost. Inventory costs include expenditures and other charges directly and
indirectly incurred in bringing the inventory to its existing condition and location. Selling
expenses and general and administrative expenses are reported as period costs and excluded from
inventory cost. Crude oil product
inventory at September 30, 2005 includes depletion and lease operating expenses (LOE) of
$1,155,700, associated with the Companys crude oil production in China. Drilling and completion
supplies inventory of $23.5 million primarily includes the cost of pipe that will be utilized
during the remainder of the Companys 2005 drilling program and the beginning of the 2006 drilling
program.
(h) Derivative transactions:
The Company has entered into commodity price risk management transactions to manage its exposure to
gas price volatility. These transactions are in the form of price swaps with financial institutions
and other credit worthy counterparties. These transactions have been designated by the Company as
cash flow hedges. As such, unrealized gains and losses related to the change in fair market value
of the derivative contracts are recorded in Other Comprehensive Income on the balance sheet to the
extent the hedges are effective.
(i) Income taxes:
Income taxes are accounted for under the asset and liability method. Deferred tax assets and
liabilities are recognized for the future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and liabilities and their respective tax
basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on deferred tax assets
and liabilities of a change in tax rates is recognized as income or loss in the period that
includes the enactment date. During the fourth quarter of 2005 the
Company expects to utilize its remaining Sino American Energy
Corporation operating loss
carryforwards, and will at that time be subject to pay income tax in
China.
(j) Earnings per share:
Basic earnings per share is computed by dividing net earnings attributable to common stock by the
weighted average number of common shares outstanding during each period. Diluted earnings per
share is computed by adjusting the average number of common shares outstanding for the dilutive
effect, if any, of stock options. The Company uses the treasury stock method to determine the
dilutive effect.
The following table provides a reconciliation of the components of basic and diluted net income per
common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
Net income |
|
$ |
60,850,169 |
|
|
$ |
27,875,374 |
|
|
$ |
146,060,633 |
|
|
$ |
66,181,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
during the period |
|
|
153,719,760 |
|
|
|
150,127,868 |
|
|
|
152,515,660 |
|
|
|
149,858,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive instruments |
|
|
8,511,488 |
|
|
|
10,053,946 |
|
|
|
9,023,246 |
|
|
|
10,056,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
during the period including the effects of dilutive
Instruments |
|
|
162,231,248 |
|
|
|
160,181,814 |
|
|
|
161,538,906 |
|
|
|
159,914,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
0.40 |
|
|
$ |
0.19 |
|
|
$ |
0.96 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
0.38 |
|
|
$ |
0.17 |
|
|
$ |
0.90 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On May 9, 2005 the outstanding shares of the Company were doubled as the result of a two for one
stock split. The prior year numbers have been adjusted to reflect this change for comparative
purposes.
6
(k) Use of estimates:
The managements discussion and analysis of the Companys financial condition and results of
operations is based upon consolidated financial statements, which have been prepared in
accordance with U.S. GAAP. In addition, application of generally accepted accounting
principles requires the use of estimates, judgments and assumptions that affect the reported
amounts of assets and liabilities as of the date of the financial statements as well as the
revenues and expenses reported during the period. Changes in these estimates, judgments and
assumptions will occur as a result of future events, and, accordingly, actual results could
differ from amounts estimated.
(l) Reclassifications:
Certain amounts in the financial statements of the prior periods have been reclassified to conform
to the current period financial statement presentation.
(m) Accounting for stock-based compensation:
Statement of Financial Accounting Standards No. 123, Accounting for StockBased Compensation
(SFAS No. 123), defines a fair value method of accounting for employee stock options and similar
equity instruments. SFAS No. 123 allows for the continued measurement of compensation cost for
such plans using the intrinsic value based method prescribed by
Accounting Principles Board Opinion No. 25, Accounting for
Stock Issued to Employees (APB No. 25), provided that pro forma results of operations are
disclosed for those options granted. The Company accounts for stock options granted to employees
and directors of the Company under the intrinsic value method. Had the Company reported
compensation costs as determined by the fair value method of accounting for option grants to
employees and directors, net income and net income per common share would approximate the following
pro forma amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
Net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
60,850,169 |
|
|
$ |
27,875,374 |
|
|
$ |
146,060,633 |
|
|
$ |
66,181,096 |
|
Deduct: Fair value of stock options issued,
net of tax |
|
|
(3,842,861 |
) |
|
|
(1,716,636 |
) |
|
|
(7,335,492 |
) |
|
|
(2,849,615 |
) |
Pro forma |
|
$ |
57,007,308 |
|
|
$ |
26,158,738 |
|
|
$ |
138,725,141 |
|
|
$ |
63,331,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.40 |
|
|
$ |
0.19 |
|
|
$ |
0.96 |
|
|
$ |
0.44 |
|
Pro forma |
|
$ |
0.37 |
|
|
$ |
0.17 |
|
|
$ |
0.91 |
|
|
$ |
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.38 |
|
|
$ |
0.17 |
|
|
$ |
0.90 |
|
|
$ |
0.41 |
|
Pro forma |
|
$ |
0.35 |
|
|
$ |
0.16 |
|
|
$ |
0.86 |
|
|
$ |
0.40 |
|
For purposes of pro forma disclosures, the estimated fair value of options is amortized to expense
over the options vesting period. The weighted-average fair value of each option granted is
estimated on the date of grant using the Black Scholes option pricing model with the following
assumptions: at September 30, 2005, expected volatility of 30.8% 37.31% and a risk free rate of
3.830% 4.320% at September 30, 2004, expected volatility of 38.35% and a risk free rate of 3.5%.
At September 30, 2005 options have expected lives of 6.5 years, and at September 30, 2004 options
had expected lives of 6.5 years.
(n) Revenue Recognition:
Revenues are recorded on the entitlement
method. Under the entitlement method, revenue is recorded based on the Companys
net interest. The Company records its entitled share of revenues based on estimated production
volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are
supported by third party pipeline statements or cash receipts. Since there is a ready market for
natural gas, the Company sells the majority of its products soon after production at various
locations at which time title and risk of loss pass to the buyer. Gas imbalances occur when the
Company sells more or less than its entitled ownership percentage of total gas production. Any
amount received in excess of the Companys share is treated as a liability. If the Company receives
less than its entitled share, the underproduction is recorded as a receivable.
(o) Other Comprehensive Earnings (Loss):
Other comprehensive earnings (loss) is a term used to define revenues, expenses, gains and losses
that under generally accepted accounting principles are reported as separate components of
Shareholders Equity instead of net earnings (loss). The loss depicted on the balance sheet as
other comprehensive loss is associated with unrealized losses related to the change in fair value
of derivative instruments designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September
30, 2005 |
|
|
September 30, 2004 |
|
|
September 30, 2005 |
|
|
September 30, 2004 |
|
Net income |
|
$ |
60,850,169 |
|
|
$ |
27,575,374 |
|
|
$ |
146,060,633 |
|
|
$ |
66,181,096 |
|
Unrealized loss on derivative
instruments, net of tax |
|
|
(1,405,907 |
) |
|
|
518,403 |
|
|
|
(1,223,127 |
) |
|
|
(3,341,935 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
comprehensive earnings |
|
$ |
59,444,262 |
|
|
$ |
28,093,777 |
|
|
$ |
144,837,506 |
|
|
$ |
62,839,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
(p) Impact of recently issued accounting pronouncements:
In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of
Financial Accounting Standards No. 123 (SFAS
No. 123R), Share-based Payment. SFAS No. 123R
requires compensation costs related to share-based payments to be recognized in the income
statement over the vesting period. The amount of the compensation cost will be measured based on
the grant-date fair value of the instrument issued. SFAS No. 123R is effective as of January 1,
2006, for all awards granted or modified after that date and for those awards granted prior to that
date that have not vested. Beginning after January 1, 2006, the Company will begin expensing share
based compensation. All outstanding awards issued prior to this date will have fully vested.
2. ASSET RETIREMENT OBLIGATIONS:
In June 2001, the FASB issued
SFAS No. 143, Accounting
for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a legal obligation associated with the
retirement of tangible long-lived assets that result from the acquisition, construction,
development and/or normal use of the assets. The Company has recorded a liability of $1,168,170
($745,163 U.S. and $423,007 China) to account for future obligations associated with its assets in
both the United States and China.
3. OIL AND GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Developed Properties: |
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs Domestic |
|
$ |
601,473,635 |
|
|
$ |
429,597,822 |
|
Acquisition, equipment, exploration, drilling and environmental
costs China |
|
|
29,684,638 |
|
|
|
24,552,316 |
|
Less accumulated depletion, depreciation and amortization Domestic |
|
|
(96,486,409 |
) |
|
|
(65,099,325 |
) |
Less accumulated depletion, depreciation and amortization China |
|
|
(8,629,253 |
) |
|
|
(3,255,887 |
) |
|
|
|
|
|
|
|
|
|
|
526,042,611 |
|
|
|
385,794,926 |
|
|
|
|
|
|
|
|
|
|
Unproven Properties: |
|
|
|
|
|
|
|
|
Acquisition and exploration costs Domestic |
|
|
17,570,990 |
|
|
|
16,910,010 |
|
Acquisition and exploration costs China |
|
|
82,805,488 |
|
|
|
71,929,450 |
|
|
|
|
|
|
|
|
Net oil and gas properties |
|
$ |
626,419,089 |
|
|
$ |
474,634,386 |
|
|
|
|
|
|
|
|
4. LONG-TERM LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
Bank indebtedness |
|
$ |
25,000,000 |
|
|
$ |
102,000,000 |
|
Other long-term obligations |
|
|
14,633,365 |
|
|
|
9,734,904 |
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
39,633,365 |
|
|
$ |
111,734,904 |
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its subsidiary) participates in a revolving
credit facility with a group of banks led by JP Morgan Chase Bank. On May 5, 2005, the Company
signed a third amendment to the Second Amended and Restated Credit Agreement. The agreement
specifies an aggregate borrowing base of $500 million and a commitment amount of $200 million.
The commitment amount may be increased up to $500 million at any time at the request of the
Company. Each bank shall have the right, but not the obligation, to increase the amount of
their commitment as requested by the Company. In the event that the existing banks increase
their commitment to an amount less than the requested commitment amount, then it would be
necessary to bring additional banks into the facility. At September 30, 2005, the Company had
$25 million outstanding and $175 million unused and available under the current committed
amount.
The credit facility matures on May 1, 2010. The note bears interest at either JP Morgans
prime rate with no margin added up to the banks prime rate plus a margin of three-quarters of
one percent (0.75%) based on the percentage of available credit drawn or at LIBOR plus a
margin of one percent (1.00%) to one and three-quarters of one percent (1.75%) based on the
percentage of available credit drawn. For the purposes of calculating interest, the available
credit is equal to the borrowing base. An average annual commitment fee of 0.25% to 0.375%,
depending on the percentage of available credit drawn, is charged quarterly for any unused
portion of the commitment amount.
The borrowing base is subject to periodic (at least semi-annual) review and re-determination
by the banks and may be decreased or increased depending on a number of factors, including the
Companys proved reserves and the banks forecast of future oil and gas prices. If the
borrowing base is reduced to an amount less than the balance outstanding, the Company has
sixty days from the date of written notice of the reduction in the borrowing base to pay the
difference. Additionally, the Company is subject to quarterly reviews of compliance with the
covenants under the bank facility including minimum coverage ratios relating to interest,
working capital and advances to Sino-American Energy Corporation, the Companys U.S.
subsidiary in which the China asset is held. In the event of a default under the covenants,
the Company may not be able to access funds otherwise available under the facility and may, in
certain
8
circumstances including a reduction in the borrowing base, be required to repay the credit
facility. The notes are collateralized by a majority of the Companys proved domestic oil and
gas properties. At September 30, 2005, the Company had $25.0 million of outstanding
borrowings under this credit facility, with a current average interest rate of approximately
4.2%. The Company was in compliance with all loan covenants at September 30, 2005.
Other long-term obligations: These costs relate to the long-term portion of production taxes
payable, a liability associated with imbalanced production, the long-term portion of the fair
value estimate of our hedging liability and our asset retirement obligations discussed in Note
2.
5. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES:
In September 2003, the AcSB (Accounting Standards Board) released revised transitional provisions
for Stock-Based Compensation and Other Stock-Based Payments, Section 3870, to provide the same
alternative methods of transition as is provided in the US for voluntary adoption of the fair value
based method of accounting for stock based compensation. These provisions permit either retroactive
(with or without restatement) or prospective application of the recognition provisions to awards
not previously accounted for at fair value. Prospective application is only available to
enterprises that elect to apply the fair value based method of accounting for stock based
compensation to that type of award for fiscal years beginning before January 1, 2004.
The AcSB has also amended Section 3870 to require that all transactions whereby goods and services
are received in exchange for stock-based compensation and other payments result in expenses that
should be recognized in financial statements, and that this requirement would be applicable for
financial periods beginning on or after January 1, 2004. Section 3870 requires that share-based
transactions be measured on a fair value basis.
As described in Note 1, had the Company expensed the fair value of options vested during the
period, net income would have been reported as $57,007,308 for the quarter ended September
30, 2005 and $138,725,141 for the nine months ended September 30, 2005.
Recorded in accumulated other comprehensive loss in the equity section of the Companys
balance sheet is an offset of $3,839,894 to a liability that measures the future effect of
the fixed price to index price swap agreements that the Company currently has in place. The
Company has recorded this in compliance
with Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133) which addresses accounting impacts
of derivative instruments.
The AcSB issued a new Accounting Guideline (Guideline), AcG-13, Hedging Relationships, in
December 2001 in connection with amendments to CICA Handbook Section 1650, Foreign Currency
Translation. The Guideline is applicable to hedging relationships in effect in fiscal years
beginning on or after July 1, 2003 (the AcSB changed the original effective date of January 1, 2002
in its December 2001 meeting, and further deferred the effective date in its September 2002
meeting). The Guideline is not applicable to prior periods, but requires the discontinuance of
hedge accounting for hedging relationships established in prior periods that do not meet the
conditions for hedge accounting at the date it is first applied.
The Guideline supplements some of the requirements on accounting for hedges of foreign currency
items in Section 1650, but is equally applicable to accounting for hedges of other types of risk
exposure. The Guideline deals with the identification, documentation, designation and effectiveness
of hedges and also the discontinuance of hedge accounting, but does not specify hedge accounting
methods.
The Guideline is intended to improve the quality and consistency of hedge accounting under Canadian
GAAP. The Guideline incorporates certain features of the U.S. hedge accounting standards as
requirements. The AcSB has attempted to avoid creating any additional GAAP differences, i.e.,
requirements that prevent an entity from adopting a U.S. requirement. However, Canadian hedge
accounting remains inconsistent with U.S. GAAP in some fundamental ways.
6. SEGMENT INFORMATION
The Company has two reportable operating segments, one domestic and one foreign, which are in the
business of natural gas and crude oil exploration and production. The accounting policies of the
segments are the same as those described in the summary of significant accounting policies. The
Company evaluates performance based on profit or loss from oil and gas operations before price-risk
management and other, general and administrative expenses and interest expense. The Companys
reportable operating segments are managed separately based on their geographic locations.
Financial information by operating segment is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
|
Domestic |
|
|
China |
|
|
Total |
|
|
Domestic |
|
|
China |
|
|
Total |
|
Oil and gas sales |
|
$ |
118,736,583 |
|
|
$ |
14,859,184 |
|
|
$ |
133,595,767 |
|
|
$ |
58,696,352 |
|
|
$ |
7,745,093 |
|
|
$ |
66,441,445 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation |
|
|
12,121,758 |
|
|
|
1,149,067 |
|
|
|
13,270,825 |
|
|
|
6,676,869 |
|
|
|
1,031,413 |
|
|
|
7,708,282 |
|
Lease operating expenses |
|
|
2,318,646 |
|
|
|
1,079,000 |
|
|
|
3,397,646 |
|
|
|
1,574,589 |
|
|
|
889,000 |
|
|
|
2,463,589 |
|
Production taxes |
|
|
13,935,435 |
|
|
|
|
|
|
|
13,935,435 |
|
|
|
6,875,586 |
|
|
|
|
|
|
|
6,875,586 |
|
Gathering |
|
|
4,602,121 |
|
|
|
|
|
|
|
4,602,121 |
|
|
|
3,259,412 |
|
|
|
|
|
|
|
3,259,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
85,758,623 |
|
|
|
12,631,117 |
|
|
|
98,389,740 |
|
|
|
40,309,896 |
|
|
|
5,824,680 |
|
|
|
46,134,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
4,019,706 |
|
|
|
|
|
|
|
|
|
|
|
1,712,429 |
|
Other expense |
|
|
|
|
|
|
|
|
|
|
610,141 |
|
|
|
|
|
|
|
|
|
|
|
833,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
|
|
|
|
|
|
|
$ |
93,759,893 |
|
|
|
|
|
|
|
|
|
|
$ |
43,588,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
72,225,419 |
|
|
$ |
4,762,429 |
|
|
$ |
76,987,848 |
|
|
$ |
62,180,753 |
|
|
$ |
4,516,775 |
|
|
$ |
66,697,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties |
|
$ |
522,558,216 |
|
|
$ |
103,860,873 |
|
|
$ |
626,419,089 |
|
|
$ |
329,599,726 |
|
|
$ |
90,835,081 |
|
|
$ |
420,434,807 |
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
|
Domestic |
|
|
China |
|
|
Total |
|
|
Domestic |
|
|
China |
|
|
Total |
|
Oil and gas sales |
|
$ |
285,546,319 |
|
|
$ |
46,389,035 |
|
|
$ |
331,935,354 |
|
|
$ |
153,425,415 |
|
|
$ |
7,745,093 |
|
|
$ |
161,170,508 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation |
|
|
32,027,985 |
|
|
|
5,138,753 |
|
|
|
37,166,738 |
|
|
|
17,573,574 |
|
|
|
1,031,413 |
|
|
|
18,604,987 |
|
Lease operating expenses |
|
|
6,336,316 |
|
|
|
4,699,000 |
|
|
|
11,035,316 |
|
|
|
4,104,257 |
|
|
|
889,000 |
|
|
|
4,993,257 |
|
Production taxes |
|
|
33,162,191 |
|
|
|
|
|
|
|
33,162,191 |
|
|
|
17,976,082 |
|
|
|
|
|
|
|
17,976,082 |
|
Gathering |
|
|
12,318,895 |
|
|
|
|
|
|
|
12,318,895 |
|
|
|
8,778,545 |
|
|
|
|
|
|
|
8,778,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
201,700,932 |
|
|
|
36,551,282 |
|
|
|
238,252,214 |
|
|
|
104,992,957 |
|
|
|
5,824,680 |
|
|
|
110,817,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
10,712,319 |
|
|
|
|
|
|
|
|
|
|
|
5,080,340 |
|
Other expense |
|
|
|
|
|
|
|
|
|
|
2,484,991 |
|
|
|
|
|
|
|
|
|
|
|
2,759,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
|
|
|
|
|
|
|
$ |
225,054,904 |
|
|
|
|
|
|
|
|
|
|
$ |
102,977,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
172,189,550 |
|
|
$ |
16,008,361 |
|
|
$ |
188,197,911 |
|
|
$ |
119,331,358 |
|
|
$ |
11,039,866 |
|
|
$ |
130,371,224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties |
|
$ |
522,558,216 |
|
|
$ |
103,860,873 |
|
|
$ |
626,419,089 |
|
|
$ |
329,599,726 |
|
|
$ |
90,835,081 |
|
|
$ |
420,434,807 |
|
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion of the financial condition and operating results of the Company should
be read in conjunction with the consolidated financial statements and related notes of the
Company. Except as otherwise indicated all amounts are expressed in U.S. dollars. We operate
in one segment, natural gas and oil exploration and development with two geographical segments;
the United States and China.
The discussion and analysis of the Companys financial condition and results of operations is
based upon consolidated financial statements, which have been prepared in accordance with U.S.
GAAP. In addition, application of generally accepted accounting principles requires the use of
estimates, judgments and assumptions that affect the reported amounts of assets and liabilities
as of the date of the financial statements as well as the revenues and expenses reported during
the period. Changes in these estimates, judgments and assumptions will occur as a result of
future events, and, accordingly, actual results could differ from amounts estimated.
The Company currently generates the majority of its revenue, earnings and cash from the
production and sales of natural gas and oil from its property in southwestern Wyoming. The
price of natural gas in the southwest Wyoming region is a critical factor to the Companys
business. The price of gas in southwest Wyoming historically has been volatile. The average
annual realizations for the period 2003-2005 have ranged from $3.84 to $7.43 per Mcf. This
volatility could be detrimental to the Companys financial performance. The Company seeks to
limit the impact of this volatility on its results of operations by entering into derivative
and forward sales contracts for gas in southwest Wyoming. The average realization for the
Companys gas during the first nine months of 2005 was $6.14 per Mcf, basis Opal, Wyoming,
including the effect of hedges. In addition, the Company continued producing from the first of
the nine fields discovered on its oil properties offshore Bohai Bay, China. The Companys
average realized crude oil price on its Bohai Bay production was $41.98 USD per barrel for the
nine months ended September 30, 2005.
The Company has grown its natural gas and oil production significantly over the past three
years and management believes it has the ability to continue growing production by drilling
already identified locations on its leases in Wyoming and by bringing into production the
already discovered oilfields in China. The Company delivered 61% production growth on an Mcfe
basis during the nine months ended September 30, 2005 as compared to the same nine months in
2004.
The Company uses the full cost method of accounting for oil and gas operations whereby all
costs associated with the exploration for and development of oil and gas reserves are
capitalized to the Companys cost centers. Such costs include land acquisition costs,
geological and geophysical expenses, carrying charges on non-producing properties, costs of
drilling both productive and non-productive wells and overhead charges directly related to
acquisition, exploration and development activities. The Company conducts operations in both
the United States and China. Separate cost centers are maintained for each country in which
the Company has operations. Substantially all of the Companys oil and gas exploration and
production activities are conducted jointly with others and, accordingly, the amounts reflect
only the Companys proportionate interest in such activities.
RESULTS OF OPERATIONS
QUARTER ENDED SEPTEMBER 30, 2005 VS. QUARTER ENDED SEPTEMBER 30, 2004
During the quarter ended September 30, 2005, production increased 44% on an equivalent basis to
18.7 Bcfe from 13.0 Bcfe for the same quarter in 2004 attributable to the Companys successful
drilling activities along with continued production in China, which commenced in July of 2004.
This increased production coupled with average realized prices for natural gas increasing 40%
to $6.86 per Mcf along with average realized prices for oil increasing 55% to $65.20 per barrel
in Wyoming and 32% to $48.44 per barrel in China resulted in a 101% increase in revenues to
$133.6 million.
10
In Wyoming, production costs increased to $20.9 million for the quarter ended September 30, 2005
compared to $11.7 million for the quarter ended September 30, 2004 due to increased production
along with increased prices received for that production which results in increased production
taxes. On a unit of production basis, LOE costs increased to $2.3 million or $0.14 per Mcfe for
the quarter ended September 30, 2005 compared to $1.6 million or $0.13 per Mcfe for the same quarter in
2004. During the third quarter of 2005 production taxes were $13.9 million compared to $6.9
million for the same quarter in 2004, or $0.83 per Mcfe, compared to $0.59 per Mcfe. Production
taxes are calculated based on a percentage of revenue from production. Therefore, higher prices
received increased the costs on a per unit basis. Gathering fees were $4.6 million for the quarter
ended September 30, 2005 compared to $3.3 million for the quarter ended September 30, 2004, which
decreased slightly to $0.27 per Mcfe compared to $0.28 for the quarter ended September 30, 2004.
In Wyoming, DD&A expenses increased to $12.1 million during the quarter ended September 30, 2005
from $6.7 million for the same period in 2004. The increased DD&A expenses were attributable to
increased production volumes and a higher depletion rate, which is primarily associated with
forecasted increased future development costs. On a unit basis, DD&A increased to $0.72 per Mcfe
for the quarter ended September 30, 2005 from $0.57 for the quarter ended September 30, 2004.
In China, production costs were $1.1 million for the quarter ended September 30, 2005 ($0.59
per Mcfe or $3.52 per BOE) compared to $0.9 million ($0.70 per Mcfe or $4.20 per BOE) for the
quarter ended September 30, 2004. DD&A was $1.1 million ($0.62 per Mcfe or $3.75 per BOE) for
the quarter ended September 30, 2005 compared to $1.0 million ($0.81 per Mcfe or $4.86 per BOE)
for the comparable prior year period.
For the quarter ended September 30, 2005, net income before income taxes increased 115% to
$93.8 million and the income tax provision increased 109% to $32.9 million. Net income
increased 118% to $60.9 million or $0.38 per diluted share.
General and administrative expenses increased 77% to $2.8 million during the quarter ended
September 30, 2005 compared to $1.6 million for the same period in 2004. This increase was
primarily attributable to both the overall growth of the Company along with payroll tax expense
associated with employee stock option exercises.
Income tax provision for the period increased to $32.9 million during the third quarter of 2005
compared to $15.7 million during the third quarter of 2004. This increase was attributable to
an increase in net income from continuing operations. The Companys effective tax rate was 35%
at September 30, 2005 compared to 36% at September 30, 2004.
NINE-MONTHS ENDED SEPTEMBER 30, 2005 VS. NINE-MONTHS ENDED SEPTEMBER 30, 2004
During the nine-months ended September 30, 2005, production increased 61% on an equivalent
basis to 52.0 Bcfe from 32.3 Bcfe for the same nine-months in 2004. The increase is primarily
attributable to the additional wells drilled and completed during the latter portion of 2004
along with the increased drilling and completion during the first nine-months of 2005.
Increased production coupled with average realized prices for natural gas increasing 26% to
$6.14 per Mcf along with average realized prices for oil increasing 47% to $56.92 per barrel in
Wyoming and 14% to $41.98 in China resulted in a 106% increase in revenues to $331.9 million.
In
Wyoming, production costs increased to $51.8 million for the nine months ended September 30,
2005 compared to $30.9 million for the same period in 2004 primarily due to a 46% period over
period increase in production coupled with higher production taxes. These higher absolute
levels of production taxes were driven by an 86% year over year increase in revenues.
Production taxes are calculated as a percentage of revenue. Therefore, higher prices received
increased the costs on a per unit basis. On a unit of production basis, production costs
increased to $1.85 per Mcfe during the first nine months of 2005 compared to $1.56 per Mcfe for
the first nine months of 2004. The increase in unit production costs was attributable almost
largely to the increase in production taxes arising from higher revenues coupled with a 25%
increase in depletion due to increased forecasted future development costs.
In China, the Company produced 1,105,036 barrels of crude oil for the nine months ended
September 30, 2005 with an average realized price of $41.98 per barrel resulting in revenues of
$46.4 million compared to $36.72 per barrel resulting in revenues of $7.7 million for the nine
months ended September 30, 2004. For the first nine months of 2005, production costs were $4.7
million ($0.71 per Mcfe or $4.26 per BOE). DD&A was $5.1 million ($0.78 per Mcfe or $4.65 per
BOE) compared to production costs of $0.9 million ($0.70 per Mcfe or $4.20 per BOE) and DD&A of $1.0
million ($0.81 per Mcfe or $4.89 per BOE) for the first nine months of 2004, respectively.
For the nine months ended September 30, 2005, net income before income taxes increased 119% to
$225.1 million and the income tax provision increased by 115% to $79.0 million. Net income
increased 121% to $146.1 million, or $0.90 per diluted share.
General and administrative expenses increased 96% to $8.4 million for the nine months ended
September 30, 2005 compared to $4.3 million for the same period in 2004. Along with the
overall growth of the Company, this increase is primarily attributable to increased audit fees
associated with the implementation of an internal audit function by the Company to support its
compliance with the Sarbanes-Oxley Act coupled with increased external audit fees. During the
first nine months of 2005, the Company has also experienced increased payroll tax expense
associated with employee stock option exercises.
The Companys income tax provision increased to $79.0 million during the first nine months of
2005 compared to $36.8 million for the same period in 2004. This increase was attributable to
an increase in net income from continuing operations. The Companys effective tax rate was 35%
at September 30, 2005 compared to 36% at September 30, 2004.
LIQUIDITY AND CAPITAL RESOURCES
During the nine month period ended September 30, 2005, the Company relied on cash provided by
operations to finance its capital expenditures. The Company participated in the drilling and
completion of 78 wells in Wyoming and continued to participate in the exploration and
development processes in the China blocks, including the ongoing batch drilling program for
the development wells. For the nine-month period ended September 30, 2005, net capital
expenditures were $188 million. At September 30, 2005, the Company reported a cash position
of $23.2 million compared to $12.5 million at September 30, 2004. Working capital at
September 30, 2005 was
11
$6.6 million as compared to a deficit of $(21.6) million at September 30, 2004. As of
September 30, 2005, the Company had incurred bank indebtedness of $25.0 million compared to
$102 million during the same nine months in 2004. The Company incurred other long-term
obligations of $14.6 million comprised of items payable in more than one year, primarily
related to production taxes.
The Companys positive cash provided by operating activities, along with the availability
under the senior credit facility, are projected to be sufficient to fund the Companys
budgeted capital expenditures for 2005, which are currently projected to be $290 million. Of
the $290 million budgeted for 2005, the Company plans to spend approximately $270 million in
Wyoming and approximately $20 million in China. With the $270 million allocated for Wyoming,
the Company plans to drill or participate in an estimated 105 gross wells in 2005, of which
approximately 18% will be exploration wells and the remaining 82% will be development wells.
Of the $20 million budgeted for China, approximately $15 million will be allocated for
development activity and the balance will be used for exploratory/appraisal activity. The
Company currently has no budget for acquisitions in 2005.
The Company (through its subsidiary) participates in a revolving credit facility with a group
of banks led by JP Morgan Chase Bank. On May 5, 2005, the Company signed a third amendment to
the Second Amended and Restated Credit Agreement. The agreement specifies an aggregate
borrowing base of $500 million and a commitment amount of $200 million. The commitment amount
may be increased up to $500 million at any time at the request of the Company. Each bank shall
have the right, but not the obligation, to increase the amount of their commitment as
requested by the Company. In the event that the existing banks increase their commitment to an
amount less than the requested commitment amount, then it would be necessary to bring
additional banks into the facility. The credit facility matures on May 1, 2010. The note bears
interest at either JP Morgans prime rate with no margin added up to the banks prime rate
plus a margin of three-quarters of one percent (0.75%) based on the percentage of available
credit drawn or at LIBOR plus a margin of one percent (1.00%) to one and three-quarters of one
percent (1.75%) based on the percentage of available credit drawn. For the purposes of
calculating interest, the available credit is equal to the borrowing base. An average annual
commitment fee of 0.25% to 0.375%, depending on the percentage of available credit drawn, is
charged quarterly for any unused portion of the commitment amount. The borrowing base is
subject to periodic (at least semi-annual) review and re-determination by the banks and may be
increased or decreased depending on a number of factors including the Companys proved
reserves and the banks forecast of future oil and gas prices. Additionally, the Company is
subject to compliance with the covenants under the bank facility including minimum coverage
ratios relating to interest, working capital and advances to Sino-American Energy Corporation,
the Companys U.S. subsidiary in which the China asset is held. In the event of a default
under the covenants, the Company may not be able to access funds otherwise available under the
facility and may, in certain circumstances including a reduction in the borrowing base, be
required to repay the credit facility. The notes are collateralized by a majority of the
Companys proved domestic oil and gas properties. At September 30, 2005, the Company had
$25.0 million of outstanding borrowings under this credit facility, with a current average
interest rate of approximately 4.2%. The Company was in compliance with all loan covenants at
September 30, 2005.
During the nine-months ended September 30, 2005, net cash provided by operating activities
was $278.8 million as compared to $119.8 million for the nine-months ended September 30,
2004. The increase in cash provided by operating activities was attributable to the increase
in earnings.
During the nine-months ended September 30, 2005, cash used in investing activities was $211.6
million as compared to $113.4 million for the nine-months ended September 30, 2004. The
change is primarily attributable to increased activity for drilling and completion of wells
in Wyoming and China.
During the nine-months ended September 30, 2005, cash provided by (used in) financing
activities was $(60.9) million as compared to $4.3 million for the nine-months ended
September 30, 2004. The change is primarily attributable to repayment of borrowings under
the senior credit facility.
OFF BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of September 30, 2005.
CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995
This report contains or incorporates by reference forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the
Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995.
All statements other than statements of historical facts included in this document, including
without limitation, statements in Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding our financial position, estimated quantities and net
present values of reserves, business strategy, plans and objectives of the Companys
management for future operations, covenant compliance and those statements preceded by,
followed by or that otherwise include the words believe, expects, anticipates,
intends, estimates, projects, target, goal, plans, objective, should, or
similar expressions or variations on such expressions are forward-looking statements. The
Company can give no assurances that the assumptions upon which such forward-looking
statements are based will prove to be correct nor can the Company assure adequate funding
will be available to execute the Companys planned future capital program.
Other risks and uncertainties include, but are not limited to, fluctuations in the price the
Company receives for oil and gas production, reductions in the quantity of oil and gas sold
due to increased industry-wide demand and/or curtailments in production from specific
properties due to mechanical, marketing or other problems, operating and capital expenditures
that are either significantly higher or lower than anticipated because the actual cost of
identified projects varied from original estimates and/or from the number of exploration and
development opportunities being greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates. See the Companys annual
report on Form 10-K for the year ended December 31, 2004 for additional risks related to the
Companys business.
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
12
The Companys major market risk exposure is in the pricing applicable to its gas and oil
production. Realized pricing is primarily driven by the prevailing price for crude oil and spot
prices applicable to the Companys U.S. natural gas production, which contributes the majority of
the Companys oil and gas revenue. Historically, prices received for gas production have been
volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations
averaged $6.14 per Mcf during the nine months ended September 30, 2005. This average price
includes the effects of hedging and gas balancing between working interest owners.
The Company periodically enters into commodity derivative contracts and fixed-price physical
contracts to manage its exposure to oil and natural gas price volatility. The Company primarily
utilizes fixed price physical contracts as well as price swaps, which are placed with major
financial institutions or with counter-parties of high credit quality that it believes are minimal
credit risks. The oil and natural gas reference prices of these commodity derivatives contracts
are based upon crude oil and natural gas futures, which have a high degree of historical
correlation with actual prices the Company receives. Under SFAS No. 133, all derivative
instruments are recorded on the balance sheet at fair value. Changes in the derivatives fair
value are recognized currently in earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) to the extent the hedge is effective. For forward sales contracts, the
gain or loss on the derivative is offset by related results of the hedged item in the income
statement. Gains and losses on hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not qualify for hedge accounting treatment
are recorded as derivative assets and liabilities at market value in the consolidated balance
sheet, and the associated unrealized gains and losses are recorded as current expense or income in
the consolidated statement of operations. The Company currently does not have any derivative
contracts in place that do not qualify as a cash flow hedge.
During the first nine months of 2005, the total impact of the Companys price swaps was a
reduction in gas revenues of $4.5 million. The effect of fixed price physical contracts is not
included in this amount. The Company does not currently hedge its oil production.
At September 30, 2005, the Company had the following open derivative contracts to manage price
risk on a portion of its natural gas production whereby the Company receives the fixed price and
pays the variable price (all prices southwest Wyoming basis).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
Unrealized |
|
|
Remaining Contract |
|
Volume- |
|
Price / |
|
loss at |
Type |
|
Period |
|
MMBTU / day |
|
MMBTU |
|
9/30/05* |
Swap
|
|
Oct 2005 Dec 2005
|
|
|
10,000 |
|
|
$ |
4.42 |
|
|
$ |
5,916,630 |
|
|
|
|
* |
|
Unrealized losses are not adjusted for income tax effect. |
The Company also utilizes fixed price forward gas sales contracts at southwest Wyoming delivery
points to hedge its commodity exposure. In addition to the derivative contracts discussed above,
the Company had the following fixed price physical delivery contracts in place on behalf of its
interest and those of other parties at September 30, 2005.
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Average |
Remaining Contract Period |
|
MMBTU / day |
|
Price / MMBTU |
Calendar 2005 |
|
|
70,000 |
|
|
$ |
5.03 |
|
Oct 2005 |
|
|
10,000 |
|
|
$ |
6.03 |
|
Calendar 2006 |
|
|
70,000 |
|
|
$ |
5.86 |
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The above derivative and forward gas sales contracts represent approximately 45% of the Companys
currently forecasted gas production for the balance of 2005, and 22% for calendar year 2006.
ITEM 4 CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. The Companys
management, including the Companys principal executive and financial officer, has
evaluated the effectiveness of the Companys disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of
1934) as of the end of the period covered by this Quarterly Report on Form 10-Q.
Based upon that evaluation, both the Companys principal executive and financial
officer have concluded that the disclosure controls and procedures were effective
to ensure that information required to be disclosed by the Company in reports that
it files or submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the rules
and forms of the Securities and Exchange Commission as of the end of the period
covered by this Quarterly Report on Form 10-Q.
(b) Changes in Internal Controls. There were no changes in the Companys
internal control over financial reporting that occurred during the Companys last
fiscal quarter that has materially affected, or is reasonably likely to materially
affect, the Companys internal control over financial reporting.
PART 2 OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
13
The Company is currently involved in various routine disputes and allegations incidental to
its business operations. While it is not possible to determine the ultimate disposition of
these matters, the Company believes that the resolution of all such pending or threatened
litigation is not likely to have a material adverse effect on the Companys financial
position or results of operations.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
(a) Exhibits
3.1 Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to
Exhibit 3.1 of the Companys Quarterly Report on Form 10Q for the period ended June 30,
2001.)
3.2 By-Laws of Ultra Petroleum Corp (incorporated by reference to Exhibit 3.2 of the
Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.)
4.1 Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the
Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.)
31.1 Certification of Chairman, President and Chief Executive Officer pursuant to Rule
13(a) 14(a)
31.2 Certification of Chief Financial Officer pursuant to Rule 13(a) 14(a)
32.1 Certification of Chairman, President and Chief Executive Officer pursuant to Rule
13(a) 14(b)
32.2 Certification of Chief Financial Officer pursuant to Rule 13(a) 14(b)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
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ULTRA PETROLEUM CORP. |
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Date October 28, 2005
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Name: Michael D. Watford |
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Title: Chairman, President and Chief Executive Officer |
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Name: Marshall D. Smith |
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Title: Chief Financial Officer |
Date
October 28, 2005
14